1. Introduction
Global climate change has become one of the most pressing challenges of the 21st century
[1],
[2],
[3]. Carbon dioxide capture, utilization, and storage (CCUS) coupled with the enhanced oil recovery (EOR) technologies are the most feasible and widely implemented CCUS solutions, contributing to 77% of the world’s total carbon capture till now [
4],[
5]. This technology captures industrial CO
2 emissions and disposes them into hydrocarbon, typically, oil reservoirs, enhancing hydrocarbon recovery through efficient displacement mechanisms while achieving permanent geological sequestration, demonstrating the dual benefits of energy production and carbon emission reduction (
Fig. 1) [
6],[
7]. According to the International Energy Agency (IEA), CCUS-EOR projects worldwide have cumulatively sequestered over 400 million tons of CO
2, which is equivalent to offsetting the annual emissions of 100 million gasoline-powered vehicles [
8],[
9]. CCUS-EOR enhances the economic value of low-productivity oilfields and extends the lifespan of oil reservoirs [
10],[
11]. CCUS-EOR technology is perhaps the most optimum solution to accelerate energy transition for the petroleum industry by offering significant socio-economic benefits
[12],
[13],
[14].
CCUS-EOR is applicable in the field through maturing research leading to high injectivity, strong viscosity reduction, and effective CO
2 storage [
15],[
16]. CCUS-EOR has expanded beyond medium- to light-oil reservoirs, where miscible displacement with CO
2 is proven to be effective, to unconventional reservoirs which increased and the scope and the applicability
[17],
[18],
[19]. The number of industrial/large-scale CCUS-EOR projects at various stages, on construction or planning or operational, has steadily increased in recent years [
20],[
21]. At present, technological advancements and field practice have led to significant progress in CCUS-EOR through better understanding of the underlying mechanisms, multiphase fluid flow dynamics, optimization methods, and economical aspects of reservoir performance management
[22],
[23],
[24],
[25]. However, current research mainly focuses solely on the oil production, and the CO
2 storage objective is often regarded as the “by-product” of the CCUS-EOR process. Driven by the goal of global carbon neutrality, CCUS-EOR implementation must shift from a single objective of increasing recovery to a dual-objective strategy that balances both crude oil production enhancement and carbon management. Therefore, there is a lack of systematic studies on integrated CCUS-EOR technology implementation for different reservoir types. There are many factors or mechanisms that have an impact on the performance of EOR and storage capacity [
26]. One of the examples that impact the performance is the lower non-hydrocarbon impurity content in the injected stream which in turn increases the oil recovery and CO
2 storage efficiency. The purpose of CO
2-EOR is to enhance CO
2 mobility and solubility, reduce oil viscosity and improve oil flow leading to higher oil recoveries as CO
2 displaced the oil, while the goals of successful geological storage are minimization of free CO
2 migration to achieve long-term storage stability. Given this relationship, the multi-objective optimization problem under the influence of complex factors can be disassembled, first through single factor decoupling, and then according to the impact mechanism classification, the multi-factor coupling analysis is conducted to determine the factors influencing the inconsistent/competing inconsistent association of CO
2-EOR and storage. Furthermore, different synergetic technologies should be used to focus on or expand the direct impact zone, avoid or reduce conflict regions to achieve the dual-objective optimization of EOR and CO
2 long-term storage.
In practical applications, mainly reservoir properties, fluid characteristics, and engineering parameters influence CCUS-EOR in three categories: ① porosity and permeability to facilitate efficient CO
2 flooding while providing sufficient space for long-term storage. However, excessive heterogeneity can cause CO
2 channeling, reducing oil recovery and increasing leakage risks, making it difficult to implement synergistic implementation of the CCUS-EOR projects [
27]. ② The flow characteristics of CO
2 in the reservoir which directly affect the oil recovery and CO
2 storage efficiency. Under the reservoir temperature and pressure, physical properties of CO
2–oil and formation water can be quite different. In addition, the CO
2–water–rock reaction caused by dissolution causes the mineral to dissolve or precipitate, thereby altering pore structures [
28],[
29]. ③ It may be hard to prioritize the selection between CO
2-EOR and storage for parameter optimization in the engineering implementation of CO
2-EOR and storage. During the oil recovery phase, CO
2 is typically injected alternately or continuously to maximize reservoir utilization of CO
2 for recovery optimization; however, these strategies may compromise storage uniformity and stability for the next stage [
30]. These challenges may further constrict the domain of applicability for CCUS-EOR. Deviations from the domain of dual implementation can shift the process toward either oil recovery or storage dominance. Therefore, developing rational synergy strategies based on existing theories and technologies is the most effective approach to maximize the benefits of CCUS-EOR.
This paper systematically reviews the critical factors influencing oil recovery and CO2 storage in the CCUS-EOR process, along with recent advances in synergistic strategies. This paper analyzes the dual mechanisms by which reservoir parameters (permeability, porosity, temperature, pressure, and mineral composition), reservoir fluid properties and injection–production controls influence performance of CO2-EOR and storage. The impact of each factor on the synergy between oil recovery and storage is thoroughly examined, leading to targeted regulatory strategies. Furthermore, a comprehensive synergistic method for the entire life cycle of CCUS-EOR is proposed. CCUS-EOR stage is first divided based on the time-scale aspects of CO2-EOR and storage. The limitations of current multi-objective optimization are further analyzed, and the future directions are proposed in view of the lack of recognition of multi-field coupling mechanisms and the research and development of new materials and emerging technologies.
2. Key factor analysis of CO2-EOR and storage synergistic technology
2.1. Reservoir properties
2.1.1. Permeability and porosity
Permeability is one of the key factors in determining the flow dynamics process in porous media, which significantly affects the physics of the flow such as CO
2 injection efficiency, sweep, and the magnitude of the formation pressures and it time dependent behavior in combination with other physical parameters. It is also a critical factor affecting the oil recovery and CO
2 storage factors [
31]. Alfarge et al. [
32] studied the effect of permeability on CO
2-EOR based on laboratory experiments. The experimental data shows that with an increase in core permeability, the oil recovery of CO
2-EOR tend to increase; however, the correlation between core permeability and oil recovery is not strong, as shown in
Fig. 2(a) [
32]. Additionally, Alfarge et al. [
32] analyzed the relationship between the average permeability and oil recovery of the Three Forks, Upper Bakken, Middle Bakken, and Lower Bakken Formations.
Fig. 2(b) [
32] illustrates the lack of a clear correlation between the average permeability of different formations and the oil recovery. This further supports the notion that the correlation between permeability and oil recovery is relatively weak [
32]. There are significant differences among different researchers regarding the forward screening criteria for permeability suitable for CO
2-EOR in reservoirs. Kovscek [
33] suggested that the product of reservoir thickness and permeability should be greater than 10
−14–10
−13 m
3. Al Adassani and Bai [
34] reviewed global CO
2-EOR projects and identified a permeability range of 1.5–4500 mD (with an average of 209.73 mD; 1 mD = 10
−3 μm
2) as a favorable screening criterion for CO
2-EOR. In recent years, CO
2-EOR technology has been successfully applied to reservoirs with permeability as low as 1 mD [
35]. Focusing solely on the effect of homogeneous permeability on oil recovery, while ignoring the synergistic effect of oil recovery and CO
2 storage, makes it difficult to comprehensively and accurately evaluate the impact of realistic permeabilities that can be faced during the project implementation [
36].
Therefore, it is critical to conduct the uncertainty assessment of permeability for the goals of oil displacement and storage. Pan et al. [
37] constructed the porosity and permeability relationship of Farnsworth Unit (FWU) based on available data, as shown in
Fig. 3(a). Additionally, Pan et al. [
37] conducted a CO
2–water–alternating gas (WAG) uncertainty analysis on FWU and found that cumulative oil production increased with increasing permeability, reaching its maximum value between matrix permeability of 10.0–31.6 mD; as illustrated in
Figs. 3(b) and
(c). The net CO
2 storage decreases with increasing permeability and reaches its minimum value in the 10.0–31.6 mD range [
37]. This indicates that the effect of permeability on oil recovery and CO
2 storage exhibits strong nonlinear characteristics. One of the main challenges faced by CCUS-EOR is unfavorable reservoir characteristics, especially reservoir heterogeneity, which can lead to an CO
2 early breakthrough, thus reducing the sweep and storage efficiencies [
38]. Currently, the influence of heterogeneity and anisotropy of permeability at the reservoir scale on the EOR performance and storage efficiency is a hot research topic. Zhao et al. [
39] studied the effect of the channel/matrix permeability ratio (
KR) on oil recovery and CO
2 storage. Their simulation results indicated that as the
KR increased, reservoir heterogeneity increases, the sweep range of CO
2 decreased, and both oil recovery and CO
2 storage efficiency decreased. Notably, CO
2 storage efficiency exhibited greater sensitivity to
KR than oil recovery, as illustrated in
Fig. 4 [
39]. Similarly, Wang et al. [
40] analyzed the effect of heterogeneity on CO
2-EOR performance. Their simulations demonstrated that as the heterogeneity index (
) increased from 0 to 0.86 (where
VDP is the Dykstra–Parsons coefficient of permeability variation,
k50 denotes the permeability at which 50% portion of total samples having higher permeabilities; and
k84.1 is permeability at which 84.1% portion of total samples having higher permeabilities), the cumulative oil recovery decreased from 41.66% to 3.89%, and CO
2 storage efficiency declined from 62.86% to 35.02%. Regarding anisotropy, when the ratio of vertical to horizontal permeability (
kv/
kh) increased from 0.001 to 0.1, the vertical sweep efficiency improved, enhancing both the oil recovery and CO
2 storage efficiency. However, when
kv/
kh exceeded 0.1, the gravity override effect became dominant, resulting in a significant decline in the oil recovery and CO
2 storage efficiency. Therefore, the CO
2-EOR process must account for the effects of reservoir heterogeneity and anisotropy on both oil recovery and CO
2 storage.
Formation porosity is another key factor in determining the performance of CO
2-EOR projects [
41]. The simulation results indicated a linear relationship between increased oil production and porosity within the range of 0.01–0.1 [
41]. Seyyedi and Sohrabi [
42] visualized this phenomenon through CO
2 miscible displacement microfluidic experiments. Their findings showed that in larger pore throat structures, the CO
2–oil contact area increased, leading to a more pronounced extraction effect and improved CO
2-EOR performance. For the porosity screening criteria, Kovscek [
33] suggested that the product of oil saturation and porosity should be greater than 0.05. Al Adassani and Bai [
34] further proposed that the reservoir porosity suitable for CO
2-EOR should be between 3% and 37%. Additionally, Wang et al. [
43] found in the physical simulation of CO
2 displacement rocks based on the Gassmann fluid replacement theory that when the porosity is below 3%, it is difficult to achieve effective fluid replacement in the pore space, resulting in limited CO
2-EOR.
Zhao and Liao [
44] evaluated the effects of permeability and porosity on CO
2 flooding recovery and storage potential in CO
2 immiscible and miscible flooding in Changqing Oilfield, as shown in
Fig. 5. It can be seen that the recovery of CO
2 miscible flooding is generally higher than that of immiscible flooding. From the overall trend, with the increase of permeability, the recovery will increase and decrease first, and the storage potential will decrease. The recovery and storage potential of immiscible flooding increase with the increase of porosity. For miscible flooding, with the increase of porosity, the storage potential increases with the increase of porosity, and the recovery rate decreases first and then increases [
44].
Studies have shown that higher porosity is beneficial for improving the oil recovery of CO
2-EOR, and the increase in porosity also helps improve the efficiency of CO
2 storage [
45]. Rezk et al. [
46] analyzed the effect of porosity on oil displacement and storage by constructing an artificial neural network (ANN) surrogate model to demonstrate the porosity increased from 0.15 to 0.25, the performance of oil recovery and CO
2 storage both showed an upward trend. In addition, Chowdhury and Taghavi [
47] revealed that an increase in porosity not only enhances oil recovery but also significantly increases the storage capacity of CO
2, which is helpful for solubility trapping, ultimately increasing the overall CO
2 storage efficiency.
The effects of porosity and permeability on CO2 flooding and storage are mainly reflected in the seepage behavior of CO2, the displacement efficiency, and the stability of long-term storage. In heterogeneous reservoirs, there are significant differences in fluid flow characteristics in different porosity and permeability regions, which complicates the migration path of CO2 in reservoirs and increases the difficulty of accurately predicting CO2 flooding and storage modes. Especially in low permeability reservoirs, heterogeneity can easily lead to CO2 fingering, resulting in a decline in recovery and storage efficiency. Furthermore, permeability governs the breakthrough time and flow dynamics of CO2 within the reservoirs, whereas porosity influences the potential for dissolution and mineral trapping. It is worth noting that permeability and porosity are not independent variables, and their coupling effect on the displacement and storage mechanism of CO2 still needs further quantitative characterization.
Porosity and permeability are not only the main constraints in CO2-EOR and storage but also the critical parameters for optimizing oil recovery and storage efficiency. The CO2 injection strategy should be optimized according to the porosity and permeability characteristics of the target reservoir, so as to ensure the effective seepage of CO2 and improve the oil recovery and storage capacity. For example, in high-permeability reservoirs, techniques such as CO2–WAG injection and foam-assisted CO2 flooding can be used to mitigate CO2 breakthrough and improve overall displacement and storage efficiency. In low-permeability reservoirs, supercritical CO2 (scCO2) or nanofluid-assisted injection can enhance CO2 diffusivity, thereby improving oil recovery efficiency. Moreover, multi-objective optimization methods can be used to comprehensively consider factors such as porosity, permeability, injection pressure, and temperature to optimize the CO2 injection strategy. Secondly, to further improve the accuracy of reservoir characterization, it is recommended to introduce intelligent optimization methods. By combining artificial intelligence (AI) and machine learning (ML) technologies, and based on multi-scale experimental data and numerical simulation results, the identification of pore permeability distribution is optimized to improve the accuracy of oil displacement and storage prediction. Understanding thoroughly the coupling effect of permeability and porosity on oil displacement and storage efficiency can help achieve synergistic optimization of efficient oil displacement and long-term storage and improve economics of CO2-EOR and storage projects.
2.1.2. Reservoir temperature and pressure
Reservoir temperature and pressure significantly affect the performance of CCUS-EOR processes by due to its impact on miscibility, and trapping mechanisms [
48],[
49]. When the reservoir temperature and pressure exceed 304.2 K and 7.39 MPa (
Fig. 6(a)) [
50], respectively, scCO
2 exhibits low viscosity and high density, which markedly reduce oil interfacial tension (IFT) and enhance diffusion (
Fig. 6(b)) [
51], thereby simultaneously improving oil recovery and storage capacity
[52],
[53],
[54]. Statistical analysis of 207 global miscible CO
2-EOR projects indicates that, under scCO
2 conditions, oil recovery increases by 20% and dissolution trapping increases by 40%
[55],
[56],
[57],
[58]. Before reaching the supercritical state, increases in temperature and pressure facilitate CO
2’s transition into its supercritical phase, producing synergistic benefits for both oil recovery and storage. After attaining the supercritical state, CO
2’s density, viscosity, and solubility in oil and water decreased with increasing temperature and increased with increasing pressure. Increases in CO
2 density and viscosity can effectively reduce the differences in density and viscosity between the injected fluid and reservoir oil, expand the sweep area within the formation, and suppress gas channeling through high-permeability pathways, thereby enhancing CO
2’s displacement and storage performance (
Fig. 6(c))
[59],
[60],
[61]. When the reservoir temperature and pressure remain constant, increasing the CO
2 injection pressure and adding a CO
2 miscibility reducer are commonly used to improve both oil recovery and storage performance [
62]. Reservoir temperature and pressure also significantly influence CO
2 solubility in formation water; research by Ahmadi and Chapoy [
63] showed that CO
2 solubility increases with pressure and decreases with temperature. Thus, once the supercritical state is reached, an increase in temperature has an adverse performance on both enhanced CO
2-EOR and storage, while an increase in pressure improves both processes. Moreover, in deep reservoirs characterized by ultra-high temperatures (> 150 °C) and high pressures (> 60 MPa), the risk of heterogeneous CO
2 channeling increases and the miscible pressure threshold rises, leading to poorer oil recovery performance
[64],
[65],
[66]. Additionally, under such extreme conditions, sequestered CO
2 is more prone to migrate and leak via thermal convection or diffusion, thereby necessitating effective seal and continuous monitoring [
50],[
67].
The effects of temperature and pressure on CO
2-EOR and storage are primarily reflected in the CO
2 density, viscosity, and solubility in the formation fluids. Prior to attaining the supercritical state, elevated temperature and pressure significantly enhance the synergistic effect of oil recovery and storage. However, after CO
2 transitions to the supercritical phase (
T > 304.2 K °C,
P > 7.39 MPa), higher temperatures reduce both oil recovery and storage efficiency, whereas increased pressure improves these outcomes, resulting in conflicting influences on recovery and storage performance. The impact of temperature and pressure on the synergistic efficiency of CO
2-EOR and storage depends on their relative weighting; if pressure exerts a greater influence, the synergistic effect is enhanced, whereas if temperature dominates, the synergy is weakened (
Fig. 6(d)). Under ultra-high temperature and pressure conditions (
T > 150 °C and
P > 60 MPa), CO
2 storage stability and oil recovery decrease, making such reservoirs unsuitable for CO
2-EOR and storage. In addition, higher pressure conditions will make it easier for CO
2 to break through the fracture pressure of the reservoir, resulting in CO
2 leakage and migration, affecting the safety of CO
2 storage. The effects of temperature and pressure variations on the synergistic enhancement of CO
2-EOR and storage are illustrated in
Fig. 6(d). The key challenges include selecting suitable reservoirs for CO
2-EOR and storage based on temperature and pressure conditions, accurately assessing storage capacity and oil recovery, and predicting CO
2 migration and evolution during injection under varying reservoir temperature and pressure conditions.
Therefore, reservoir temperature and pressure conditions serve as both limiting and driving factors for CO
2-EOR and storage. Accurate evaluation of storage capacity and the design of CO
2 injection strategies should be based on target reservoir conditions to ensure that CO
2 enters the reservoir in a supercritical state. The miscibility of CO
2 and crude oil should be improved to maximize the oil recovery and CO
2 storage efficiency. Meanwhile, to maximize the storage capacity while ensuring storage safety (injection pressure < caprock fracture pressure), the CO
2 pressure should be increased and the temperature lowered [
66],[
68],[
69]. Thus, when selecting sites, priority should be given to geological reservoirs with lower temperatures and higher pressure. However, the reservoir pressure should not exceed the original formation pressure to prevent caprock fracturing and CO
2 leakage. Additionally, integrating AI-driven multi-monitoring technologies across the subsurface, surface, and atmosphere enables the real-time monitoring of CO
2 leakage and reservoir pressure. This approach enhances storage safety and oil recovery while ensuring the integrity of the caprock.
2.1.3. Mineral property
The mineralogy of reservoirs has a significant impact on performance for the synergistic processes of CO
2-EOR and storage. For CO
2 storage, mineral trapping is considered to be the safest long-term storage mechanism, as it permanently immobilizes injected carbon. The mineral trapping potential in reservoirs depends on the abundance of reactive minerals containing Ca, Mg, Al, and Fe; higher concentrations of these minerals yield greater storage potential
[70],
[71],
[72]. The reaction pathways of several typical reactive mineral components with CO
2 are shown in
Fig. 7(a) [
73]. The nucleation and growth of the precipitate may control the overall rate of mineralization, depending on factors such as temperature, pressure, fluid chemistry, mineral composition, and reaction time.
Fig. 7(b) shows the representative working conditions of CO
2 mineralization reaction. Temperature affects the rate of mineral dissolution and precipitation, mineral phase transition, and crystal structure stability [
74]. In hydrocarbon reservoirs, the minerals that participate in dissolution–precipitation reactions with CO
2 are primarily carbonate (e.g., calcite and dolomite) and silicate minerals (e.g., feldspars and clays) [
75]. Under acidic conditions, carbonate minerals undergo congruent dissolution, releasing ions such as Ca
2+ and Mg
2+, whereas silicate minerals dissolve incongruently, forming secondary minerals (e.g., kaolinite and quartz) and soluble ions such as Al
3+ [
76],[
77]. Metal ions released during dissolution combine with carbonate ions to form secondary carbonate precipitates, thereby enabling long-term CO
2 mineral storage [
78],[
79]. Common precipitates include calcite and magnesite (MgCO
3) (
Fig. 7(c)) [
80],[
81]. Furthermore, after CO
2 injection, a dynamic process occurs in which primary minerals dissolve and secondary minerals are formed within the reservoir. CO
2 dissolved in formation water forms carbonic acid, which reacts with minerals to generate a secondary pore network and enlarge pore throat diameters, thereby improving the reservoir properties. In addition, water–rock interactions alter rock wettability, facilitate the detachment of crude oil from rock surfaces, and reduce residual oil saturation, enhancing both CO
2-EOR and storage efficiency [
82],[
83]. Metal ions released from the dissolution of primary minerals combine with carbonate ions (CO
32−) to form relatively stable secondary carbonate minerals, which favor the trapping of CO
2 in minerals. However, the resulting secondary precipitates (e.g., calcite, siliceous cements) may block flow channels, thereby adversely affecting oil recovery and distribution of CO
2 in reservoir (
Fig. 7(d)). In summary, CO
2–water–rock interactions induced by reservoir minerals indirectly enhance oil recovery and storage capacity by improving reservoir properties and mobility ratios, whereas mineral trapping reactions strengthen CO
2 storage efficiency and stability. However, long-term storage requires careful consideration of both the mineral trapping efficiency and the risk of leakage due to acid corrosion. Optimizing injection parameters, such as alternating injections of water and CO
2 slugs, can balance oil recovery with reservoir damage, achieving both effective oil recovery and safe storage
[84],
[85],
[86].
The influence of mineral properties on CO
2-EOR and storage is highly complex in reservoirs. On one hand, the diverse and highly heterogeneous mineral composition of reservoir rocks prevents current techniques from accurately quantifying each mineral’s contribution to oil recovery and storage. Conventional experimental methods, which are limited by their temporal and spatial scales, cannot fully characterize the complete CO
2 dissolution–mineralization process in real formations over extended periods. On the other hand, minerals exist in an oil–gas–water (or brine) multiphase environment, where the factors governing primary mineral dissolution and secondary mineral precipitation are intricate. The changes in reservoir properties due to these dissolution–precipitation processes, including the migration of precipitate particles and their effects on rock properties, are also difficult to describe accurately [
68],[
83]. These challenges significantly hinder the precise evaluation of the effects of mineral composition on CO
2-EOR and storage.
Therefore, future research on the impact of reservoir mineral properties on CCUS-EOR should focus on quantifying the contributions of different mineral components to CO
2 mineral trapping. It is essential to understand how primary mineral dissolution and secondary mineral precipitation affect oil recovery and storage processes within the oil–CO
2–water–rock multiphase system under various reservoir conditions. This can be achieved by developing high accuracy coupled numerical simulation methods that integrate flow, chemical, and thermodynamic processes and by incorporating AI techniques to accurately capture the dynamic migration and evolution of CO
2 and mineral components over extended periods of time and pore-scale ranges
[86],
[87],
[88]. Such an approach will enable a quantitative and accurate description of the transport and evolution behaviors of various rock–mineral components in CO
2 multiphase systems
[89],
[90],
[91].
2.2. Fluid characteristics
2.2.1. Crude oil
Due to the scCO
2 dissolution in crude oil viscosity of the mixture is reduced. The ultra-low viscosity of CO
2 reduces the viscosity of the mixture. This results, in improvements in oil mobility and facilitates the displacement of more crude oil from the reservoir [
92]. Meanwhile, the light components are extracted by CO
2, resulting in CO
2 enrichment. However, residual asphaltenes and resins may cause a decline in mobility, which is the primary reason for decrease in oil recovery. Excessive asphaltene and resin content can hinder CO
2 from effectively mobilizing the remaining oil. Therefore, the density and viscosity characteristics of crude oil are key factors influencing the efficiency of CO
2 flooding and storage [
53].
The microscopic interaction mechanisms between CO
2 and different hydrocarbon components significantly affect oil recovery and CO
2 storage. Based on the carbon number, crude oil can be classified into ultra-light components (C
1–C
4), light components (C
5–C
9), intermediate components (C
10–C
19), and heavy components (C
20+) [
93]. The efficiency of CO
2 extraction of ultra-light components is the highest, capable of extracting approximately 53% of light-saturated hydrocarbons, which rapidly transition into the CO
2-rich phase. CO
2-rich phase significantly improves oil recovery. However, the retention ratio of CO
2 in crude oil is relatively low, at only approximately 5%–10%, which is unfavorable for long-term storage [
94]. For the light and intermediate components, the extraction ratio is approximately 28%, with a relatively low diffusion coefficient. As shown in
Fig. 8 [95],
[96],
[97],
[98],
[99],
[100], firstly, the crude oil components were analyzed based on gas chromatography to clarify the characteristics of crude oil components. Secondly, pressure–volume–temperature (PVT) experiments were carried out on crude oil under high-pressure CO
2 conditions to determine key properties of crude oil such as volume expansion coefficient and viscosity, and to clarify the miscibility pressure. Through molecular simulation and core experiments, the miscibility mechanism between CO
2 and different crude oil components and the oil recovery and storage efficiency were revealed. Finally, a reservoir-scale numerical model was constructed to study the influence of different crude oil properties on the synergistic efficiency of CO
2 oil recovery and storage in the reservoir
[95],
[96],
[97],
[98]. Therefore, it is necessary to optimize the injection pressure, such as increasing it to 10–15 MPa, to increase the diffusion of CO
2. Meanwhile, the CO
2 storage ratio in the intermediate components can reach 15%–25%. For the heavy components, CO
2 exhibits the weakest diffusion and extraction capability, with an extraction ratio of only approximately 9%. However, its adsorption capacity in the pore space is high, resulting in a storage ratio exceeding 40%, making it the primary carrier for CO
2 geological storage [
101]. Additionally, the minimum miscibility pressure (MMP) between light oil and CO
2 is relatively low (approximately 8–12 MPa), allowing it to reach miscibility relatively easily and increasing oil recovery by over 20%. In contrast, medium- and heavy-crude oils exhibit higher MMP values (> 15 MPa), necessitating the use of co-solvents (such as dimethylether) or an increase in CO
2 injection pressure to above 20 MPa to optimize miscibility conditions and enhance oil recovery by 5%–15%. In conclusion, the key to CO
2-EOR lies in optimizing the injection parameters according to different crude oil components to maximize oil recovery while simultaneously enhancing CO
2 storage in the reservoir.
Under high reservoir pressure conditions, CO
2 contacts with crude oil typically with a viscosity of less than 10 mPa·s, decreasing the viscosity of the crude oil and as well as the IFT between oil and the gas phase significantly, resulting a decrease in mobility ratio while increasing the capillary number, which significantly improves the efficiency of crude oil production, thus increasing the oil recovery by 12%–25%. This will correspond to storing approximately 30%–45% of CO
2. When CO
2 comes into contact with crude oil of high viscosity, it is more difficult to significantly reduce the viscosity. The increase in oil mobility and getting to multi-contact miscibility state is limited, resulting in an increase in the recovery of only 5%–12%, while the CO
2 storage ratio is only 18%–25% [
102].
When the crude oil density is relatively low (< 0.8 g·cm
−3), low-density crude oil is easily miscible with CO
2, making the displacement front more stable and resulting a significant improvement in oil recovery. In this case, the oil recovery increases by 18%–30%, and the CO
2 storage ratio can reach 35%–50% [
103]. High-density crude oil (> 0.9 g·cm
−3) is difficult to mix with CO
2, resulting in a decrease in displacement efficiency, an increase in oil recovery of only 6%–15%, and a CO
2 storage ratio of approximately 20%–30%. To be miscible or not is the key to maximizing oil recovery and CO
2 storage. If the injection pressure is close to or above the MMP, a storage ratio of 40%–55% can be achieved [
104]. Light crude oils with a density below 0.87 g·cm
−3 are conducive to the formation of miscible phases after CO
2 dissolution [
55]. The density of crude oil can be quantitatively evaluated using the API (here the API is the American Petroleum Institute, and its API Gravity is a measure of the density of crude oil relative to water). Studies have shown that in reservoirs with burial depth of 760–3700 m, when the API is between 29–48, the reservoir is suitable for the injection and storage of CO
2. Because the most efficient oil production through CO
2-EOR comes from miscible displacement, it is recommended to follow the established standards [
33]. According to numerous laboratory studies, the API should be greater than 22, and the viscosity should be less than approximately 5 cP (1 cP = 0.01 mPa·s). Similarly, the oil should be composed of a large percentage of hydrocarbons with a chain length of 5–12 carbons to promote the miscibility of oil and CO
2. Similarly, higher fractions of straight-chain alkanes are preferred to aromatic compounds [
33]. Crude oil with a lower asphaltene content achieves better sweep efficiency by limiting the adsorption of CO
2 on the asphaltene fraction. Simultaneously, asphaltene may block pores [
105].
Before the CO2 front reaches the production well, the miscibility of CO2 with crude oil is poor because of the high content of heavy components. Consequently, oil recovery is reduced, but the CO2 storage ratio in the reservoir is not affected by the crude oil composition. As the content of light and medium components in crude oil increases, that is, the miscibility of crude oil with CO2 increases, it has a positive effect on oil recovery. After the CO2 front reaches the production well, the increase in the heavy component of crude oil will impact the miscibility, thereby reducing oil production and leading to a large amount of CO2 produced.
This section is related to the physical properties of crude oil and analyzes their impact on CO2-EOR and storage synergy considering the aspects of viscosity reduction, component extraction, and miscibility. The focus of this study can be summarized in four categories.
(1) The effects of long chain HC’s on CO2 extraction and miscibility require further investigation. The high efficiency of CO2 extraction of ultra-light and light hydrocarbons leads to the enrichment of CO2 by light hydrocarbons, which improves oil recovery but reduces the retention rate of CO2 in the reservoir at the same time, which is not conducive to long-term storage. The extraction rate of the medium components is high, but the diffusion is slow, and the CO2 storage is relatively low.
(2) The combined effect of heavy components an asphaltenes, on CO2-EOR and storage requires further investigation. While CO2 extracts light hydrocarbons, it may lead to a higher content of heavier species and asphaltenes, which reduces the mobility of the contacted crude oil. However, colloidal asphaltenes and heavier species also provide some dissolution storage capacity for CO2.
(3) The complex multiphase flow and mass transfer mechanism in combination with gravity in CO2-EOR is still unclear. High-density crude oil is difficult to mix with CO2, and CO2 can rise up forming a gas cap, resulting in a decrease in oil recovery, excluding the cases of gas–oil gravity drainage driven systems.
(4) The gas channeling problem during long-term CO2 injection is difficult to control. Even though crude oil has a high content of light components and easily forms a miscible phase with CO2, the medium and heavy components gradually increase as CO2 injection proceeds, resulting in a gradual decrease in sweep efficiency and oil recovery. The mobility ratio between CO2 and formation fluids must be optimized in the middle and later stages of CO2 injection.
Future research should focus on: ① improving displacement efficiency in high-viscosity and high-density reservoirs with high heavy component content. By utilizing AI technology, we can develop efficient EOR and carbon storage chemical systems by optimizing/selecting the key drivers that influence the performance such as the crude oil composition (i.e., selecting the right candidate reservoir-fluid system), thereby promoting the dissolution of CO2. ② Focus on the microscopic interaction mechanisms between various carbon components in crude oil (saturated hydrocarbons, unsaturated hydrocarbons, colloids, and asphaltenes) and CO2. The microscopic interaction law between different components of crude oil and CO2 can be predicted simultaneously using ML.
The synergistic efficiency of CO2-EOR and storage is significantly affected by density, viscosity, and carbon number. According to the color distribution of the three-dimensional scatter plot, the most favorable interval is medium density, low to medium viscosity and light to medium carbon number crude oil. Under these conditions, CO2 has high solubility and strong oil displacement and storage capacity. The most unfavorable interval is high density, high viscosity, and heavy hydrocarbons, under which the miscible displacement capacity of CO2 is significantly reduced. Medium viscosity and density are in the transition zone, and the effect is affected by temperature, pressure, and CO2 injection method. To further optimize the efficiency of CO2 oil displacement and storage, CO2 solubilizers, viscosity reducers or nano-enhancement technology can be considered.
2.2.2. Formation water
Solubility of CO
2 in formation water directly affects the storage capacity related to CO
2 dissolution. Salinity affects the CO
2 solubility in the aqueous phase [
106]. Low salinity is conducive to the dissolution of CO
2 and improves the storage capacity of the aqueous phase, whereas high salinity may reduce the solubility of CO
2 and reduce the storage capacity of the aqueous phase. The process is accompanied by ion exchange and mineral dissolution–precipitation, which affect long-term storage stability [
107]. This phenomenon is mainly attributed to the salting-out effect [
108], wherein, Na
+ and Cl
− ions dissolved in water reduce the solubility of water molecules for CO
2 by changing the structure of water. When the salinity increases from 0 to 12 wt%, the solubility of CO
2 in the formation water decreases by 30%–50%. This indicates that in high-salinity reservoirs, the CO
2 dissolution storage capacity will be limited to a certain extent, and other storage mechanisms, such as mineralization storage or capillary storage, must be considered to improve the storage efficiency [
109].
The pH of the formation water also affects the solubility of CO
2. Its mechanism differs from that of salinity. As the pH decreases, the surface rocks of the reservoir are usually negatively charged, which leads to the adsorption of hydrogen ions on the surface of the rock, conducive to the hydrolysis of CO
2 and thus promoting the dissolution of CO
2 in formation water [
110]. Under low pH (2–5) conditions, the solubility of CO
2 in nanopore water can reach 1.3–1.6 times that in the macroscopic system, while under relatively high pH (7–9) conditions, the solubility of CO
2 is close to that in the macroscopic system. This shows that an acidic environment is more conducive to the dissolution and storage of CO
2, whereas an alkaline environment may reduce the solubility of CO
2, making it easier to exist in the form of free gas or mineral binding [
111]. As shown in
Fig. 9 [
109],[
[112],
[113],
[114], first, the influence of different formation water properties (salinity, pH) on CO
2 solubility and CO
2–water surface tension was determined; secondly, through microscopic experiments and molecular simulations, the dissolution and diffusion mechanism of CO
2 in water was revealed, and a numerical reservoir model of CO
2 dissolution and diffusion coupled with formation water was constructed. The influence of different formation water properties on the CO
2 storage form and storage stability was studied, and the influence of formation water characteristics on the synergistic efficiency of CO
2 oil recovery and storage was revealed.
CO
2 reacts with ions in the formation water to form mineral precipitation, which affects porosity. The ion composition in formation water (such as Ca
2+, Mg
2+, Na
+, Cl
−, and SO
42−) can form a carbonate equilibrium system with CO
2, affecting the dissolution–precipitation process of minerals. After CO
2 dissolves in formation water, it can reduce the pH value, induce the dissolution of carbonate minerals (such as calcite), release Ca
2+, promote carbonate precipitation, lead to changes in pore throat structure, and increase or decrease the reservoir permeability [
115]. Mild mineral dissolution can increase porosity by 2%–5% and increase EOR by 2%–5%. When Ca
2+ exceeds 20 000 parts per million (ppm), it causes severe precipitation and pore blocking, resulting in a 5%–30% decrease in permeability and a 3%–10% decrease in EOR. However, it can promote mineral storage and increase carbon storage rate by 10%–30% [
116].
The properties of formation water are important factors in CCUS-EOR. A low-salinity reservoir environment helps improve the solubility of CO
2, thereby enhancing the solubility and storage capacity and improving the storage efficiency [
117]. The solubility and diffusion of CO
2 in water affect the permeability in the formation; therefore, low-salinity formation water may help increase oil recovery. In contrast, the solubility of CO
2 is low, and it is easier to form free-phase gas in high-salinity reservoirs, which may adversely affect CO
2 storage and increase the risk of CO
2 leakage [
118]. Therefore, in practical applications, the CO
2 injection mode must be optimized according to the salinity of the formation water. Under high-salinity conditions, the CO
2 injection pressure should be increased to maintain the supercritical state, reduce the CO
2 dissolution loss, enhance the volume expansion effect, and reduce the viscous fingering. Under low-salinity conditions, CO
2 is more easily dissolved in water, forming carbonic acid dissolution. The operational factors that matches the formation water properties can achieve storage and oil recovery in the most efficient manner [
119]. CO
2 injection methods include injection pressure, injection mode (continuous injection, WAG injection, and surfactant alternating CO
2 injection) and CO
2 injection rate.
CO
2 storage by mineralization gradually happens after CO
2 is injected into the reservoir. Calcium and magnesium ions in the formation water are important factors affecting the storage capacity related to CO
2 mineralization. The higher the salinity of calcium and magnesium ions in the formation water, the higher the CO
2 mineralization rate. However, when the salinity of formation water is too high, salt precipitation occurs during the water injection process, resulting in blockage of the formation pore throat, making it easy for CO
2 to flow through the high-permeability channel, resulting in a decrease in the CO
2 sweep efficiency and affecting the oil recovery [
49].
During the process of CO2-EOR and saline aquifer storage, the migration and evolution of the CO2 multiphase system determine the oil recovery and CO2 storage ratio. The reaction of CO2 with ions in the formation water may cause carbonate mineral precipitation. Mild dissolution helps improve porosity, whereas large amounts of mineral precipitation lead to pore blockage and have an adverse effect on oil recovery. The salting precipitation phenomenon still has two-sided effects on CO2-EOR and storage efficiency. Overall, the dissolution, precipitation, migration, and evolution of CO2 in formation water remain complex. The multiphase flow and interfacial effects on storage and oil recovery have not been fully understood. Therefore, further research on the relevant mechanisms is needed to improve the synergy between CO2-EOR and storage. Further research should focus on the migration and evolution of the CO2 multiphase system during CO2 injection into the reservoir to further explore the microscopic mechanism.
2.2.3. Injected components
Although numerous laboratory experiments and numerical simulation studies have confirmed the synergistic effects of CO
2 injection in enhancing oil recovery and achieving carbon storage, most existing research focuses on the displacement and storage behavior of pure CO
2, neglecting the impact of impurities in the injected gas (such as N
2, SO
2, CH
4, and light hydrocarbons) on the reservoir fluid phase behavior and long-term storage safety [
120],[
121]. In oil fields, non-pure CO
2 injection strategies are often used to achieve low-cost gas injection, including CO
2–impurity flue gas injection and CO
2–associated gas co-injection [
56],[
122]. Therefore, it is necessary to analyze the mechanism of the composition of the injected gas system on the synergistic technology of oil recovery and CO
2 storage.
(1)
CO2 injection with impurities. Flue gas, a typical waste gas from industrial processes such as coal-fired power plants, has been used in CO
2-EOR and storage projects due to its widespread availability [
123]. In addition to CO
2, the components of flue gas usually include inert and acidic gas components such as N
2 and SO
2, which can significantly affect CO
2-EOR and storage effectiveness through physical and chemical interactions. For example, impurities in flue gas can alter the phase equilibrium of the CO
2–oil system [
124],[
125], reduce the miscibility between CO
2 and crude oil, and thus lead to a decrease in oil recovery. Secondly, the presence of noble gases such as N
2 will reduce the density of CO
2 supercritical phase, resulting in the weakening of fluid compressibility [
124],[
125], which in turn reduces the effective CO
2 storage space utilization within the pore structure and exacerbates the plume effect of CO
2 under buoyancy forces. In heterogeneous reservoirs, the lateral diffusion range of the plume can lead to localized pressure accumulation at the cap rock interface, especially when acidic gases such as SO
2 react with formation water to generate acidic fluids. This accelerates the dissolution and alteration of cap rock minerals, leading to increased cap rock porosity, reduced breakthrough pressure, and a serious threat to the integrity of the reservoir seal [
126]. Therefore, before implementing flue gas injection, it is essential to conduct multi-scale geological modeling and reassess the geological and engineering factors to quantify the impact of impurities on the synergistic effects of oil recovery and CO
2 storage and to reasonably control the proportion of flue gas injected.
(2)
CO2–associated gas co-injection. CO
2–associated gas co-injection helps achieve the dual objectives of efficient crude oil development and reduced associated gas treatment costs [
120]. The main components of associated gas are hydrocarbons, but it also includes a portion of CO
2 that re-emerges from the production wells after the breakthrough of the injected gas. It is important to note that the components of associated gas can affect its phase behavior with crude oil, and excessive levels of certain components may negatively impact oil displacement efficiency [
127]. In particular, in reservoirs where the pressure is close to the MMP, this negative performance may alter the displacement form of CO
2 and significantly reduce both oil recovery and CO
2 storage efficiency. For instance, CH
4, a major component of the associated gas, increases the saturation pressure of crude oil when injected into the reservoir, resulting in decreased CO
2 solubility in crude oil, which further reduces the miscibility and lowers the oil recovery efficiency [
128]. Consequently, CO
2 dissolution storage is adversely affected [
124]. In contrast, other light hydrocarbons in the associated gas (such as C
2–C
4) can directly mix with crude oil in any proportion to form a miscible phase, which helps reduce the MMP. At higher levels of miscibility, oil recovery improves, and after the crude oil is mobilized, the CO
2 storage space increases, leading to enhanced storage efficiency [
129]. Moreover, as oilfield development progresses, the composition of the associated gas changes, and the produced gas typically shifts from being dominated by light hydrocarbons to CO
2. Therefore, it is crucial to determine a reasonable injection gas composition under conditions that do not involve associated gas treatment and to make timely adjustments based on the composition of the produced gas.
Fig. 10 [130],
[131],
[132] shows the relevant results of the research on the injection limits of CO
2 containing impurities. The MMP between the target crude oil and the impurity CO
2 is generally measured using the slim-tube experiment (
Fig. 10(a)) [
131]. Yang et al. [
130] selected multi-objective wells and determined the pressure range for different CO
2 displacement forms based on oil recovery efficiency and IFT, then combined this with actual reservoir pressure to establish a lower limit for CO
2 injection concentration (
Fig. 10(b)). Building on this, Wen et al. [
132] used numerical simulation methods to perform grid partitioning of the reservoir and accurately characterize the dynamic distribution process of the miscible zone under CO
2–associated gas co-injection conditions, which optimizes the best injection conditions (
Fig. 10(c)). In conclusion, the key to CO
2–associated gas co-injection lies in reasonably balancing oil recovery and CO
2 storage efficiency with the associated gas treatment limits, based on the actual conditions of the reservoir.
Fig. 10(d) shows the schematic diagram of the influence of CO
2 purity on the CO
2-EOR and storage synergy efficiency. The reservoir is assumed to be a closed environment, that is, the oil production is in balance with the CO
2 storage. Whether it is non-hydrocarbon impurities (N
2, SO
2, etc.) or light hydrocarbon gases (mainly CH
4) in the injected gas components, the miscible behavior between injected gas and crude oil will be adversely affected when the CO
2 purity is reduced. When the CO
2 purity is higher than the critical value, the conditions of miscible displacement are met. Depending on the characteristics of high displacement efficiency and balanced sweep, the synergistic effect of CO
2-EOR and storage is higher. The reverse is true under immiscible flooding.
Currently, it is challenging to achieve both effective CO2 extraction–storage performance and efficient treatment of associated gas/industrial waste gases simultaneously in the field. In some reservoirs, owing to significant differences between the reservoir pressure conditions and the MMP of CO2 and crude oil, non-pure CO2 injection significantly limits the CO2-driven oil production and storage potential under high treatment costs for output gas/associated gas. To expand the applicability of non-pure CO2, future research should focus on improving the phase behavior between non-pure CO2 and crude oil, such as by using efficient, low-cost chemicals for auxiliary regulation and forming low-cost waste gas treatment technologies. This will play a crucial role in developing synergistic CO2-EOR and storage technologies.
2.3. Operational factors
2.3.1. Injection and production rate
A suitable injection/production rate facilitates the rapid establishment of miscible conditions in the pressurized system. When the injection rate is high, the pressure front of CO
2–oil system can quickly reach the MMP, the two phase IFT is reduced, and the microscopic displacement efficiency in reservoir pores is improved [
133]. Field studies indicate that when the injection rate exceeds 0.5 PV·a
−1 (here the PV is pore volume), the miscibility of oil and gas across the reservoir is significantly improved [
134]; on the other hand, for thick reservoirs, a higher injection rate effectively suppresses gravity-induced gas overriding, thereby enhancing displacement efficiency [
135],[
136]. However, in heterogeneous reservoirs, high injection rates may lead to adverse effects, such as viscous fingering and premature gas breakthrough [
137].
For CO
2 storage, the impact of injection/production rate on storage efficiency varies with the storage stages: short-term storage (gas injection stage) and long-term storage (shut-in stage) [
138]. During short-term storage, continuous injection/production increases the reservoir pressure, raising the risk of caprock fracture. The injection and production rate is positively correlated with the formation pressure gradient, and a safe bottom-hole pressure (BHP) should be maintained [
139]. During long-term storage, the injection rate primarily affects residual and solubility trapping. Lower injection rates enhance residual trapping dominated by capillary force, but extend the injection period is extended and operational cost is increased accordingly [
140]. Some laboratory studies have been performed to investigate the relation between oil recovery enhancement and CO
2 storage related to injection rates [
64],[
[141],
[142],
[143]. The result is shown in
Fig. 11 [
144]. It shows that as oil recovery factor increment becomes slower, CO
2 storage ratio drops rapidly, and higher rate leads to higher oil recovery and lower CO
2 storage ratio at the same time [
144].
Optimal injection/production rates depend on the reservoir type. For homogeneous, high-permeability reservoirs (
K > 100 mD), a higher rate (0.8–1.2 PV·a
−1) is recommended to ensure CO
2 flooding efficiency, rapid miscibility, and uniform displacement front. Residual and dissolution trapping are less sensitive to injection rates in these reservoirs [
145]. Some researchers have shown that, for heterogeneous/fractured reservoirs (e.g., carbonate reservoirs), a lower rate (0.2–0.4 PV·a
−1) mitigates gas channeling and improves sweep efficiency. Pulse injection (alternating high/low rates) has been suggested to further alleviate viscous fingering [
24]. For shale/tight reservoirs, an ultra-low rate (0.05–0.1 PV·a
−1) prevents caprock fracturing, and residual and dissolution trapping are improved. For hydraulically fractured reservoirs, a localized rate of up to 0.3 PV·a
−1 is suggested via artificial fracture networks. Global EOR and storage projects provide empirical benchmarks [
146]. For example, the injection rate in the Weyburn Oilfield in Canada is 0.35 PV·a
−1, and a 25% increase in oil recovery and 80% storage efficiency have been achieved [
147]. Jilin Oilfield adjusted its rate from 0.2 to 0.3 PV·a
−1, and the oil recovery increased by 18% [
148].
Fig. 12 [
149] below illustrates the relationship between the CO
2 injection rates and ultimate recovery/storage efficiency in homogeneous and heterogeneous reservoirs. For homogeneous reservoirs, higher rates guarantee higher oil recovery, whereas a lower rate in heterogeneous reservoirs is required to delay gas breakthrough. CO
2 storage efficiency decreases with higher injection rates, and rate optimization is required to balance oil recovery and CO
2 storage goals.
Throughout the entire CO
2 injection and storage process, the injection rate can be dynamically adjusted at different stages based on the specific objectives of oil recovery and CO
2 storage. During the initial stage, a distinct displacement front exists between CO
2 and oil, and the reservoir pressure gradient is low. A high injection rate is recommended to establish a significant displacement pressure differential (and also speeds) and rapidly achieve miscible flooding. In the middle stage, the injection rate can be moderately reduced to mitigate risks of gas breakthrough and caprock fracturing and further expand sweep efficiency [
150]. When oil recovery reaches a plateau and further extraction becomes challenging, the lowered injection rate strengthens residual trapping and dissolution trapping, and CO
2 storage stability is improved. Additionally, researchers have utilized reinforcement learning (RL) to dynamically adjust injection rates based on real-time reservoir pressure and gas production monitoring, improving storage efficiency by 10%–15% [
151].
Table 1 [152],
[153],
[154] summarizes the CO
2 injection rate ranges, corresponding oil recovery increments, and final storage efficiencies in different types of formations.
From an economic perspective, high injection rates or prolonged injection periods require higher compressor power and energy consumption. Conversely, prolonged low-rate injection exacerbates pipeline corrosion and increases the risk of CO
2 leakage. Current studies primarily focus on the impact of injection rates on oil recovery and CO
2 storage, whereas the potential costs associated with rate adjustments remain underexplored [
155].
Due to the scale effect, parameters such as the injection/production rate, gas channeling time, rock porosity, and permeability determined in the laboratory largely deviate from field scale. Even if the lab measurements can be extrapolated to the field scale by the similarity criterion, the corresponding errors are amplified simultaneously, and the results obtained from different experimental equipment and core sizes are distinct, thus the optimal rate values obtained in the laboratory is not uniform when upscaled to the field cases [
156]. Second, a mutual influence exists between the injection/production rate and pressure, and changing the injection rate inevitably leads to fluctuations in the pressure field. Therefore, it is difficult to separate the effect of the injection rate on oil displacement and CO
2 storage from the influence of injection pressure for independent analysis. In addition, for most reservoirs, the injection/production rate over the entire lifespan of CO
2 storage is not constant; however, a constant rate still dominates recent research, and the influence of different rate combinations and timing on oil displacement and storage are still unclear. In terms of the influence mechanism of the storage ratio, a high injection/production rate weakens the residual trapping led by capillary force, reduces the storage proportion of residual gas and storage stability, and increases the potential risk of long-term storage. Meanwhile, a high injection and production rate shortens the contact time between CO
2 and the minerals of the rocks and reduces the effect of mineralization storage, storage capacity, and stability of long-term storage.
For future work, the coupling effect of the injection/production rate and pressure induced by injection/production balance will be considered to ensure miscible conditions and storage efficiency, and thus multi-objective optimization models can be established to balance the oil recovery and CO2 storage rates. Long-term storage mechanisms, such as residual, solubility, and mineralization trapping, have been studied to optimize the injection and production rate and accelerate the reaction between reservoir fluid and minerals. Considering the correlation between the injection and production rates, the injection rate determines the rate of CO2 advancing in the reservoir, while the production rate affects the reservoir pressure distribution. Both need to be optimized to maintain a stable displacement front to avoid gas channeling or premature breakthrough.
2.3.2. Injection pressure
Injection pressure mainly affects oil recovery and CO
2 storage rate by changing the reservoir pressure distribution, CO
2 phase, and fluid–rock interaction. First, CO
2 at different pressures exhibits different physical properties. Research shows that scCO
2 can reduce the viscosity of crude oil (by 80%–90%) and extract light components, which can improve the microscopic oil displacement efficiency by 20%–40% [
157]. Second, the injection pressure controls the reservoir pressure, influences the miscibility of the CO
2 injection process and crude oil, and ultimately affects the oil recovery and CO
2 storage rates. For immiscible flooding, the final oil recovery and CO
2 storage rates are more highly correlated with the gas injection pressure. When the injection pressure reaches the MMP, the influence of increasing injection pressure on the oil recovery and CO
2 storage rates is not obvious (
Fig. 13) [
37],[
158]. In addition, the injection pressure has a significant impact on stability. First, high pressure increases CO
2 density, viscosity, and mobility ratio, which can inhibit the viscosity fingering effect. Second, the increasing density of CO
2 can reduce the gravity override effect and improve the vertical sweep efficiency [
159].
During CO
2 geological storage, injection pressure has important impact on binding, dissolution, and mineralization storage. Under high pressure conditions, scCO
2 occupies large pores and is trapped as a residual phase by capillary forces after pressure reduction. Moreover, high injection pressure enhances the solubility and reactive storage of CO
2. High pressure promotes CO
2 dissolution in formation water and oil, and the solubility increases with pressure. High pressure accelerates the reaction of CO
2 and carbonate minerals to form carbonates, and a long duration of high-pressure environment can shorten the time required for mineralization reaction. Oyagha et al. [
160] indicated that CO
2 solubility trapping is a kind of long-term and stable retention process and the pressurization process is an important factor expediting CO
2 solution driven by CO
2–liquid density difference. However, on the other hand, high pressure will lead to fracturing in cap rock, so the maximum injection pressure is generally set at 0.7–0.9 times of the fracture pressure to avoid inducing micro-cracks [
161]. For high-permeability sandstones, miscible flooding and high storage rates are the main targets, and the pressure range is 1.1–1.2 MMP <
P < 0.8
Pfrac (where
Pfrac is formation fracture pressure). For low-permeability/shale reservoirs, the pressure should be slowly increased to the MMP, fracture propagation can be used to improve sweep efficiency, and nanofluid injection can be considered to enhance residual trapping. Controlling the reservoir pressure by WAG to suppress gas channeling, maintain formation pressure close to the MMP, and controlling the rate of produced liquid to avoid rapid pressure drop are important optimization avenues [
162]. Previous work also shows that for immiscible flooding, higher pressure is beneficial for higher oil recovery and CO
2 storage. However, as pressure exceeds the MMP, this kind of positive effect becomes inconspicuous (
Fig. 14) [
163].
The injection pressure is mainly affected by the CO2–oil interaction, and its limitation is determined via MMP. The minimum miscible pressure of crude oil in different reservoirs is very different; therefore, it is difficult to establish a standard to measure the correlation of recovery/storage rate with injection pressure. Second, because the MMP is affected by crude oil composition and temperature, the prediction accuracy of MMP based on the existing empirical formula is still insufficient, and the underestimation and overestimation of MMP further affect the design of the gas injection pressure. Low pressure leads to immiscible injection, whereas high pressure causes inefficiencies in compression. It also increases the risk of reservoir and cap fractures. In addition, the multiphase flow mechanism of CO2–oil–water impacted by injection pressure is still unclear, and the changes in IFT, seepage, and capillary force caused by pressure variation have not been fully quantified. The effect of gas injection pressure on the storage rate is mainly reflected by the dynamic change in the storage mechanism and the contradictory relationship between pressure and storage capacity. The change in reservoir pressure affects the conversion direction and rate among free, dissolved, bound, and solid CO2, which is difficult to predict in real time.
Based on the discussion above, a ML-based MMP prediction model can be developed in the future to further improve the prediction accuracy of MMP. The microscopic mechanism of CO2–oil–water multiphase flow in pores with microscopic experiments and numerical simulations are needed. A multi-field coupling geo-mechanical model is established to accurately predict the influence of injection pressure on overburden layers, and then used to optimize the injection pressure to improve the CO2 storage capacity of the reservoir while ensuring cap rock integrity.
2.3.3. Injection modes
At present, the main CO
2 injection methods include continuous gas drive, WAG, gravity stabilization drive, and CO
2 huff-n-puff. Continuous gas flooding forms a gas drive front, reduces residual oil saturation by reducing oil viscosity, expanding oil volume, and miscible displacement, and finally, CO
2 remains in the reservoir pores in free and dissolved states [
164]. This method is suitable for homogeneous reservoirs with permeability (> 100 mD) with a small dip angle and high injection rate to ensure that the pressure front quickly reaches the MMP (for the right fluid system) after injection. This method easily causes viscous fingering due to the flow ratio, forms gas channeling, and decreases the conformance coefficient if the reservoir heterogeneity is too strong. This method can improve oil recovery to a certain extent, but obtaining a high CO
2 storage rate is difficult. For example, in the Permian Basin in the United States, continuous gas drives show a 18% increase in oil recovery but only 55% storage [
165]. WAG refers to the alternate injection of water and CO
2, the use of water slug to control the mobility ratio, inhibit gas channeling, expand the swept volume, promote CO
2 solubility storage, and strengthen residual trapping. In the case of WAG injection, the optimal injection pressure should be slightly higher than the MMP, which is suitable for heterogeneous medium-permeability reservoirs (10–100 mD). By optimizing the water–gas slug ratio and injection cycle, higher oil recovery and CO
2 storage rates can be obtained. The reasonable water–gas slug ratio is generally between 1:1 and 3:1. A shorter cycle injection period is beneficial for reducing the influence of gravity differentiation, whereas a longer cycle injection period is conducive to pressure recovery. What’s more interesting is, some researches show the effect of water in different CO
2 injection modes on oil recovery and CO
2 geo-storage (
Fig. 15)
[166],
[167],
[168],
[169],
[170],
[171],
[172],
[173]. Water-saturated–CO
2 (wsCO
2) means CO
2 with 5% water and carbonate water injection (CWI) means CO
2 with over 85% water. Results show that CO
2 injection with about 50%–75% water is ideal for co-optimizing oil recovery and CO
2 storage
[166],
[167],
[168],
[169],
[170]. Gravity-stabilized flooding is mainly suitable for reservoirs with high dip, and the storage mechanism is based on the upper part of the structure because CO
2 forms a stable gas cap at the top of the structure (while in some of the lighter oil reservoirs, CO
2 can also underride the oil zone as shown by Gautam et al. [
171] (
Fig. 16)). This method is suitable for a reservoir dip greater than 5°, ensuring that the gravity segregation dominates, and the ratio of vertical permeability to horizontal permeability is greater than 0.1 to facilitate vertical flow. It is generally injected at a low speed (0.1–0.3 PV·a
−1). For ultra-low permeability/tight reservoirs, CO
2 huff-n-puff is generally considered to extract the light components of crude oil through periodic pressure change. During soaking, CO
2 diffusion is the main mechanism for the production of micro–nano pore crude oil and carbon storage [
172].
For different types of reservoirs, different CO
2 injection methods should be adopted, such as continuous gas injection (CGI), WAG, gravity stable drive, and CO
2 huff-n-huff. The key parameters of gas injection methods are different, and the measurement standards are not identical; therefore, it is difficult to form a set of standards to determine the specific parameter range. In addition, different injection methods have a certain range of applications and shortcomings; for example, WAG may improve the sweep efficiency but may sacrifice the storage of CO
2 in the free state, and CGI has a high CO
2 storage capacity but gas channeling is a risk [
173]. In addition, the injection method changes the reservoir pressure distribution, which may induce microfractures or fault activation in the cap rock, and the existing model makes it difficult to predict the security of 100-year storage. Developing intelligent adaptive injection technology by combining ML with real-time monitoring data and dynamically adjusting injection methods (such as CGI/WAG switching) is highly recommended. A fully coupled geomechanical–geochemical–flow model needed to be constructed to quantify the effects of different injection methods on mineral storage and fracture propagation.
Actually, the oil recovery and CO
2 storage process are affected synthetically by different operational parameters stated above. The coupling mechanism is shown in
Fig. 17 [
129],[
158],[
174].
3. Multi-factor coupling analysis and solutions for CCUS-EOR
Compared with traditional CO
2-EOR techniques, CCUS-EOR synergistic technology (which aims to achieve the dual benefits of increased oil production and reduced carbon emissions simultaneously) operates on a longer-time scale, encompassing not only the CO
2 injection and oil displacement processes but also the long-term storage of CO
2 in the reservoir. The process of CO
2 flooding and storage will inevitably go through different development stages, and the process of CO
2 storage can be divided into physical storage process and chemical storage process based on storage mechanism [
175]. Currently, the stage division methods for the CCUS-EOR full lifecycle are mainly classified into oil recovery-oriented and storage-oriented types: the former is based on the injection–production stage, which includes the CO
2 injection and oil displacement stage, followed by the CO
2 injection-only stage after reservoir depletion, and the final CO
2 static storage stage [
176],[
177]; the latter is based on the classification of CO
2 storage forms, which divides the process into physical CO
2 storage stages (such as trapping storage and structural storage) and long-term chemical storage stages (such as dissolution storage and mineralization storage) [
178]. Based on the concept of CO
2-EOR and storage synergistic technology, this study redefines the full lifecycle of CO
2-EOR and storage into two simple stages. According the time of CO
2 injection phase is completed, the whole lifecycle of CCUS-EOR is divided into CO
2-EOR storage stage and long-term CO
2 storage stage.
CO
2-EOR storage stage refers to the process of scCO
2 entering the reservoir, miscible or immiscible interaction with crude oil under high temperature and high pressure to drive crude oil production. The injected scCO
2 dissolved into the oil continuously reduces the viscosity, increases its fluidity, and significantly improves the displacement efficiency. After oil production, CO
2 continues to fill the pore space of porous media, and achieves physical storage of CO
2 while maintaining reservoir energy. In addition, CO
2 dissolves into formation water and reacts with rocks to form chemical precipitation, which may change the pore throat morphology while achieving solubility and mineral trapping [
179]. At this stage, to achieve a substantial EOR target, it is often necessary to inject CO
2 with a large sweep volume and oil displacement efficiency. As a result, CO
2 typically migrates a considerable distance within the reservoir after the end of this stage.
The long-term CO
2 storage stage refers to the process in which scCO
2 enters the water layer under high temperature and pressure conditions. Here, CO
2 either dissolves in high-salinity formation water or reacts chemically with water and rock, generating significant precipitation and achieving CO
2 chemical storage [
180],[
181]. During this stage, the crude oil in the reservoir is typically in the depletion phase, and the dominant form of CO
2 storage is mineralization, driven by the extensive injection of CO
2 and the chemical interactions between water and reservoir rocks. However, due to the influence of reservoir tilt, CO
2 plume phenomenon may occur further under the density drive. Finally, after a long-term physical migration and chemical reaction process, CO
2 can be safely and stably stored in the formation.
The two stages outlined above serve as the foundation for forming synergistic technology for the full lifecycle of CO
2-EOR and storage. Key factors influencing the effectiveness of oil displacement and storage in each stage are selected, and effective technical solutions and combinations under the influence of adverse factors are discussed, providing guidance for field-scale CO
2-EOR and storage projects. As shown in
Table 2, the results of the single-factor analysis of CO
2-EOR and storage synergistic technology from the previous section are summarized, while excluding factors that are difficult to control (such as reservoir temperature, mineral properties, and formation water salinity conditions). The key controlling factors for each stage are selected, and based on the influence patterns of these factors on the oil recovery and storage performance, corresponding technical strategies are proposed.
(1) CO2-EOR storage stage. In the CO2-EOR storage stage, the crude oil in the reservoir is the primary target of CO2 injection. The continuous injection of CO2 fills the volume and pressure voids left by the extracted crude oil, facilitating crude oil extraction and achieving CO2 synchronous storage. Based on the characteristics of this stage, the impact mechanisms of the key controlling factors on the synergistic effects of CO2-EOR are categorized. The research progress on the optimization of CO2-EOR and storage synergy is discussed from three perspectives: the distribution of the CO2 saturation field, CO2–crude oil phase behavior, and CO2–formation water–rock reactions.
CO2 saturation field distribution. The CO
2 saturation field distribution is the result of CO
2 injection into a reservoir to displace crude oil, based on the fundamental physical properties of the reservoir and fluid. First most of the reservoirs are not homogeneous; rather, due to geological processes such as sedimentation and diagenesis, reservoirs often exhibit strong heterogeneity characteristics [
39]. Second, the viscosity and density differences between CO
2 and crude oil can lead to viscous fingering and gravitational segregation phenomena. Under these real-world conditions, CO
2 injection is highly prone to channeling, which reduces the swept volume of CO
2, leading to poor oil displacement and storage performance. This is one of the key factors that hinder many CO
2-EOR projects from scaling up from small- to medium-scale field trials and large-scale applications [
182].
Numerous researchers have conducted extensive research on the control of CO
2 channeling, which can be broadly divided into two categories: flow control and conformance control. Flow control methods mainly reduce flow disparity by adjusting the physical properties of CO
2 or crude oil in the injected fluid and are generally used to prevent premature CO
2 channeling. The prevention (or delay) of channeling can be considered from aspects such as the design and dynamic adjustment of production process parameters (injection method, injection rate, etc.) and well location optimization. Common methods include WAG, injection–production coupling control, and the injection of CO
2 thickening agents and drag reducers. It is impossible to completely control channeling using these techniques alone, and adjusting the injection–production processes is often ineffective (especially in low/ultra-low permeability reservoirs). The use of chemical agents to seal the channel is a technique for directly adjusting the physical properties of the reservoir. In particular, gel-based methods have become widely used in recent years. The mechanism of gel blocking systems is to selectively enter and occupy fracture spaces, allowing CO
2 flow to enter the reservoir matrix and migrate to deeper layers, thus improving both oil displacement and storage efficiency. Zhao et al. [
183] summarized the development history of gel systems and provided a brief evaluation based on five aspects: injectability, migration depth, plugging ability, reservoir damage potential, and economic cost (
Fig. 18). In recent years, with the development of smart hydrogel materials science, many sealing systems with temperature and salinity resistance characteristics have been developed to address conformance control issues in harsh reservoir environments [
23],[
24]. Although significant progress was made in developing new materials, most of the sealing materials are hard to use in field applications effectively. Future studies should focus on scaling up between laboratory and usage in the field.
The regulation based on the above-mentioned means is conducive to expanding the distribution degree of the CO2 saturation field inside the reservoir, which has far-reaching significance for the subsequent two stages of chemical storage considering the CO2–water–rock reaction.
The influence of CO2–
crude oil phase behavior. CO
2 miscible displacement is considered an efficient CO
2 displacement technology for EOR and CO
2 storage
[184],
[185],
[186],
[187],
[188]. The prerequisite for the design of CO
2 miscible displacement in a reservoir is the relationship between the reservoir pressure and the MMP of CO
2 and the
in situ oil. CO
2 miscible displacement can only be achieved on a large scale when the reservoir pressure exceeds the MMP. A prerequisite for the formation of CO
2 miscible displacement in a reservoir is the relationship between the reservoir pressure and the MMP of CO
2 (or any other injected gas in that matter) and the reservoir oil. CO
2 miscible displacement can only be achieved on a large scale when the reservoir pressure exceeds the MMP [
19],[
137]. To achieve this goal, both crude oil properties and reservoir pressure should be aligned. First, crude oils with a higher content of medium and heavy components are more difficult to achieve miscibility. Therefore, some researchers have used chemical agents to alter the interfacial properties between CO
2 and crude oil to achieve miscible contact between oil and CO
2. Liu and Rui [
189] proposed the use of dimethyl ether as an effective chemical agent for CO
2-EOR with net carbon emission reduction. Laboratory tests showed that it can significantly increase the solubility of CO
2 and suppress the escape of light hydrocarbon components from crude oil, thus assisting conventional CO
2-EOR and enhancing CO
2 storage in the reservoir. In response to green energy development, Singh et al. [
190] extracted a green surfactant from biological resources (fenugreek seeds) that, without harming the environment, could potentially enhance CO
2’s ability to improve crude oil production in porous media. However, increasing the reservoir pressure can also promote the microscopic displacement efficiency of the CO
2 through achieving miscibility. During CO
2-EOR and storage, injection–production alignment can be used to adjust or maintain the reservoir pressure to meet miscibility conditions . Yang et al. [
191] significantly increased the reservoir pressure to 1.2 times the MMP, enhancing the interaction of medium- and heavy-components in crude oil with CO
2, leading to increasing oil recovery from small pores, and balancing the displacement front to improve the swept volume, resulting in a substantial increase in both oil recovery and CO
2 storage efficiency. Additionally, field experiments in Shengli Oilfield, China, confirmed that high-pressure injection could preemptively meet CO
2–crude oil miscibility conditions, with an expected 11.6% increase in oil recovery after 15 years of implementation [
191]. Apart from the aforementioned factors, controlling the composition of the injected gas to balance CO
2–crude oil miscibility conditions is crucial for achieving efficient CO
2-EOR and storage. Optimization of these various factors to achieve CO
2–crude oil miscible displacement is a key for simultaneously improving oil displacement and CO
2 storage during the early stages of CCUS-EOR.
In summary, the optimization of synergistic effects in the early stages of CO2-EOR and storage should focus on the core goals of “uniform sweep” and “stable and sustained miscibility.” This can be achieved through techniques such as flow control, miscibility enhancement, and smart monitoring, combined with an integrated engineering design considering the inherent geology, to achieve a dynamic balance between oil displacement efficiency and secure storage. Future engineering advancements are required to overcome key technological bottlenecks, such as early detection of the reservoir heterogeneity achieving and sustaining miscibility state regulation, and compatibility of green smart materials.
CO2–formation water–rock reactions. In addition to the factors considered in the CO
2-EOR storage stage, the impact of CO
2–dissolved water–rock reactions on both oil displacement and storage must be considered [
192]. While crude oil is displaced and extracted by scCO
2 in the oil–water transition zones (i.e., transition zones), some CO
2 (along with other gases as impurities) also dissolves in high-salinity formation water
[193],
[194],
[195] and reacts with rock minerals [
196],[
197] and in some cases can form precipitants. The salinity of the formation water and reactivity of the reservoir rock may significantly influence the effectiveness of CO
2-EOR and storage, especially in the context of near wellbore behavior of the system and as well as in the far-field where CO
2 plume interacts with brine and as well as with hydrocarbons. The impact of CO
2–water–rock reactions on oil displacement has been fully studied based lab-scale experiments and as well as numerical models. For example, Sun et al. [
198] reviewed the macroscopic reservoir and pore-scale microscopic salt distribution patterns, and argued that the formation water salinity, CO
2 injection rate, and initial reservoir properties are the key factors that determine the quantity and distribution of precipitated salts and the extent to which injection capacity is reduced. Yuan et al. [
199] quantitatively studied the amounts of precipitates generated by CO
2 and formation water under different temperature, pressure differential, and scaling ion concentration conditions during the CO
2-EOR process and the impact of precipitation on the reservoir properties. They found that, compared to the scenario in which precipitation effects were not considered, the oil recovery rate from CO
2-EOR after 20 years decreased by 4.19%. These studies have only analyzed the individual effects of CO
2–water–rock reactions on oil displacement and CO
2 storage. Research on how to promote efficient CO
2 chemical storage while ensuring CO
2 oil displacement is still insufficient, and this is an important direction for future research.
In summary, the optimization of synergistic effects in the early stages of CO2-EOR and storage should focus on the core goals of “uniform sweep” and “stable miscibility.” This can be achieved through techniques such as flow control, miscibility enhancers, and smart monitoring, combined with an integrated geological engineering design, to achieve a dynamic balance between oil displacement efficiency and storage security.
The other challenge in the CO
2-EOR storage stage lies in balancing the effects of CO
2–water–rock chemical reactions on the synergistic technology of oil displacement and storage, particularly in estimation and controlling reaction rates, stability, and the adaptability of engineering parameters. Future advancements are required to overcome key technological bottlenecks, such as reservoir heterogeneity control, miscibility state regulation, chemical reactions regulation, and compatibility of green smart materials, to reduce the inverse impact caused by the multiphase fluid–rock contact fractions within the reservoir, which affect the effectiveness of EOR and CO
2 sequestration [
200].
(2) Long-term CO
2 storage stage. After the CO
2 injection phase is completed, CO
2 storage stage starts, the CO
2 plume generally spreads over the larger segment of the reservoir, along with CO
2 storage occurring primarily through CO
2 dissolution and chemical reactions between CO
2 and formation water [
200]. At this stage, no further fluid injection affects the reservoir’s flow field or saturation field, and the focus should shift from CO
2 oil displacement to storage safety monitoring, and early warning technologies [
201]. Currently, researchers have conducted extensive research on monitoring systems for safety for coupled CO
2-EOR and storage projects, forming a multi-dimensional monitoring framework centered around the reservoir, cap rock, wellbore, and near-surface environment and as well as surface facilities and pipelines
[202],
[203],
[204],
[205],
[206]. Whittaker et al. [
205], based on the geological characteristics of the Weyburn and Pembina oil fields, established a comprehensive monitoring system by integrating reservoir pressure, geochemical characteristics, and surface gas concentration monitoring techniques, which has become a benchmark in research and development. Zaluski et al. [
206] further improved the monitoring system for the Weyburn low-permeability oil field CO
2-EOR and storage project by analyzing the applicability and cost-effectiveness of different monitoring techniques for various targets. Hamling et al. [
207] developed a cost-effective monitoring system for large-scale CO
2-EOR and storage projects (annual injection greater than 1 million tons) for the Bell Creek low-permeability oil field in the United States. Lakeman et al. [
208] established a CO
2-EOR and storage monitoring system for the Pembina low-permeability oil field in Canada by integrating reservoir monitoring and geochemical, geophysical, and environmental monitoring techniques. However, existing systems are mainly designed for conventional reservoirs and lack adaptability to ultra-low permeability reservoirs. In addition, systems with complex fracture networks and leakage risks caused by high injection pressures have not been systematically addressed.
In particular, for CO
2-EOR and storage synergistic technology, the current safety monitoring systems still face many challenges [
209]. These include reservoir complexity: strong heterogeneity and the interlacing of natural/induced fractures lead to highly uncertain CO
2 migration paths, making it difficult for traditional monitoring technologies (e.g., seismic imaging) to accurately capture local leakage or migration paths. Surface environmental complexities: Loose surface soil layers and adverse topography weaken the sensitivity of near-surface gas monitoring, and as well as weather conditions (such as wind speed and rainfall) further increase monitoring errors. Coherence of economic and technical adaptability conflicts: Existing high-precision technologies (e.g., 4D seismic) are expensive, whereas low-cost methods (e.g., surface gas sampling) have insufficient resolution, making it difficult to meet the long-term monitoring needs of large-scale ultra-low permeability reservoirs. Multiphysics coupling risks: The long-term evolution of reservoir pressure and evolving stress during the static storage stage could compromise the containment through caprock. Existing models have limited predictive capabilities for such multi-physics coupling risks.
In summary, for the long-term CO
2 storage stage, future research should focus on the development of intelligent monitoring technologies (such as dynamic early warning systems based on fiber-optic sensors and AI), the construction of multi-scale coupling models (integrating geological mechanics, geochemistry, and fluid dynamics to simulate evolution of leakage risk) [
210], as well as low-cost, high-sensitivity
in situ monitoring methods (such as nano-sensors or microbial tracers). It is also necessary to advance domain-specific monitoring standards (such as 3D monitoring networks for ultra-low permeability reservoirs) and interdisciplinary risk management systems (covering leakage early warning, repair, and long-term stability assessment) to achieve synergistic optimization of safety and cost-effectiveness.
4. Comprehensive synergistic method for CCUS-EOR
The above chapter discusses the dual influence mechanism of key factors on the benefit of CO2-EOR and storage, and gives technical countermeasures from the inverse impact existing in different development stages. On this basis, this chapter further discusses the implementation path of synergistic technology, and reviews the synergistic technical process of CO2-EOR and storage is reviewed, to provide effective guidance for the key decisions of on-site CCUS-EOR projects.
The synergistic problem of CO
2-EOR and storage is a process of single factor decoupling, sub-factor classification and re-coupling, and finally multi-objective optimization. The decoupling process is the key single factor analysis (e.g. Section 2), which analyzes the inconsistent association of the EOR and storage performance under a single factor. At present, single-factor studies based on experiments and numerical simulations have been very substantial. For example, high permeability and porosity can improve oil displacement efficiency and CO
2 storage capacity. The recoupling process of multi-factor needs to be classified according to the governing mechanisms of each single factor on the EOR and CO
2 storage performance, and the influence limit of each parameter on the EOR and CO
2 storage performance is clearly defined, and then the multi-factor coupling analysis is carried out. In this respect, the current research only stays at the stage of partial factor coupling. This is because the current research methods and technologies still cannot fully mimic the complex multi-factor coupling conditions inside the reservoir, such as the current CO
2 flooding and storage experiments based on high pressure microfluidics, which cannot consider the complex multi-component interaction of oil–CO
2–water–rock [
196] (i.e., with proper scaling, core-floods with PVT experiments will be more relevant). Furthermore, after identifying the impact of multi-variable coupling on the inconsistent association of CO
2-EOR and storage, optimization process is mainly based on the existing combination of the current technologies. For example, combination of injection and production optimization techniques and chemical injection (surfactants and plugging agents) aims to solve the adverse effect of high MMP or CO
2 channeling on CCUS-EOR.
At present, the synergistic evaluation methods mostly start from reservoir engineering evaluation index system (such as channeling degree, gas–oil ratio (GOR), storage capacity, and so on) of CCUS-EOR, and then through analyzing the internal relationship between the dual objective evaluation ranking of CO
2-EOR and storage, the synergistic evaluation ranking of reservoir engineering is constructed, and the synergistic evaluation method of CO
2-EOR and storage is finally established [
132],[
[211],
[212],
[213],
[214]. These evaluation methods are commonly used to identify key injection–production parameters and technical policies in reservoir engineering projects for CO
2 flooding. As there is no systematic coordination technology for CO
2-EOR and storage, the above methods still belong to the single-objective optimization of maximum oil recovery or storage efficiency in essence. The weight allocation of CO
2-EOR and storage relies too much on empirical assumptions and fails to fully consider the actual benefits brought by CO
2 storage. In terms of economic evaluation, the traditional net present value (NPV) model is dominated by oil output income, and takes CO
2 capture, compression, and injection cost as the main expenditure item, while carbon sequestration income is mostly regarded as “by-product” and not included in the total value chain. Despite attempts to introduce carbon trading mechanisms (such as carbon tax credits and sequestration subsidies) in recent years, its economic quantification still has the following shortcomings. First, the dynamics of carbon prices (such as regional carbon market fluctuations and policy uncertainty) are not sufficiently coupled to NPV models. Second, although some scholars have introduced carbon economic benefit analysis in single technical links such as injection and production optimization, chemical additives and channeling agent research and development, there is still a lack of systematic methods for efficiency enhancement potential and economic evaluation of combinations of various technologies at different development stages. In particular, there is a lack of systematic modeling of life-cycle synergistic economic benefits (e.g., sequestration subsidies to reduce capture costs, benefits of cross-industry CCUS cooperation). Third, life-cycle costs (such as long-term monitoring, analysis, and leak remediation costs) are often reduced to fixed proportional parameters, leading to long-term economic forecasts that are unrealistic. The future economic evaluation strategy should fully consider the benefits of carbon sequestration, and realize the collaborative economic evaluation of CO
2-EOR and storage in the whole process of CCUS-EOR.
As shown in
Fig. 19, the entire CCUS-EOR synergistic technology framework should include the theoretical research stage of single-factor decoupling analysis and multi-factor classification and re-coupling process. On this basis, existing technologies should be used to optimize inverse impact, and the effect evaluation of CO
2-EOR and storage should be completed based on multi-objective optimization methods. Carbon storage benefits should be introduced into the economic accounting process. Finally, a synergistic techno-economic evaluation model of CO
2 injection for oil displacement and storage conforming to the whole life cycle of various reservoirs should be established. However, there are still challenges in the integrated process of CCUS-EOR, such as multi-field, multi-objective, and multi-threaded coupling of various technology applications, especially considering the uncertainty and variation of oil prices and economics under carbon subsidies. To accelerate the green transformation of the oil and gas industry and form the comprehensive evaluation methods for CO
2-EOR and storage in the oilfield, the following recommendations can be made for the future development of synergistic methodologies:
(1) Establish a full-life cycle dynamic management process with critical path analysis for the long-term risk matrix and monitoring, establish a full-process cost–benefit model covering capture, transportation, injection and storage, focus on quantifying long-term storage monitoring and leakage remediation costs, combine carbon sequestration subsidy policies, clarify the accounting boundary of negative carbon benefits, and reduce full-cycle economic risks.
(2) Form a multi-objective optimization method driven by AI, use ML algorithms to analyze the relationship between the main control parameters and the CO2-EOR coupled with storage performance, and dynamically optimize the combination of parameters; through RL to simulate the impact of carbon price, oil price, and variations, and impact of policy change related scenarios on project revenue, real-time adjustment or selection of technical options to balance between CO2-EOR and storage.
(3) Establish the connection between quantification and monetization of negative carbon emissions, develop an accounting methodology for decarbonization revenue based on net carbon emissions considering the emissions from crude oil combustion to calculate “net negative carbon value,” and incorporate it into the carbon trading system, explore cross-industry carbon quota replacement mechanisms (such as cooperation between different oil fields, operators, and power plants), and improve the economic and environmental sustainability of CCUS-EOR projects.
In the future, continuous optimization of synergistic technological evaluation methods for CO2-EOR and storage can provide effective guidance for decision-making for a given field, further promote the transformation of CCUS-EOR coupling with the right economic drive for dual socio-economic benefits, move towards the goal of net carbon emissions, and accelerate the realization of global carbon reduction and neutrality.
5. Conclusions
This study reviews the mechanisms and parameters affecting performance of oil recovery and CO2 storage coupling in CCUS-EOR projects. Based on existing theories and technological advancements various approaches and evaluation methods are summarized for different development stages considering the adaptive aspects of implementation for changing environment (policy, technology, technical and regulatory limits). The factors analyzed for CO2-EOR, and safe CO2 storage technologies include but not limited to reservoir architecture, fluid characteristics, and engineering parameters and constraints, considering injection–production coupling, the use of chemical agents to improve crude oil/CO2 interactions via fluid properties, handling heterogeneity related challenges.
Reservoir properties and architecture, in situ fluid characteristics and its interactions with the injectants and operational parameters are the three key factors affecting the synergistic effect of CO2-EOR and storage. There is no obvious correlation between permeability, porosity, and synergistic efficiency for dynamic performance for EOR and storage due to reservoir characteristics and architecture and the time scales involved. CO2 channeling prevention and symptomatic treatments are the core means to enhance the coupled implementation of the projects. When CO2 at the supercritical state, elevated temperatures weaken the performance of the oil displacement, and the increase of pressure will offset that adversity and strengthen the storage capacity. It is necessary to alleviate the inverse impact of oil displacement and storage under high temperature and high pressure through managing reservoir pressures. In terms of mineral properties, the dissolution of CO2–water–salt and reactions and the formation of secondary minerals have a two-sided effect on oil displacement and storage, which should be also be dynamically evaluated according to key parameters. In terms of fluid characteristics, microscopic interaction mechanism of CO2 and crude oil composition directly affects the oil recovery and later CO2 storage efficiency. It is necessary to develop low-cost environmentally friendly additives (such as surface-active agents) to dynamically regulate fluid properties and/or behavior at the interfaces for effective solutions. In addition, the dissolution–precipitation–transport process of CO2 in formation water the entire process for the full value chain involves multiphase flow in porous media with reactive transport and interphase mass transfer. Among all, a few of the engineering parameters can be controlled in real time such as injection rate/speed, pressure, injection composition (generally in the context of additives and impurities) and injection modes.
The process of CO2-EOR and storage involves many technical fields such as reservoir engineering, production/well engineering, and surface and facility engineering. Given all the complexities and multi-disciplinary nature of this objective, CO2-EOR and CCUS, traditional engineering methodologies should be coupled with the newer techniques and technologies using ML and as well as AI. In the context of candidate reservoir or disposal site selection, digital twins and analog case selections will be essential for the success of the startup phase of the new projects. Continuous learning and data sharing worldwide will also be essential to be able to tackle this global problem through sharing data and as well as best practices. Where the causality is hard to identify, data-centric approaches can lend themselves into history match development where the causality and the controlling physical parameters can be identified. For chemical materials used in oil production enhancement, interdisciplinary collaboration should be emphasized, especially for their design. Some of the considerations should focus on the cost element of those in the for the economies of scale (for example, projects across various nations and their timing, etc.) Furthermore, novel and advanced materials will be part of the system, especially considering the time-scales and the complexities. Based on the highlighted aspects, coupled CO2-EOR-CCUS-objective should consider the double benefits of the increased oil production and carbon reduction.
CRediT authorship contribution statement
Zhenhua Rui: Writing – review & editing, Writing – original draft, Supervision, Resources, Project administration, Methodology, Investigation, Funding acquisition, Conceptualization. Tingting Liu: Writing – review & editing, Writing – original draft, Methodology, Investigation, Conceptualization. Xin Wen: Writing – review & editing, Writing – original draft, Methodology, Investigation, Conceptualization. Siwei Meng: Writing – review & editing, Writing – original draft, Methodology, Investigation, Conceptualization. Yang Li: Methodology, Investigation, Conceptualization. Birol Dindoruk: Methodology, Investigation, Conceptualization.
Declaration of competing interest
The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.
Acknowledgments
We greatly acknowledge the financial support from the National Key Research and Development Program of China (2022YFE0206700), the Science Foundation of China University of Petroleum, Beijing (2462021YJRC012). We would also like to express our sincere gratitude to professors (Yongle Hu, Yueliang Liu, Fengyuan Zhang, Yang Zhao, Jirui Zou, and Ting Hu) and PhD students (Cheng Qian, Zheng Zhang, Zesen Peng, and Haiyang Deng) for their valuable contributions.
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