Advances in North American CCUS-EOR Technology and Implications for China’s Development

Abstract

CCUS-EOR combines emission reduction with economic benefits, making it one of the key technologies for addressing global climate change. Addressing the lack of systematic comparative studies on the differences in geological endowments and engineering conditions between China and North America in existing literature, this paper systematically reviews the progress of North American CO₂-EOR in areas such as gas source structure transformation, capture technologies, and pipeline network construction, based on a self-constructed database of typical projects. It then conducts a quantitative comparative analysis of typical projects in China and the United States from three dimensions: reservoir geological endowment, gas source composition, and infrastructure. The study reveals that the advancement of U.S. CO₂-EOR projects benefits from increasing industrial CO₂ supply and the construction of cross-regional pipeline networks. Comparative analysis indicates that North American projects primarily feature miscible displacement in medium-to-low temperature and light oil reservoirs. This contrasts fundamentally with the characteristics of China’s continental reservoirs, which exhibit “strong heterogeneity, high viscosity, and high minimum miscibility pressure (MMP)”. Currently, China’s CCUS-EOR is transitioning from engineering demonstration to commercial application. However, gaps persist compared to more mature international systems in areas such as low-concentration CO₂ capture, pipeline network construction for source-sink matching, and suitability for continental reservoir EOR. Moving forward, China can draw on U.S. CCUS-EOR development experience, accelerate research on relevant technologies tailored to its continental reservoir characteristics, and establish a differentiated whole-industry-chain CCUS-EOR technology system.

1. Introduction

In recent years, extreme weather events have become increasingly frequent, and global climate change has intensified, with significant temperature rises observed both on land and in the oceans [1]. Growing evidence indicates that greenhouse gases generated by human activities are the primary drivers of global warming, particularly CO₂ emissions from fossil fuel combustion and agricultural activities, which contribute approximately two-thirds to global warming [2,3]. Currently, reducing greenhouse gas emissions is a challenge that all humanity must collectively address to counteract the drastic changes in the global climate.

The Paris Agreement aims to reduce the risks and impacts of climate change by limiting the global average temperature increase to well below 2 °C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5 °C above pre-industrial levels [4]. In 2021, the International Energy Agency (IEA) released its first Net Zero Emissions Roadmap, targeting global energy sector CO₂ Net-Zero Emissions [5]. The Intergovernmental Panel on Climate Change (IPCC) Sixth Assessment Report sets emission requirements: limiting global warming to 1.5 °C above pre-industrial levels necessitates reducing greenhouse gas emissions by 43% relative to 2019 levels by 2030 and by 84% by 2050 [6]. China has set its “dual carbon” goals: achieving peak carbon emissions before 2030 and carbon neutrality before 2060. Similarly, the United States has established targets to achieve a carbon-free electricity sector by 2035 and net-zero greenhouse gas emissions by 2050 [7].

CCUS encompasses the capture, utilization, and storage of CO₂, adding a utilization phase to CCS. Scholars recognize that focusing solely on storage efficiency is less effective than deploying CO₂ for beneficial purposes to mitigate its impact on the global carbon cycle [8]. Moreover, CCUS holds commercial value and stands as one of the most attractive strategies for addressing greenhouse gas emissions. CCUS Enhanced Oil Recovery (EOR) technology not only injects captured CO₂ into reservoirs for permanent storage but also boosts oil recovery rates, increasing project profitability and significantly enhancing investment viability. It has become an effective means of implementing CO₂ emissions reduction in many countries today. In 1972, the world’s first commercial CO₂-EOR project commenced operations at the Kelly-Snyder oilfield in Texas, USA, significantly boosting local oil production [9]. By the end of 2022, nearly 100 CCUS projects were either operational or in the planning stage in China, with CCUS-EOR technology being the primary deployed CCUS approach [10].

The United States holds a world-leading position in CCUS-EOR technology, having advanced to the commercial deployment phase. The U.S. federal government’s 45Q tax credit policy introduced in 2018 has further accelerated the deployment of local CCUS-EOR projects [11,12,13,14]. China’s overall CCUS-EOR technology development still lags behind the United States, with technologies remaining immature and large-scale application facing numerous challenges. Currently at the industrial application stage, it struggles to meet the urgent demands of low-carbon development. Therefore, absorbing and learning from North American CCUS-related technologies can accelerate China’s technological advancement.

However, current reviews mainly focus on specific technologies or regional projects. They lack systematic comparisons between China and the United States. Specifically, differences in geology, infrastructure, and policies are often ignored. This leads to adaptability issues when applying these technologies. Therefore, this paper uses a self-constructed dataset of North American projects. We analyze the technical logic behind the dominance of miscible flooding. We also systematically compare the key differences in reservoir properties, gas sources, and pipeline networks between the two countries. The aim is to move beyond simple technology replication. Based on the characteristics of China’s continental reservoirs (such as low permeability and strong heterogeneity), we propose tailored technical and policy directions. This provides targeted references for the large-scale application of CCUS-EOR in China.

2. CCUS-EOR Technology Process

Carbon dioxide capture and storage (CCS) is one of the most critical technologies required to achieve global low-carbon goals. Among all CCS methods, CO₂-enhanced oil recovery (EOR) represents a technique with significant inherent economic value [15]. The primary objective of CCS-EOR technology is to reduce emissions through geological CO₂ sequestration while simultaneously leveraging the revenue generated by enhanced oil recovery (EOR) to make high-cost CCS projects economically viable. Carbon Capture, Utilization, and Storage (CCUS) expands upon CCS by incorporating CO₂ utilization. This concept was first proposed by Shen Pingping et al. [16], emphasizing the integration of CO₂ reduction with its beneficial application. They recognized that focusing solely on carbon sequestration efficiency is less effective than deploying CO₂ for productive uses [8,17]. CCUS-EOR technology represents one application of CCUS. Compared to CCS-EOR, it prioritizes utilizing CO₂ to enhance oil production rather than emphasizing emission reduction through permanent sequestration. CO₂ storage emerges as a natural environmental benefit during the enhanced oil recovery process [18]. CCUS-EOR technology encompasses CO₂ capture, transportation, EOR, and storage. Figure 1 illustrates a typical CCUS-EOR process flow.

2.1. CO₂ Capture

CO₂ emissions primarily originate from industrial processes, fossil fuel combustion, agricultural activities and transportation. CO₂ capture involves the process of capturing and separating CO₂ from these sources. The captured CO₂ is purified to produce a high-concentration, high-purity CO₂ stream, which is then compressed, transported, utilized, and sequestered [19,20]. For the power generation sector, CO₂ capture technologies can be categorized into three approaches: pre-combustion capture, oxy-fuel combustion capture, and post-combustion capture [21,22]. Concurrently, emerging carbon capture technologies such as chemical looping combustion (CLC), electrochemical capture, and direct air capture (DAC) are progressively developing [23].

The three traditional capture methods each possess distinct advantages and disadvantages in terms of efficiency, cost, and retrofit flexibility [24,25,26,27,28,29]. Post-combustion capture, owing to its ease of retrofitting, remains the most widely adopted method today [30,31]. The potential of the other two approaches lies in reducing equipment costs and energy consumption. Emerging technologies further broaden the scope of carbon capture applications. Direct air capture (DAC) [32,33] differs from traditional stationary source capture by addressing dispersed emissions, such as those from vehicles on highways. By capturing CO₂ from the air using adsorbent materials and then desorbing and purifying it, the resulting product can be utilized in industrial processes like enhanced oil recovery and biofuel synthesis [34,35]. However, developing highly efficient and low-cost adsorbents remains a core challenge in current R&D efforts. The advantages and disadvantages of different capture methods are summarized in Table 1.

Regardless of the CO₂ capture technology employed, one step involves separating CO₂ [36]. CO₂ separation technologies are primarily categorized into physical and chemical methods [37]. Physical methods include solvent absorption, adsorption, membrane separation, and cryogenic distillation [38]. Chemical methods encompass solvent absorption, adsorption, membrane absorption, electrochemical processes, and hydrate formation [39,40].

Table 1. Advantages and Disadvantages of Various CO₂ Capture Methods.

CO2 Capture Technology	Advantages	Disadvantages	Applicable Targets
Pre-combustion Capture	Captured CO2 has high concentration [41]; CO2 is easily separable [42]; Purified hydrogen can be used as fuel for fuel cells and as feedstock for synthesizing high-value chemicals [31,43]; Water consumption is lower [44].	Separation process equipment requires high investment costs [45]; Gasification processes may generate polluting gases; Existing equipment requires retrofitting [31].	Integrated Coal Gasification Combined Cycle (IGCC) power plants, steel, cement, glass industries, etc. [46]
Oxy-fuel combustion	Reduces emissions of pollutants such as nitrogen oxides; compared to air combustion, nitrogen oxide emissions decrease by 60–70% [46]; High combustion efficiency, low consumption.	Separating oxygen from air consumes significant energy, impacting overall power plant efficiency [46].	Combustion systems such as boilers, furnaces, and gas turbines
Post-combustion capture	Technologically flexible and cost-effective, applicable for retrofitting existing power plants; additionally removes nitrogen oxides and sulfur oxides.	Low partial pressure of CO2 in flue gas, requiring large gas volumes to be treated, resulting in higher costs [44].	Suitable for existing coal-fired power plants
Direct air capture	Flexible site selection reduces subsequent transportation costs.	Expensive equipment, relatively low efficiency	Distributed emission sources (e.g., transportation vehicles)

Table 1. Advantages and Disadvantages of Various CO₂ Capture Methods.

CO2 Capture Technology	Advantages	Disadvantages	Applicable Targets
Pre-combustion Capture	Captured CO2 has high concentration [41]; CO2 is easily separable [42]; Purified hydrogen can be used as fuel for fuel cells and as feedstock for synthesizing high-value chemicals [31,43]; Water consumption is lower [44].	Separation process equipment requires high investment costs [45]; Gasification processes may generate polluting gases; Existing equipment requires retrofitting [31].	Integrated Coal Gasification Combined Cycle (IGCC) power plants, steel, cement, glass industries, etc. [46]
Oxy-fuel combustion	Reduces emissions of pollutants such as nitrogen oxides; compared to air combustion, nitrogen oxide emissions decrease by 60–70% [46]; High combustion efficiency, low consumption.	Separating oxygen from air consumes significant energy, impacting overall power plant efficiency [46].	Combustion systems such as boilers, furnaces, and gas turbines
Post-combustion capture	Technologically flexible and cost-effective, applicable for retrofitting existing power plants; additionally removes nitrogen oxides and sulfur oxides.	Low partial pressure of CO2 in flue gas, requiring large gas volumes to be treated, resulting in higher costs [44].	Suitable for existing coal-fired power plants
Direct air capture	Flexible site selection reduces subsequent transportation costs.	Expensive equipment, relatively low efficiency	Distributed emission sources (e.g., transportation vehicles)

Physical absorption achieves CO₂ separation by adjusting operating pressure and temperature, without any chemical reaction between CO₂ and the absorbent. Mature industrial processes include Rectisol (using methanol), NHD (polyethylene glycol dimethyl ether), and Selexol, which are primarily suitable for high-pressure and low-temperature environments [47]. Physical adsorption widely employs Pressure Swing Adsorption (PSA) technology [30], commonly utilizing traditional adsorbents such as zeolite molecular sieves and activated carbon. However, current research is increasingly focusing on novel adsorbent materials; Metal–Organic Frameworks (MOFs) [44] are considered the next generation of high-efficiency adsorbents due to their ultra-high specific surface area and tunable pore sizes. In contrast, chemical absorption demonstrates higher capture efficiency at low partial pressures. The industry mainly uses amine-based solutions (e.g., MEA, MDEA) as absorbents, though they are associated with high-energy consumption [48]. Emerging solvents like Ionic Liquids possess excellent thermal stability but face high cost barriers, requiring further research for industrial implementation. Additionally, Mixed Matrix Membranes (MMMs) [49] combine the processability of polymers with the high separation performance of inorganic fillers, effectively overcoming the ‘trade-off’ effect of traditional membrane materials and significantly improving gas separation efficiency.

2.2. CO₂ Transport

Since utilization and storage sites are often distant from capture sources, CO₂ transportation becomes a critical link in the entire CCUS chain, with transport costs accounting for approximately 25% of total CCUS project expenses [50]. In Wales, UK, lacking domestic geological storage sites, the UK government plans to invest in transporting CO₂ generated by factories and power plants in North Wales to the seabed in Liverpool Bay [51]. In Canada, the Alberta Carbon Trunk line project operates a 240-kilometer pipeline transporting CO₂ captured from central Alberta’s industrial zone to oil fields in the central and southern regions for enhanced oil recovery [52]. In 2023, China completed its first 100-kilometer-long transport pipeline (total length 109 km), laying the foundation for scaling up the entire CCUS industry chain [53]. Safe and reliable transportation methods are critical for CCUS projects.

Currently, CO₂ transportation primarily involves two methods: pipeline transport and tank container transport. Pipeline transport is divided into onshore and offshore pipelines, while tank container transport includes rail, road tanker trucks, and ship transportation [45,54]. Pipeline transport offers low costs and high capacity, making it suitable for long-distance transportation and the current mainstream method. Road and rail transport are appropriate for small-scale, short-distance CO₂ shipments. When distances are excessively long or involve crossing large bodies of water, ship transport becomes more economical.

Each CCUS project must comprehensively evaluate various factors to determine the optimal transportation solution. Precise alignment of costs, scale, and distance across different modes ensures efficient CO₂ transport from capture to utilization. The maturity of transportation technologies and the completeness of infrastructure are key factors constraining the large-scale application of CCUS. Therefore, building transportation networks is a crucial pillar for the scaled development of CCUS.

2.3. CO₂-EOR Mechanism

CO₂ utilization refers to using captured CO₂ to produce valuable products or enhance resource recovery, achieving economic benefits alongside partial carbon sequestration. It primarily encompasses physical, chemical, biological, and geological utilization, with geological utilization being the most common approach [55,56]. CO₂ Enhanced Oil Recovery (CO₂-EOR), as the core technology of geological utilization, delivers both social and economic benefits [57].

The core mechanism of CO₂EOR primarily leverages CO₂ to alter the flow properties of crude oil. Under reservoir temperature and pressure conditions, supercritical CO₂ enhances crude oil mobility by expanding its volume, reducing interfacial tension, lowering viscosity, and extracting light hydrocarbons from the crude. This process ultimately increases oil recovery rates [58]. Based on the relationship between reservoir pressure and minimum miscibility pressure (MMP), displacement mechanisms are categorized into miscible displacement (Figure 2a), near-miscible displacement, and immiscible displacement (Figure 2b) [59]. When reservoir pressure exceeds the minimum miscible pressure (MMP), CO₂ becomes fully miscible with crude oil and forms a miscible zone at the displacement front. Theoretically, this achieves 100% micro-displacement efficiency and optimal displacement efficiency [60]. When pressure falls below MMP, non-miscible displacement occurs, primarily leveraging CO₂ dissolution and viscosity reduction to enhance oil recovery [61,62], with displacement efficiency slightly lower than miscible displacement. Near-miscible displacement occurs in the transitional zone where reservoir pressure approaches but remains slightly below MMP. Zhang Xiansong et al. [63] conducted CO₂ near-miscible displacement studies using capillary experiments and numerical simulations. They categorized the displacement process into three stages: displacement phase (dominated by expansion), mixing phase (viscosity reduction), and breakthrough phase (extraction effect), providing a useful framework for understanding near-miscible displacement. Complex near-critical phase behavior and multiphase dynamic mass transfer processes remain key factors hindering theoretical progress in near-miscible displacement.

Although the micro-mechanism of CO₂ enhanced oil recovery primarily relies on miscible effects, in field practice, a rational injection method can effectively expand the gas sweep volume and delay gas migration. Common injection methods mainly include continuous gas injection production, water-gas alternation, and CO₂ slug injection. The advantages and disadvantages of different methods are shown in

Table 2. Different Gas Injection Methods and Their Advantages and Disadvantages [64,65,66].

Injection Method	Principle	Advantages and Disadvantages	Typical Case
Continuous gas injection production	Continuously inject CO2 to replenish energy for the formation.	Simple to operate; can quickly replenish energy to the formation. However, it consumes a large amount of CO2, and is prone to gas channeling affected by production pressure differences and fractures.	Block 38 of Subei Basin Muma (China); Petra-Nova (USA) [67]
Water-Air Alternation (WAG)	Water preferentially enters high-permeability channels, increasing the seepage resistance of gas and forcing CO2 to flow toward low-permeability areas.	CO2 can enter low-permeability zones and small-pore throats, expand the swept volume, and delay gas channeling. However, water injection in low-permeability reservoirs is difficult (high startup pressure), and the water shielding effect prevents the mobilization of remaining oil at the wellbore.	Caoshe Oilfield in Subei Basin
CO2 Huff and Puff	An unstable pressure field forms between high-permeability and low-permeability areas, with continuous changes in flow direction, leading to fluid redistribution. During well shutdown, CO2 can fully contact crude oil.	Interferes with the advancement of the CO2 front, delays gas channeling, gives full play to CO2 diffusion, and increases swept volume. However, parameters such as gas injection rate, cycle, and gas slug need to be optimized.	Block Q7P1 of Jiangsu Oilfield [68]
Pulsed Gas Injection	Create an unstable dynamic environment through pressure field fluctuations, suppress front expansion, and delay gas channeling.	CO2 miscibility can be achieved by controlling pressure. However, it is not suitable for fracture-vuggy reservoirs, as CO2 tends to channel along fractures due to pressure fluctuations.	Girasol Oilfield [69]

.

Continuous CO₂ injection operations are relatively straightforward and were initially applied extensively in West Texas, USA (e.g., during the early stages of SACROC). However, they are highly prone to gas migration in heterogeneous reservoirs, resulting in low sweep efficiency. Water–gas alternation (WAG) involves alternating water and gas injections, utilizing water to control the Mobility Ratio and suppress viscosity index progression. This is currently the most widely applied technique in North America, particularly in Permian Basin carbonate reservoirs, effectively balancing production rates with sweep volumes. CO₂ gulping is suitable for small-scale reservoirs lacking pipeline infrastructure or with poor injection-production connectivity, offering low investment and rapid results. Pulsed injection suppresses front expansion through unstable pressure fields, delaying gas migration.

In the United States, approximately 40 billion barrels of oil remain recoverable after primary and secondary extraction, with an additional 14 billion barrels of residual oil beneath and adjacent to existing fields. CO₂-EOR technology can produce nearly 250,000 barrels of oil per day [70], demonstrating the feasibility of significantly enhancing oil recovery rates using CO₂.

2.4. CO₂ Geological Sequestration

CO₂ sequestration technology involves capturing CO₂ from emission sources, transporting it, and injecting it into designated storage sites. Through physicochemical means, CO₂ is stored and permanently isolated from the external environment, preventing its release into the atmosphere [41], thereby effectively mitigating the greenhouse effect. Geological CO₂ sequestration has become the mainstream storage method due to its minimal disturbance to surface ecosystems and the stability of deep storage.

CO₂ geological sequestration mechanisms are typically categorized into four primary types: structural traps, residual traps, dissolution traps, and mineralization traps. The sequestration of CO₂ within a hydrocarbon reservoir is influenced by one or a combination of these mechanisms. Structural and residual traps utilize physical means for sequestration [71]. The former relies on the sealing properties of cap rocks and faults to achieve large-scale CO₂ sequestration. The P18-4 oilfield in the Netherlands demonstrates the critical role of cap rock and fault sealing in sequestration [72]. The latter method utilizes capillary forces within pores to confine CO₂ as dispersed phases like bubbles [73,74]. Dissolution traps and mineral traps exemplify chemical sequestration. Dissolution traps achieve storage by dissolving CO₂ into reservoir fluids [75], while mineral traps achieve permanent sequestration by chemically converting CO₂ into solid carbonate minerals. Although they offer superior storage stability, their chemical reaction cycles are significantly longer than physical processes, and their storage capacity is relatively low. Tang et al. [76] calculated the CO₂ sequestration potential in depleted reservoirs, finding that structural, dissolution, and mineral traps account for 90.6%, 4%, and 5.4% of CO₂ storage, respectively. This indicates tectonic traps play the primary role in the overall sequestration mechanism.

The core logic of CO₂ geological sequestration mirrors nature’s fossil fuel storage mechanisms: injecting CO₂ into specific geological formations at defined depths for storage [20]. Potential CO₂ geological storage sites currently include deep saline aquifers, depleted oil and gas reservoirs, unmineable coal beds, shale formations, basalt formations, and CO₂ hydrate storage [77,78,79]. While depleted oil and gas reservoirs account for a limited share of storage capacity, they represent one of the most mature technologies today. Millennia of hydrocarbon storage history validate their structural integrity for carbon sequestration. Prior exploration has clarified geological features, and existing wellhead equipment and pipeline infrastructure can be directly repurposed, significantly reducing costs [80]. More importantly, CO₂-EOR technology enables economic recovery of residual oil while achieving sequestration [79]. Canada’s Weyburn-Midale sequestration project employs this technology [81].

The selection of CO₂ storage sites requires consideration of multiple factors beyond storage capacity alone, including storage costs, technological maturity, stability, and environmental risks. Future trends in site selection will shift from a singular focus on “storage capacity” toward a balanced approach that integrates technological, economic, environmental, and social considerations.

3. North American CCUS-EOR Technology Advancements and Applications

3.1. Data Sources and Statistical Methods

To systematically evaluate the geological suitability and engineering characteristics of CCUS-EOR technologies in North America, this study constructed a specialized database comprising 148 representative projects, serving as the foundational dataset for subsequent technical analysis. Data collection primarily relied on the authoritative global EOR project survey published in the Journal of Petroleum and Natural Gas, which has been led by the team of Larry Lake, a distinguished professor at the University of Texas at Austin, and holds significant industry reference value [82]. Considering data timeliness and completeness, a “baseline and update” construction strategy was adopted: using the 2014 survey list as the baseline, the database was supplemented and updated with parameters for CO₂ flooding projects commissioned between 2014 and 2023, primarily integrating the latest industry reports published by Advanced Resources International (ARI) [83,84]. This ensures the database reflects the current technological landscape in North America. Furthermore, to guarantee data accuracy, this study cross-validated key reservoir parameters using publicly available geological data from the U.S. Department of Energy (DOE) and selected project operators.

Regarding sample selection, to ensure broad industrial representativeness of statistical results, this study prioritized commercial and pilot projects located in five core regions: the Permian Basin, Gulf Coast, Rocky Mountains, Midcontinent, and Midwest. These areas account for the vast majority of total CO₂-EOR production in the United States. For the 148 valid projects selected, this study established a multidimensional dataset incorporating engineering information and geological properties. Key indicators were systematically compiled, including operator, production start date, displacement type (miscible/immiscible), primary reservoir lithology, porosity, permeability, reservoir depth, crude oil gravity (API), and formation crude oil viscosity.

3.2. Overview of CO₂ Source Supply in the United States

CO₂ is a critical factor in implementing CCUS-EOR technology, with its sources, distribution, and supply stability directly impacting project feasibility. North America’s CO₂ sources primarily include natural CO₂ sources and industrial CO₂ sources. Early North American projects leveraged the discovery of large CO₂-rich gas reservoirs, providing ample, stable, and inexpensive CO₂ supplies that enabled sustained large-scale CO₂ injection. In contrast, other regions globally face challenges in developing CO₂-EOR projects due to the scarcity of natural CO₂ [85]. As natural CO₂ consumption in the United States declines and capture technology advances, reducing capture costs, CO₂ captured from waste gases emitted by industrial plants and other facilities is increasingly being utilized to enhance oil and gas recovery [86].

It should be pointed out that the generalized CO₂-EOR technology includes two types of gas sources: CO₂ from natural gas reservoirs and industrially captured CO₂. Strictly speaking, only the process of using CO₂ captured from industrial emissions falls into the category of CCUS-EOR. Early projects in the United States were mostly based on natural gas sources and belonged to CO₂-EOR; with the increasing demand for emission reduction, the proportion of industrial sources has risen, and they are gradually transitioning to CCUS-EOR.

The United States has 32 CCS-EOR operators across 147 projects in five regions: the Permian Basin, the Gulf of Mexico, the Rocky Mountains, the Central Continent, and the Midwest. By 2021, CO₂ enhanced oil recovery projects in the U.S. had increased recovery rates to 299,300 barrels per day. Across 147 projects operated by 32 distinct operators, the total daily CO₂ supply reached 85 million cubic meters, comprising 57 million cubic meters of natural CO₂ and 28 million cubic meters of industrial CO₂. Figure 3 illustrates the distribution of CCS-EOR projects in the United States as of 2021. For these projects, 5 natural CO₂ sources and 13 industrially captured CO₂ sources are utilized to supply the required CO₂. In 2021, the supply of natural CO₂ in the United States decreased to 6 million cubic meters per day, marking a significant decline from 2014 levels. Conversely, industrial CO₂ sources continue to expand, with growth observed across all regions. Despite the decline in natural gas sources, U.S. CCS-EOR crude oil production remains stable at nearly 300,000 barrels per day, sufficiently demonstrates that industrial gas sources have begun to support production capacity.

Natural CO₂ serves solely as a resource carrier, whereas industrial CO₂ capture not only reduces carbon emissions but also meets oil recovery demands, representing a major pathway for low-carbon synergistic technology development. Currently, transforming gas source structures still faces significant challenges. In 2010, the U.S. CCS-EOR project projected CO₂ sources for 2021 at 181 million cubic meters per day, with industrial CO₂ accounting for 85 million cubic meters per day. However, actual 2021 total CO₂ sources amounted to 85 million m³/day, with industrial CO₂ accounting for only 28 million m³/day. The actual proportion of industrial CO₂ sources fell below projections, indicating ongoing challenges for the U.S. CCS-EOR project in diversifying CO₂ sources and scaling industrial CO₂ capture. On one hand, capture costs remain high and scale is limited for small-to-medium industrial emitters. On the other hand, poor spatial alignment between some oilfields and industrial clusters, coupled with high transportation costs, restricts the viability of industrial CO₂ sources. Looking ahead, natural CO₂ production will steadily decline. Low-cost industrial gas supplies will become critical for U.S. CCS-EOR to sustain oil production. Developing the entire chain—from industrial capture to transportation and utilization—will be the core challenge facing the United States.

3.3. Analysis of North American CO₂-EOR Technical Indicators

U.S. CCUS-EOR projects account for approximately 90% of the global total [87]. To understand the intrinsic drivers of CO₂ flooding in North America, a thorough analysis of key reservoir parameters is essential. The effectiveness of CO₂ flooding technology implementation is highly correlated with multidimensional indicators such as reservoir properties, fluid characteristics, and phase conditions. Regarding reservoir properties, rock permeability and porosity are central factors [88,89]. Permeability influences CO₂’s transport capacity within reservoirs, while jointly regulating CO₂ convective transport processes with porosity. Regarding fluid properties, crude oil viscosity determines its inherent flow ability. While high-viscosity crude exhibits poor mobility, CO₂ dissolution significantly reduces its viscosity [90]. Crude oil saturation reflects the volume fraction of crude oil within reservoir pores, with higher initial oil saturation indicating greater extraction potential. Regarding phase conditions, miscible flooding—a mainstream technology in the United States—requires achieving the minimum miscible pressure, which is influenced by CO₂ purity, crude oil composition, and reservoir temperature [91]. These indicators collectively influence CO₂ enhanced oil recovery efficiency from different dimensions. Analyzing these technical metrics helps define reservoir criteria for CO₂-EOR, providing a reference for identifying potential reservoirs in other regions and reducing trial-and-error costs.

This study surveyed 148 CCS-EOR projects across U.S. states. Among these, Texas hosts 82 projects, Mississippi 19, Wyoming 15, and Michigan 10, while other states have only 1–2 projects each. Results are shown in Figure 4.

Among these 148 projects, 93.79% are CO₂ miscible flooding projects. The composition of crude oil significantly affects the minimum miscible pressure (MMP); the higher the proportion of light components, the lower the MMP. As can be seen from Figure 4h, most North American reservoirs contain crude oil with API grades between 30 and 40, classified as light oil with low miscible pressure. Consequently, most North American reservoirs are suitable for miscible flooding. It can be seen from Figure 4b that 45.07% of the reservoir temperatures are between 40–60 °C and the average reservoir temperature is 56 ℃. Considering that, higher temperatures increase the minimum pressure required to achieve miscibility, projects implementing miscible flooding generally opt for the medium-to-low temperature range to reduce operational complexity and costs. As can be seen from Figure 4h. The proportion of projects with initially high oil saturation reservoirs has significantly decreased, demonstrating CO₂ flooding is effective in lowering residual oil saturation. As shown in Figure 4e–g, permeability values predominantly ranged from 10 to 100 mD, with low permeability (<10 mD) accounting for 37.85%, categorizing these reservoirs as low-to-medium permeability. Despite the inherent poor fluid mobility of low-to-medium permeability reservoirs, the widespread application in North American projects demonstrates CO₂’s unique advantage in overcoming flow resistance in low-permeability reservoirs. Porosity values predominantly range from 10–15%, with most crude oil viscosities falling between 1–5 cP, classifying them as low-viscosity oils.

In summary, reservoirs in North America suitable for CO₂ flooding exhibit the following characteristics: miscible flooding dominance, moderate to low temperatures, high oil saturation, medium to low permeability, moderate porosity, and light, low-viscosity crude oil. This summary of characteristics provides a reference for CO₂ flooding technology in similar reservoirs worldwide.

3.4. Key Block Technology Application: Case Study of the SACROC Formation in the Permian Basin

The Permian Basin ranks among the highest-producing major oil-rich basins, hosting over half of North America’s onshore oil rigs. The majority of U.S. CCUS projects are concentrated in the West Texas carbonate region of the Permian Basin [92,93]. Spanning New Mexico and West Texas, the basin comprises three sub-basins: the Midland Basin, Delaware Basin and Central Basin [94], with original oil in place estimated at 95.4 billion barrels. In the 1970s, large-scale CO₂ enhanced oil recovery EOR trials were conducted in the Permian Basin of West Texas and southeastern Mexico, initiating the technology’s large-scale application [95].

The success of CO₂ flooding technology in the Permian Basin hinges on robust infrastructure and data support. On one hand, Advanced Resources developed a database encompassing 207 Permian Basin reservoirs, using five key indicators—reservoir depth, crude oil gravity, reservoir pressure, reservoir temperature, and crude oil composition—to identify formations suitable for enhanced oil recovery via CO₂ miscible flooding [96]. On the other hand, the project benefited from abundant underground pure CO₂ sources and robust infrastructure. While early CO₂ supply relied on natural gas separation in the southern part of the basin, Chevron constructed the first supercritical CO₂ pipeline (CRC), transporting CO₂ from the Val Verde Basin to the SACROC block. By the early 1980s, the development of the Bravo Dome, McElmo Dome, and Sheep Mountain gas fields, coupled with the construction of a large-scale pipeline network, secured CO₂ supply (Figure 5a). Companies like ExxonMobil leveraged this network for their projects. Subsequently, Occidental Petroleum invested $850 million to build natural gas and CO₂ processing plants along with cross-regional pipelines, further enhancing gas transportation capacity [70]. Edwards et al. [97] analyzed the pipeline network connecting ethanol plants to the basin, broadening perspectives on industrial gas sourcing.

As EOR projects scale up, existing natural gas sources and pipeline infrastructure struggle to satisfy current requirements. Although industrial CO₂ supply continues to grow, it still falls short of filling the gap, with significant disparities remaining between natural and industrial CO₂ in terms of cost and scale. However, Kuuskraa et al. [70], through their research on CO₂ flooding projects in the Permian Basin, have confirmed that industrial CO₂ has huge economic potential in the market, providing a key basis for the transformation of gas sources.

Supported by a comprehensive industrial system, CO₂ flooding has demonstrated remarkable effectiveness in the Permian Basin. As the basin’s first large-scale CO₂-EOR project, SACROC holds original geological oil reserves of 4.1 × 10⁸ tons, equivalent to approximately 2.8 billion barrels. Production commenced in 1949, peaking at 1020 × 10⁴ tons in 1974 before declining to 40 × 10⁴ tons by 1998 (The development history is shown in Figure 5d). Following CO₂ miscible flooding in 2002, output rebounded to 150 × 10⁴ tons by 2005. As of 2020, the field has maintained stable production for 16 years, with cumulative output reaching 2456 × 10⁴ tons. Enhanced recovery rates are projected to exceed 26% [98].

The SACROC reservoir [99] has an average depth of 2070 m, average porosity of 7.6%, and average permeability of 19.4 mD. The reservoir consists of Permian Canyon and Cisco carbonate formations (Figure 5c), characterized by extremely complex geological conditions and high heterogeneity. The reservoir has a formation pressure of 21.4 MPa, a minimum miscible pressure of 15.9 MPa, an oil specific gravity of 39 API, a viscosity of 0.35 cP, and a formation temperature of 60 °C, classifying it as a miscible light oil reservoir (Reservoir parameters are shown in Figure 5b). However, even if miscible drive can be achieved, mitigating the impact of its vertical heterogeneity remains challenging. The Canyon interval exhibits significant permeability gradation, with the upper section developing secondary pores and karst cavities featuring permeability as high as 100 D. Conversely, the lower portion consists of a tight, continuous layer with permeability below 10 mD. This geological feature—the coexistence of high-conductivity channels and a tight matrix—created severe engineering bottlenecks during the field expansion and adjustment phase from 1996 to 2001. Injected CO₂ rapidly advanced through upper high-permeability channels, triggering severe ineffective circulation and gas-lock failures in electric submersible pumps of production wells. This also prevented effective penetration of low-permeability zones rich in reserves, causing rapid decline in block production.

To address the challenge of early gas channeling induced by reservoir heterogeneity, the operators of the SACROC project abandoned the traditional injection mode, gradually established and implemented a comprehensive profile control technology system comprising “3 reservoir-based measures” and “5 wellbore-based measures”. In terms of wellbore control, the project extensively adopted technologies such as dual/triple-string separate-layer injection, mechanical packers, and expandable liners, achieving forced separate-layer injection through physical isolation. For the more critical mobility control in deep reservoirs, gas-soluble surfactant alternating gas (SAG) and crosslinked polyacrylate gel technologies were introduced. Particularly, the SAG technology utilizes surfactants that generate foam with CO₂ as they penetrate deep into the formation, effectively plugging the high-permeability preferential channels in the Canyon formation. Field monitoring data confirmed that after the application of this technology, the CO₂ absorption profile underwent a fundamental reversal, CO₂ absorption shifted from a single high-permeability layer to uniform absorption across multiple layers. This successfully activated the long-untapped low-permeability intervals and significantly improved vertical sweep efficiency.

The journey of the SACROC project from “early gas breakthrough” to “precise control” holds significant implications for the development of CCUS-EOR in China. Although China’s primary reservoirs are predominantly Continental sedimentary formations (such as the Ordos and Songliao basins), differing in lithology from SACROC’s carbonate rocks, both face the core engineering challenge of “strong inter-layer heterogeneity and large permeability gradients.” Therefore, when advancing large-scale CO₂ enhanced oil recovery in China, the “3 + 5” system experience from SACROC should be adopted: On one hand, from the initial wellbore design stage, the construction of “layered injection capability” should be strengthened, reserving space for multiple tubing strings or intelligent injection control to avoid limitations imposed by the wellbore that could hinder subsequent fine-tuning. On the other hand, given that simple water-gas alternation (WAG) struggles to resolve severe cross-flow in fractures or high-permeability zones, there is an urgent need to develop next-generation flow control technologies resistant to high temperatures and salts. Key research should focus on intelligent foam or gel systems similar to SAG. This approach enables the dual objectives of significantly enhancing recovery rates and ensuring safe sequestration within highly heterogeneous reservoirs.

3.5. Scientific Advances in North American CCS-EOR Technology

Over the past few decades, the U.S. Department of Energy has been supporting the deployment of CCS technology. The U.S. Department of Energy has focused on the development of combined CO₂ enhanced oil recovery and storage technologies. Among the projects currently funded by the U.S. Department of Energy, the focus is on four technologies: mobility control, displacement profile improvement, monitoring optimization, and reservoir simulation, as shown in

Table 3. List of Projects Currently Funded by the U.S. Department of Energy (2001–2025).

Project	Funded Entity	Focused Technology	Web Link
Machine Learning-Based Completion Optimization for CO2 Injection Wells	University of North Dakota	Improving Displacement Profiles and Enhancing Monitoring	https://netl.doe.gov/node/9773 (accessed on 25 August 2025)
Chemical-Assisted CO2 Displacement	Battelle Memorial Institute	Fluidity Control, Enhanced Multiphase Flow	https://netl.doe.gov/node/9504 (accessed on 25 August 2025)
CO2 Enriched Gas Enhanced Recovery	University of North Dakota	Enhanced Multiphase Flow	https://netl.doe.gov/node/11785 (accessed on 25 August 2025)
Optimization of Oil-Water Transition Zone Development	University of Texas at Austin	Improving Displacement Profiles, Strengthening Monitoring, and Enhancing Reservoir Simulation	https://www.netl.doe.gov/node/1426 (accessed on 25 August 2025)
CO2 Viscosity Enhancers	University of Pittsburgh	Fluidity Control, Enhanced Displacement Profiles, and Improved Reservoir Modeling	https://netl.doe.gov/node/2635 (accessed on 25 August 2025)
Formation and Distribution of Oil-Water Transition Zones	University of Texas at Austin (PB)	Enhanced Reservoir Simulation	https://netl.doe.gov/node/2686 (accessed on 25 August 2025)
Next-Generation CO2 Flood Reservoir Simulator	University of Texas at Austin	Advanced Reservoir Simulation	https://netl.doe.gov/node/2717 (accessed on 25 August 2025)
CO2-EOR Reservoir Planning Software (COZView/COZSim)	NITEC	Advanced Reservoir Simulation	https://netl.doe.gov/node/2714 (accessed on 25 August 2025)
Nano-Foam Enhanced Oil Recovery	New Mexico Tech	Flow ability Control, Enhanced Displacement Profile	https://netl.doe.gov/node/2695 (accessed on 25 August 2025)
Aerosol Surfactant Foam	University of Texas at Austin	Flow Control, Enhanced Displacement Profiles, Enhanced Reservoir Simulation	https://netl.doe.gov/node/2699 (accessed on 25 August 2025)
SPI Gel	New Mexico Tech	Fluidity Control, Improved Displacement Profile	https://netl.doe.gov/node/3861 (accessed on 25 August 2025)
Water-Soluble Surfactant Foam	University of Texas at Austin	Flow Control, Improved Displacement Profile	https://netl.doe.gov/node/3945 (accessed on 25 August 2025)

.

This focus reflects the core challenges facing the commercial application of CCUS-EOR technology in the United States today. During CO₂ enhanced oil recovery, the significantly lower viscosity of CO₂ compared to crude oil causes the gas to undergo viscous fingering within the reservoir. This leads to premature breakthrough, limited displacement volume, and low recovery rates. In addition, because the density of CO₂ is lower than that of crude oil, under the action of gravity, CO₂ will channel to the structurally higher parts, resulting in uneven oil displacement and low displacement efficiency. The U.S. focus on flow control and displacement profile improvement technologies fundamentally enhances recovery rates, increases project profitability, and prevents CO₂ accumulation in localized high-permeability zones, thereby mitigating leakage risks. Simultaneously, significant investments in monitoring optimization and reservoir simulation technologies enable real-time tracking of CO₂ migration pathways within formations, optimize production strategies, and ensure long-term, safe, and effective CO₂ sequestration. This innovation in CCUS-EOR technology, driven by economic incentives while serving environmental protection, forms the critical foundation for the large-scale commercial application of U.S. CCUS-EOR technology.

4. Challenges and Prospects for China’s CCUS-EOR Technology Development

4.1. Current Progress of China’s CCUS-EOR Technology

Although China initiated CCUS-EOR technology early, industrialization has lagged due to constraints such as gas supply limitations, insufficient understanding of mechanisms and equipment challenges. The technology is currently transitioning from engineering demonstration to commercial application [100]. Supported by China’s national “dual carbon” goals and a series of related policies, CCUS has achieved significant progress in engineering practice, with a continuous increase in project numbers. From 2021 to July 2024, the number of projects grew from approximately 40 to about 120, as shown in Figure 6. Project scales have surpassed the million-ton level, and the scope has expanded beyond enhanced oil recovery to include high-emission industries such as power generation, steel, and cement.

Currently, carbon capture technologies are accelerating their integration into industrial processes. Some relatively mature carbon capture technologies have achieved significant improvements in energy efficiency, with their large-scale application expanding further. Major breakthroughs have been made in the research and development of emerging carbon capture technologies. In 2023, the world’s largest chemical looping combustion carbon capture demonstration facility was completed, with a thermal power of 4 megawatts. The chemical looping combustion technology employed offers low cost and low energy consumption, with operating costs only one-third of traditional capture technologies [101]. Additionally, CO₂ transportation technology is advancing toward larger scales and longer distances. The commissioning of a 100-kilometer CO₂ pipeline and the planned construction of a 400-kilometer pipeline have significantly propelled the scaled development of China’s entire CCUS industry chain. Regarding enhanced oil recovery (EOR) technologies, addressing the complex lithology, high heterogeneity, and thin reservoir characteristics of China’s Continental sedimentary reservoirs, extensive technical research and field trials have established an engineering system tailored to these reservoir features [102].

Figure 6. Growth of China’s CCUS Projects and Carbon Capture Capacity, 2021–2024 [103].

Figure 6. Growth of China’s CCUS Projects and Carbon Capture Capacity, 2021–2024 [103].

4.2. Comparative Analysis of Key Characteristics of CO₂-EOR in China and the United States

4.2.1. Comparison of Typical Project Parameters

Despite China’s significant progress in engineering demonstrations, substantial differences exist between its reservoirs and those in the United States in terms of geological endowment and development metrics when compared to mature commercial applications in the U.S.

Table 4. Key Parameter Comparison of Typical CO₂-EOR Projects in China and the United States [67,84].

Country	Typical Project	Permeability (mD)	Porosity (%)	Reservoir Depth (m)	Reservoir Temperature (°C)	Oil Viscosity (cP)	API Gravity (°)	Displacement Regime	Recovery Factor Increase (%)
USA	SACROC	19.0	9.2	2040	57	0.7	40	Miscible Flood	>15.0
	Wasson	3.0	9.41	1500	41	1.2	33	Miscible Flood	17.2
	Salt Creek	52	19.0	670	38	0.6	37	Miscible Flood	>15.0
China	Caoshe Oilfield	46	14.8	/	104	12.8	29.5	Miscible Flood	3.25
	Shengli Oilfield Block Ga89-1	4.7	12.5	2700–3100	126	1.59	60.2	Near-Miscible Flood	5.4
	Sulige Block Ma38	15.7	16	/	81	12.3	36.8	Immiscible Flood	1.14
	Zhangjia Oilfield Block Zhang1	5.0	17.0	3200	112	1.7	45.4	Miscible Flood	4.1

summarizes key parameters for typical CO₂-EOR projects in China and the U.S. regarding reservoir geology, fluid properties, and infrastructure.

Table 4 reveals significant differences in resource endowment and development stages between China and the United States in CO₂-EOR projects. These differences fundamentally determine the selection of technical pathways and the ultimate development outcomes.

Reservoir temperature and crude oil composition are key factors determining CO₂ displacement mechanisms. Most U.S. reservoirs fall within the thermodynamically favorable range of “low-to-medium temperatures (<60 °C) and light crude oils,” readily meeting minimum miscible pressure (MMP) conditions to achieve highly efficient miscible displacement. In contrast, Chinese projects (such as Caoshe Oilfield) commonly face complex conditions characterized by “high temperatures (>100 °C)” and “high viscosity (>10 cP)”. The high-temperature environment significantly elevates crude oil MMP, making it difficult to achieve miscible conditions. Statistics indicate that in China’s Continental reservoirs, reservoirs with miscible pressures exceeding 25 MPa account for as high as 82.6% [104]. If China were to strictly adopt the U.S. selection criteria, only a small fraction of Chinese reservoirs would qualify as potential “miscible drive” reservoirs. Therefore, China primarily screens potential reservoirs for miscible drive implementation based on crude oil relative density, depth, and crude oil viscosity [105].

The Permian Basin in the United States is predominantly marine sedimentary, featuring good reservoir connectivity and relatively uniform permeability distribution. In contrast, China’s typical demonstration projects, influenced by Continental sedimentary environments, exhibit “dual-low” characteristics (low porosity and low permeability) alongside strong heterogeneity. The dense reservoir properties not only cause significant increases in injection pressure, limiting injection capacity, but also readily induce gas migration along high-permeability pathways. This severely hampers improvements in macro-scale sweep efficiency. Additionally, the crude oil contains high levels of asphaltene and gum, resulting in high viscosity. The fluidity ratio between CO₂ and crude oil is far greater than 1, making viscous fingering highly likely and leading to low sweep efficiency.

To address these parameter differences, one approach involves developing chemical agents and flow control technologies that reduce MMP, thereby adapting to such challenging reservoir conditions. Another strategy involves modifying injection and production methods to suppress gas entrainment. Given the high minimum miscibility pressure in most Chinese reservoirs, the pursuit of “full miscibility” should be de-emphasized, with a focus instead on developing a “near-miscible flooding” technology system. Given the pronounced heterogeneity of Chinese reservoirs, large-scale CO₂ continuous injection—common in the United States—is impractical. Consequently, WAG technology and its modified forms (e.g., surfactant-assisted WAG) are better suited for most heterogeneous sandstone reservoirs in China to enhance profile mobilization. Examples include the WAG applications in Caoshe and Yaoyingtai oilfields. Furthermore, considering that some Chinese oilfields (e.g., Changqing and certain Xinjiang blocks) are in the early stages of pipeline network development and feature fragmented blocks, CO₂ flooding offers greater economic viability and flexibility during initial evaluation phases. It can serve as a transitional approach toward large-scale enhanced oil recovery.

4.2.2. Infrastructure and Economic Viability Comparison

China’s CCUS-EOR holds immense potential. From 2018 to 2021, China’s average proven geological oil reserves stood at 13.3 × 10⁸ tons per annum, while its theoretical storage capacity ranges from 1.21 to 4.13 trillion tons. Additionally, China accounts for approximately 30% of global carbon emissions, presenting substantial reduction demands. To achieve the maximum annual emission reduction target of 654 million tons of CO₂, over 17,000 km of CO₂ transport pipelines would be required. To further reach the maximum annual reduction of 1.536 billion tons of CO₂, an estimated 26,000 km of transport pipelines would need to be constructed [106]. This indicates that China must indeed invest heavily in constructing thousands of kilometers of pipeline networks, similar to the United States in the 1980s, while simultaneously enhancing project capture capabilities (as shown in Figure 7a,b).

Economically, unlike the United States with abundant low-cost natural CO₂, China primarily relies on low-concentration industrial sources such as coal-fired power plants. Currently, the average capture cost in China’s thermal power sector ranges from 300 to 450 yuan per ton (approximately $40 to $60 per ton), and installing capture equipment increases power generation costs by about 60%. Spatial mismatch leads to high transportation costs: over 80% of China’s carbon sources are concentrated in the eastern coastal regions, while 90% of its storage potential (oil fields/saline aquifers) lies in the northwest. Currently, point-to-point tanker truck transportation is costly (approximately 0.5–0.6 yuan/(t·km)), keeping overall process costs elevated. Only by constructing regional pipeline networks, such as the “Ningxia-Changqing” or “Xinjiang” routes, can transportation costs be reduced to the pipeline-transportation level of 0.15–0.20 yuan/(t·km) [107].

Furthermore, constrained by the geological characteristics of Continental reservoirs—low porosity and low permeability—China struggles to replicate the high-profit model of single-well high productivity seen in the Permian Basin in the United States. Currently, the net emission reduction costs for China’s CCUS projects generally range between 300–700 yuan/ton. Only in a few demonstration projects, such as the Jilin Oilfield, has a critical break-even carbon price of approximately 236 yuan/t been achieved through full-industry-chain optimization. However, the logic driving this high-cost investment differs from that in the United States. While U.S. CCUS development is primarily driven by commercial profits from EOR, China’s development is dual-driven by the national “dual carbon” strategy and energy security. Although initial implementation relies on substantial infrastructure investment, capture and transportation costs are projected to decline significantly by 2060 as economies of scale take effect (as shown in Figure 7c). Therefore, even if single-well production and economic returns cannot match U.S. levels in the short term, cultivating the industrial chain and sharing infrastructure costs through EOR projects remains an essential pathway for China to achieve its carbon neutrality goals.

4.2.3. Policy Incentive Mechanisms and Oil Price Sensitivity Analysis

The fundamental difference in the commercial logic of CCUS-EOR between China and the United States stems from how policy tool combinations reshape project economics. Based on the latest quantitative research on international policy frameworks and economic assessments of typical projects, the underlying mechanisms of this divergence can be revealed. Currently, global CCUS policy frameworks are evolving toward prioritizing economic incentives. Xie Xiaoyu et al. (2025) [111] conducted a panel regression analysis using global data from 1970 to 2024, demonstrating that among various policy instruments, economic incentive policies exert the most significant effect on project implementation. This impact far exceeds that of legislative regulation and national strategies. The United States has established an incentive system centered on the “45Q tax credit,” with the latest amendment raising EOR sequestration subsidies to $60/t and geological sequestration to $85/t. Canada has legislated an Investment Tax Credit (ITC), offering up to 60% tax credits for DAC projects and 50% for the CCUS capture phase. In contrast, China’s current policy framework primarily consists of national strategy documents (plans, roadmaps). Although multiple plans have been issued under the “1 + N” policy system, no comprehensive, universal fiscal and tax incentive policies covering the entire process have been introduced. The absence of economic incentives results in insufficient direct driving force for market entities.

The lack of economic incentives directly resulted in Chinese projects being extremely sensitive to oil price fluctuations. Yang Junfeng et al. (2025) [108] used an economic evaluation model to calculate the relationship between different wellhead carbon prices and break-even oil prices (as shown in Figure 7d). When the wellhead carbon price (including capture and transportation costs) is approximately 450 yuan/ton, the marginal break-even oil price for CCUS-EOR projects reaches as high as $62.68/barrel, rendering them unsustainable under normal oil price conditions. However, under a scenario introducing subsidies simulating the intensity of the U.S. 45Q program (reducing the wellhead carbon price to 0 yuan/ton), the project’s marginal oil price can be significantly lowered to $38.93/barrel. Relying solely on national strategies is insufficient to drive large-scale CCUS commercialization. A hybrid incentive mechanism combining “financial subsidies and tax credits” is key to overcoming cost barriers.

4.3. Challenges Faced

Despite significant progress in China’s CCUS-EOR technology, numerous challenges remain for achieving large-scale commercial application.

A stable and affordable CO₂ gas supply is critical for advancing CCUS-EOR technology. Early U.S. efforts relied on CO₂ from natural gas reservoirs to sustain large-scale CO₂ enhanced oil recovery projects. However, natural CO₂ struggles to meet emission reduction targets, and its scarcity has become increasingly evident as reserves are depleted. Consequently, the U.S. has progressively increased its reliance on industrial CO₂. Compared to the high-concentration industrial CO₂ sources in the U.S., CO₂ emissions from China’s power plants, steel mills, and cement factories generally have lower concentrations and contain more impurities like sulfur and nitrogen oxides. Currently, high-concentration CO₂ capture technology is relatively mature and cost-effective, but low-concentration CO₂ capture technology is still in its developmental stage, with higher costs and energy consumption. Some emerging capture technologies can achieve negative emissions, but their high costs constrain commercial application. There is an urgent need to coordinate technological innovation, large-scale demonstration projects, and business model innovation to reduce costs and transition from policy-driven to market-driven implementation.

The lagging transportation infrastructure and spatial mismatch pose another challenge for CCUS-EOR technology. Currently, most CCUS projects still rely primarily on road tanker trucks for transportation, resulting in low efficiency and high costs. China’s carbon sources mainly originate from high-energy-consuming factories in the eastern coastal regions, while CO₂ sequestration reservoirs are concentrated in Northeast, Northwest, and Southwest regions. This spatial mismatch between sources and sinks significantly increases road tanker transportation costs, undermining project economics. The United States began large-scale construction of CO₂ pipeline infrastructure in the 1980s, now operating over 50 independent CO₂ transport pipelines with a combined network exceeding 7200 km. To meet global carbon emission targets, North America’s pipeline network is projected to reach 43,000 km by 2025 [106]. In contrast, China’s first CO₂ pipeline capable of transporting over 100 km only commenced operations in 2023, with pipeline network development still in its infancy. This has become a critical bottleneck constraining the development of the entire CCUS industry chain. Therefore, establishing a cross-regional CCUS pipeline network represents a major challenge for China today.

China’s reservoirs are predominantly Continental sedimentary formations characterized by strong heterogeneity, low permeability, and low light hydrocarbon content in crude oil. Existing enhanced oil recovery (EOR) technologies face adaptability and compatibility issues in such reservoirs, struggling to achieve ideal miscible effects and encountering technical hurdles in enhancing recovery rates. Furthermore, the high cost of low-concentration CO₂ purification technology, coupled with insufficient field-testing of low-concentration mixed-gas EOR and inadequate research on the migration patterns of multi-component gases within reservoirs, hinders the efficient utilization of low-concentration gas sources. The pronounced heterogeneity of Continental sedimentary reservoirs exacerbates issues such as CO₂ gas migration, limited flooding volume, and low flooding efficiency, resulting in production increases that fall short of project expectations.

Methods for evaluating storage potential and long-term safety monitoring systems require further refinement. Although China possesses extensive oil and gas reservoirs and saline aquifers that provide favorable storage sites for CO₂, geological storage potential assessment methods have primarily been developed by adapting models established in North America to the specific conditions of domestic oilfields [112,113,114,115]. Most evaluation methods are constructed based on material balance theory and volume balance theory after considering structural traps, residual traps, and dissolution traps. There is a lack of more precise, efficient, and standardized methods for evaluating storage potential. Furthermore, there is a shortage of extensive reservoir data and understanding of coefficients in relevant storage capacity calculation formulas [116], making it difficult to meet the precise assessment requirements for complex reservoirs. The safety and monitoring system (MRV) for long-term storage has not undergone large-scale validation. There is a lack of long-term liability attribution, cross-regional regulatory frameworks, and standardized systems, necessitating breakthroughs in technological demonstration, legal regulations, and institutional innovation.

Compared to North America, which possesses extensive CCUS application experience, China’s relevant policies require refinement and business models remain underdeveloped. Due to high costs and low returns, CCUS projects struggle to generate economic benefits, with some projects yet to commence formal operations [117]. Currently, the primary revenue source for domestic CCUS projects is enhanced oil recovery (EOR) using CO₂. However, this revenue is influenced by oil prices and reservoir geological conditions. For reservoirs with complex geology, CO₂-EOR struggles to achieve significant production increases. Volatile oil prices create substantial uncertainty in the profitability of CCUS-EOR projects, posing major challenges to scaling up the technology through market mechanisms alone.

4.4. Outlook

China’s CCUS-EOR technology still lags behind international standards. Drawing on global technical expertise while adapting to domestic conditions, and propelled by the “dual carbon” policy, CCUS-EOR is poised to enter a new phase of rapid, large-scale development. To address these challenges, it is imperative not to simply replicate the North American model. Instead, there is an urgent need to establish a comprehensive theoretical and technical standards system for the entire industrial chain that is tailored to China’s context, encompassing technological innovation, infrastructure development, and policy incentives.

Focusing on technological innovations such as low-cost capture and mobility control is the core driver. Future efforts must accelerate the transition of CO₂ capture technology from high-concentration to medium- and low-concentration applications, focusing on developing efficient and low-cost separation methods while overcoming bottlenecks in large-scale production to meet the commercialization demands of CCUS-EOR technology [100,118]. Oil and gas companies must also continuously enhance industrial CO₂ supply, strengthen collaboration with high-carbon-emission enterprises such as refining, coal-fired power generation, and coal chemical industries to ensure stable and reliable gas sources [119]. According to break-even analysis, subsequent efforts should focus on reducing the CO₂ capture cost of low-concentration industrial flue gas to approximately 200 yuan/ton to meet commercial application requirements. Regarding oil displacement technologies, given the characteristics of China’s continental sedimentary reservoirs—high temperature, high crude oil viscosity, and strong reservoir heterogeneity—achieving miscible displacement poses substantial challenges. Thus, priority should be given to near-miscible displacement. Additionally, innovative mobility control technologies must be developed to expand the swept volume under conditions where miscible displacement is unfeasible. Concurrently, key supporting technologies such as well spacing optimization, water-alternating-gas (WAG) injection, and corrosion-inhibited injection-production processes should be refined.

Accelerating industrial clustering and infrastructure sharing is key to reducing transportation costs. Although multiple pipelines spanning hundreds of kilometers are currently under construction, China will ultimately need to build a dedicated CO₂ pipeline network exceeding 17,000 km in total length to support the annual emission reduction demand of 654 million tons. It is recommended to prioritize establishing industrial clusters in regions with high source-sink matching potential, such as Xinjiang and Ordos. By sharing infrastructure, transportation costs can be reduced from the current road transport level to 0.15–0.20 yuan/(t·km). Concurrently, establish parallel evaluation methods for the storage capacity of oil and gas reservoirs and deep saline aquifers at the same stratum level. Utilize multi-field coupled numerical simulation to optimize storage solutions and develop dynamic monitoring technologies to mitigate leakage risks.

China’s CO₂ emissions far exceed its sequestration capacity, indicating immense potential for CCUS development. However, commercial application remains constrained by high costs. Government policy incentives are crucial, drawing inspiration from the U.S. Section 45Q tax credit policy to transition from “investment subsidies” to “operational subsidies.” Differentiated subsidy standards should be established for CCUS-EOR projects to bridge the gap between current high capture costs and oilfield affordability. Concurrently, carbon pricing mechanisms and CCUS regulations must be refined—particularly by establishing clear long-term liability transfer and risk response protocols. Expanding industry coverage, introducing diverse trading entities, and discovering effective carbon prices will incentivize societal-wide emissions reduction. Active international cooperation should leverage mature foreign technologies while mitigating potential risks.

In the future, with strengthened policy support, accelerated technological innovation, and deepened industrial coordination, China will continue to build a complete and efficient CCUS industrial chain, providing crucial support for achieving the dual carbon goals.

5. Conclusions

(1) Carbon capture, utilization, and storage (CCUS) is an indispensable technology for supporting global carbon neutrality goals. Among its applications, CCUS-enhanced oil recovery (EOR) has emerged as a key pathway for large-scale deployment due to its dual potential for emissions reduction and economic viability.

(2) Quantitative analysis of 148 representative projects indicates that the commercial success of North American CCUS-EOR relies on a specific resource combination: natural/high-purity gas sources + mature pipeline networks + easily miscible marine reservoirs. Its technological evolution has shifted from early-stage pure oil displacement to focusing on flow control, displacement profile enhancement, and full-lifecycle monitoring—aiming to resolve the synergy between long-term sequestration and efficient oil recovery. Comparative studies reveal fundamental differences in engineering boundary conditions between China and the United States: North American CO₂-based displacement primarily targets mixed-phase drive in medium-to-low temperature, light-grade reservoirs, whereas China’s Continental reservoirs commonly face challenges of “strong heterogeneity, high viscosity, high mixed-phase pressure,” and spatial mismatch between sources and sinks.

(3) Given these differences, China’s CCUS-EOR development cannot simply replicate the U.S. model. Moving forward, China should establish a differentiated full-industry-chain system tailored to its Continental sedimentary characteristics. To address the challenge of achieving miscibility in continental sedimentary reservoirs, research should focus on near-miscible/immiscible flooding and Mobility Control Technology. For low-concentration gas sources, breakthroughs in low-cost capture materials are essential. Furthermore, drawing lessons from the Permian Basin experience, infrastructure sharing and industrial cluster development should be prioritized in regions with high source-sink compatibility (e.g., Xinjiang, Ordos Basin) to reduce transportation costs. Referencing the U.S. 45Q experience while adapting to China’s national conditions, research should explore establishing incentive mechanisms transitioning from “investment subsidies” to “operational subsidies,” and clarify long-term storage responsibility boundaries to facilitate the leap from engineering demonstration to commercial application.