A Critical Review on the Opportunities and Challenges of Offshore Carbon Capture, Utilization, and Storage

Abstract

Offshore Carbon Capture, Utilization, and Storage (CCUS) is emerging as a critical strategy for achieving net-zero emissions, offering significant storage potential in depleted hydrocarbon reservoirs and deep saline aquifers while leveraging existing offshore infrastructure. This review summarizes recent advances in capture, transport, utilization, and storage technologies in the offshore industry. Case studies including Sleipner, Gorgon, and Northern Lights illustrate both the technical feasibility and the operational, economic, and regulatory challenges associated with large-scale deployment. While post-combustion capture and pipeline transport remain the most technologically mature approaches, significant uncertainties continue to exist regarding the logistics of marine transportation, reservoir integrity, and the robustness of monitoring frameworks. Policy and regulatory complexity, coupled with high capital costs and public acceptance issues, continue to constrain commercial viability. This review highlights that offshore CCUS holds significant promise but requires advances in monitoring technologies, cost reduction strategies, and harmonized international governance. Future research should focus on integrating CCUS with hydrogen production and renewable energy systems to accelerate large-scale deployment.

1. Introduction

The rapid growth of industrialization and persistent dependence on fossil fuels have resulted in a substantial rise in the atmospheric carbon dioxide (CO₂) concentration, which represents the primary anthropogenic driver of global warming and climate change [1,2,3,4,5,6,7]. To address these critical stressors, international efforts have resulted in key agreements such as the Paris Agreement, adopted in 2015 at the 21st Conference of the Parties (COP21) [8,9,10]. The objectives of this agreement is to limit the global average temperature rise to well below 2 °C above pre-industrial levels, with ambitious efforts aimed at restricting it to 1.5 °C by the end of the century [2,5,6,8,11]. Furthermore, the Intergovernmental Panel on Climate Change (IPCC) continually assesses climate change and its impacts, underscoring the vital necessity of substantial CO₂ emission reductions to meet these global climate targets [5,8,9,12,13]. A recent IPCC press release indicated that limiting warming to 1.5 °C requires global greenhouse gas emissions to peak in 2025 and be reduced by 43% by 2030, ultimately achieving net-zero emissions, a state where the amount of greenhouse gas entering the atmosphere is balanced by the amount removed, which is considered indispensable for mitigating climate change and securing a sustainable future [14].

Industry activities such as cement, steel, chemicals, and power generation are considered hard-to-abate sectors due to the substantial and often inherent CO₂ emissions generated by their processes [10,15,16]. These sectors, including cement and steel production, account for approximately 15% of global industrial CO₂ emissions, facing unique challenges due to CO₂ being an inherent byproduct or the limited availability of scalable low-carbon substitutes for their operations [17,18]. In addition, aviation and shipping, which account for 5% of CO₂ emissions, are also recognized as hard-to-abate sources, with dispersed and mobile emissions that are difficult to address with conventional capture technologies [19]. However, activities involving these essentials are difficult to reduce, thus requiring a parallel solution to reduce emissions.

In recent decades, Carbon Capture, Utilization, and Storage (CCUS) has become an essential tool for reducing carbon dioxide emissions by capturing CO₂ directly from hard-to-abate sectors such as power plants, waste-to-energy facilities, and industrial facilities before it enters the atmosphere [1,2,20]. Functioning as a transitional and bridging technology, CCUS enables existing fossil fuel industries to decarbonize, minimizing CO₂ release and controlling climate change [21]. Many scholars have directed their efforts toward CCUS to limit anthropogenic warming to well below 2 °C and achieve net-zero emissions targets by 2050 [1,5,22,23,24,25,26]. Meanwhile, the International Energy Agency (IEA) projects that CCUS will contribute approximately 15% of the total emission reductions needed to keep global temperature rise below 2 °C, requiring a ten-fold increase in capacity by 2050 to meet net-zero targets [22,27].

Within the broader landscape, offshore CCUS presents distinct opportunities and challenges compared to onshore applications. The offshore environment indeed offers vast geological storage potential for CCUS, with advantages over onshore approaches [5,28]. These factors can make offshore CCUS potentially safer and more cost-effective in certain contexts. However, offshore carbon storage technologies face significant technical, economic, and regulatory challenges, including high-pressure operation, geological injection complexities, salt precipitation, marine environmental impacts, and specialized deployment requirements that must be addressed for widespread adoption.

Since the first CO₂ sequestration project in the subseabed North Sea in 1996, offshore CCUS has become more popular both technically and economically. In fact, the Sleipner project has shown its effectiveness in the CO₂ storage of 20 million tons of CO₂ beneath the seabed. This results in compliance with stringent CO₂ regulations and avoids hefty emissions taxes for the operator [29,30,31,32]. Similarly, the Gordon project aims to capture 3.3 to 4 million tons of CO₂ per year from extracted natural gas. However, the project has faced an issue with the reservoir pressure and needs a supportive system to control the pressure. This effort enhances the operation of the underground sequestration. Sleipner and Gorgon are pioneering CCUS successes that provide a global benchmark for plume behavior, trapping mechanisms (structural, residual, dissolution), and monitoring methods [33,34]. However, scaling up offshore CCUS is not straightforward; it requires robust engineering, contingency planning, and transparent performance monitoring [30].

This study evaluates the potential of CCUS in offshore areas, examining the opportunities and challenges across the complete CCUS processes. The review systematically analyzes technical, economic, and environmental dimensions of offshore CCUS deployment, with particular emphasis on high-pressure operation, separation technologies, and deep borehole injection challenges throughout the offshore carbon lifecycle.

2. Principle of Carbon Life Cycle and CCUS

2.1. Life Cycle of Carbon

The life cycle of carbon (LCA) encompasses the continuous movement and transformation of carbon through various processes, including the atmosphere, oceans, land (biosphere and geosphere), and anthropogenic emissions (Figure 1) [35]. Carbon emissions, mostly in the form of CO₂, originate from diverse industrial sectors with varying intensities. In China, the most important steel producer in the world, the steel industry generates approximately 2.33 tons of CO₂ per ton of crude steel, with fossil fuel combustion contributing 68% of total emissions [35]. Cement manufacturing releases 8% of global CO₂ emissions through both fuel burning and raw material decarbonation during clinker production [17]. On the other hand, the chemical industry contributes 40% of global anthropogenic CO₂ emissions [36,37,38]. Other human activities, such as transportation, deforestation, agricultural practices, and waste management, are releasing massive amounts of CO₂ into the atmosphere.

According to Jones and colleagues (2023), anthropogenic emissions of carbon dioxide (CO₂), methane (CH₄), and nitrous oxide (N₂O) are the most important greenhouse gases (GHGs). It is reported that the global mean surface temperature increased by 0.07 °C in the period of 1922–2023, and the same calculation for methane and nitrous oxide yields values of 0.032 and 0.026 °C, respectively (Figure 2). Rapid urbanization and industrialization have resulted in a significant increase in GHG emissions worldwide [39]. An average of 99.3 Mt CO₂ was emitted every day globally, with the largest contributions from India, Russia, and China [40]. In 2024, the power industry contributed 38.7% of the total CO₂ emissions, followed by industry at 28.5%, ground transportation at 18.7%, residential at 9.4%, shipping at 1.9%, and aviation at 2.8%. Human activities such as urbanization, agriculture, and industry are the leading causes of climatic changes all over the world. Many researchers indicate that CO₂ emissions have a close relationship with the global temperature rise [41]. Under current emission trajectories, various policies and regulations have been implemented by many countries to avoid overshooting the global warming limit [42].

Natural forms of carbon sequestration—like photosynthesis in plants and absorption by oceans—maintained a near balance of CO₂ in the atmosphere [43]. However, human activities have overwhelmed these natural processes, leading to a buildup of CO₂ in the atmosphere [43]. Previous studies revealed that the rate of natural CO₂ absorption by the terrestrial biosphere, such as forests and other vegetation, peaked in 2008 and has been decreasing since then, exhibiting a declining trend [44]. This indicates that although these natural carbon sinks continue to play an important role, their effectiveness in removing atmospheric CO₂ has diminished over time.

Figure 1. Carbon life cycle in the natural environment. In the environment, carbon moves through Earth’s atmosphere, land, oceans, and human activities. The carbon cycle maintains a balance between carbon sources (volcanoes, fossil fuel burning, respiration) and sinks (photosynthesis, ocean absorption). Human activities, however, are breaking this balance by releasing more CO₂ than natural processes can absorb—driving climate change [45].

Figure 1. Carbon life cycle in the natural environment. In the environment, carbon moves through Earth’s atmosphere, land, oceans, and human activities. The carbon cycle maintains a balance between carbon sources (volcanoes, fossil fuel burning, respiration) and sinks (photosynthesis, ocean absorption). Human activities, however, are breaking this balance by releasing more CO₂ than natural processes can absorb—driving climate change [45].

Figure 2. Summary of greenhouse gas contributors and average temperature change in 1992–2023. In this figure, the grey square-dotted line indicates the global temperature increase due to methane (CH₄) emission, whereas the red circle-dotted line and blue triangle-dotted line indicate the temperature variations due to carbon dioxide (CO₂) and nitric oxide (NO₂), respectively [46].

Figure 2. Summary of greenhouse gas contributors and average temperature change in 1992–2023. In this figure, the grey square-dotted line indicates the global temperature increase due to methane (CH₄) emission, whereas the red circle-dotted line and blue triangle-dotted line indicate the temperature variations due to carbon dioxide (CO₂) and nitric oxide (NO₂), respectively [46].

2.2. Overview and Role of CCUS in Net-Zero Pathways

Nowadays, climate change has become a pressing global challenge that demands stronger policy commitments and coordinated actions from governments worldwide. Carbon Capture, Utilization, and Storage (CCUS) is widely recognized as an indispensable and critical technology for achieving global net-zero emissions and mitigating the adverse impacts of climate change [47]. CCUS, a vital component of the low-carbon economy, plays a multifaceted role in global decarbonization pathways. The core function of CCUS is to capture CO₂ from large-scale sources, such as industrial facilities and power plants, and then either utilize it for productive purposes or sequester it permanently to prevent its release into the atmosphere [25]. This process is composed of four interdependent components: capture, transport, utilization, and storage (Figure 3) [16]. For instance, CCUS is currently the only technically viable solution for achieving near-zero emissions [48].

CCUS can facilitate the production of low-emission hydrogen and, when combined with bioenergy or Direct Air Capture (DAC), can achieve “negative emissions” by actively removing CO₂ from the atmosphere [49,50,51]. These capabilities allow for the continued operation of existing industrial assets while also balancing out residual emissions from other sectors like heavy transport. However, the widespread deployment of CCUS has faced challenges, including high initial costs, a lack of sufficient policy incentives, and regulatory hurdles [2,5,8,16,24]. In addition, public perception and social acceptance also remain significant barriers due to concerns about the perceived risks of CO₂ leakage and the potential impact on local communities [13,52,53]. To overcome these challenges, the emergence of CCUS hubs and clusters with shared transport and storage infrastructure (e.g., pipelines and port facilities) is a promising approach for reducing unit costs and commercial risk through economies of scale [52,54].

3. Technical Overview of Offshore CCUS

3.1. Carbon Capture Technologies

CO₂ capture is the collection of emission gases from industrial activities, which is a significant step for reducing climate change. Currently, carbon capture technology has three areas of study, which are pre-combustion, post-combustion, and oxycombustion capture (Figure 4). Post-combustion capture is the traditional method, involving the collection of carbon in flue gases after a combustion process [13,15,22,53]. The flue gases may include a mixture of nitrogen, sulfur dioxide, nitrogen oxides, and carbon dioxide. Therefore, a separation stage is necessary to separate the CO₂ from the gas mixture. In an industry plant, flue gases are fed into a separation unit or absorbed by monoethanolamine (MEA) [2,55]. In addition, a membrane is also used as a supportive technique to reduce capital costs associated with post-combustion technology. To meet low-energy requirements with a low carbon footprint and operating cost, membrane technology is straightforward to adapt and scale up with an existing power plant [26].

Pre-combustion carbon capture is a process that removes CO₂ from a fuel source before it is burned, typically from a syngas stream produced during gasification [53]. In general, pre-combustion carbon capture is the gasification of fossil or biomass fuels to form syngas, which contains mainly hydrogen, carbon monoxide, and carbon dioxide. The most common pre-combustion methods are the Selexol process, Purisol process, and Morphysorb process, which are widely used in industry. It is reported that the efficiency values of pre-combustion carbon capture in power plants are 37% and 43.7% for the Integrated Gasification Combined Cycle (IGCC) and the Integrated Reforming Combined Cycle (IRCC), respectively [56].

Oxyfuel combustion (OFC) is a method used to capture CO₂ from power plants [57]. This process involves the burning of fuel with oxygen to run the boiler or generator in the power plant [58]. A high concentration of CO₂ is captured from the flue gas mixture after dehydration [58,59]. OFC enhances the CO₂ removal from flue gas, reduces the NOx by burning pure oxygen, and captures the CO₂ stream at a high purity that is suitable for pipeline transport or enhanced oil recovery (EOR) without extensive purification [57,60,61]. However, provision of pure oxygen for burning requires a complicated separation process that may result in high capital and operational costs [62,63].

3.2. Carbon Transportation Technologies

The successful implementation of offshore CCUS hinges on the development of a robust and efficient transportation network. Moving captured CO₂ from industrial sources to subseabed storage sites requires technologies that are not only effective but also environmentally sound and economically viable. The primary methods for offshore carbon transport are pipelines and marine carriers (ships), which are increasingly integrated into hybrid systems to form flexible and large-scale infrastructure [64]. The selection between pipelines and ships is commonly determined by factors such as transport volume, distance, project maturity, and required flexibility.

Pipelines represent the most mature transport technology, ideally suited for large, continuous volumes of CO₂ over shorter distances [65,66]. For over 50 years of commercial experience, pipeline technology has been used to transport 110 million tons of carbon dioxide annually over a distance of 9500 km [64]. For offshore applications, CO₂ is typically transported as a high-pressure supercritical fluid, with a unique combination of liquid-like density and gas-like viscosity making it ideal for transport [66,67]. However, this state is highly sensitive. As the fluid moves through a subsea pipeline, heat loss can cause it to transition into a liquid phase. To prevent problematic two-phase flow (liquid and gas), pipelines are engineered to operate consistently above the critical pressure of CO₂, ensuring a dense phase with a density typically between 800 and 1000 kg/m³ [68].

The presence of impurities is a critical challenge that significantly complicates phase management. Non-condensable gases such as nitrogen (N₂), oxygen (O₂), and methane (CH₄) raise the critical temperature and pressure of the CO₂ stream. Even minor concentrations of N₂ can substantially increase the required compression power, requiring higher operating pressures to maintain a single, dense phase, which in turn increases energy consumption and compression costs [68]. Beyond altering the physical properties of fluid, impurities in the CO₂ stream introduce severe material constraints and risks. The presence of water (H₂O) is particularly problematic; when combined with hydrogen sulfide (H₂S) or sulfur oxides (SO_x), it forms highly corrosive acids that degrade pipeline walls, necessitating the use of expensive, higher-grade steel to ensure long-term integrity [69,70,71]. Additionally, residual water can form solid hydrates in the low temperatures characteristic of offshore pipelines, creating blockages that require costly system shutdowns to resolve [72,73]. A major hurdle for the industry is the lack of universal CO₂ quality standards. Specifications are currently determined on a project-by-project basis, creating a trade-off between the high cost of purification at the source and the high cost of corrosion-resistant pipeline materials. This is particularly problematic for hub-based infrastructures, where mixing CO₂ streams from different sources can trigger unpredictable chemical reactions. While projects such as Norway’s Northern Lights have adopted very strict specifications, this approach places a heavy financial burden on industrial emitters [73].

In addition, ensuring the structural integrity of offshore pipelines is paramount, as they represent the most frequent potential source of leaks in a CCUS system. While minor leaks may have a limited impact radius (<100 m), a total pipeline failure could affect an area with a radius of up to 30 km [67]. To mitigate these risks, pipeline design involves rigorous validation against multiple failure criteria, including pressure containment, collapse, and local buckling. Key engineering considerations for fracture control and pipeline integrity are presented in

Table 1. Key engineering considerations for offshore CO₂ pipeline transportation.

Categories	Technical Specifications and Literature-Based Insights
Risk of leaks	In regional offshore CCS systems (~20 Mtpa), the most frequent events are CO2 pipeline leaks, expected every ~2–10 years across the industry; rarer but higher-impact “total failures” are estimated at ~1–10 years [67]. These frequencies underpin monitoring design and emergency planning. The consequence of a CO2 leak in the marine environment depends on pipeline pressure and release rate. CO2 leaks may lead to ocean acidification and a potential asphyxiation hazard in the marine environment. In addition, the addition of CO2 in seawater results in a pH decrease and detrimental effects on ocean life [74,75,76,77].
Design and validation	Offshore CO2 flowlines/risers are validated for pressure containment, collapse, local/global buckling, and fatigue following submarine pipeline practice with corrosion allowance and impurity-dependent material selection [78]. Offshore codes and standards are used for CO2 subsurface sequestration [79].
Operating conditions (phase and pressure–temperature window)	Dense-phase operation is preferred to avoid two-phase transients. Typical design/operation windows reported in the literature are ≥80 bar at ~20 °C (minimum operating pressure) and often 100–150 bar for trunk lines; internal temperatures are commonly in the range of 4 °C to 44 °C, or specifically 15 °C to 30 °C [68,80,81,82,83]. Impurities tend to raise the critical pressure, narrowing the single-phase envelope; this must be reflected in compression/dehydration and set points.
Dynamic response (hydro-environmental and flow-induced)	Dynamic analyses address current/wave/vessel-motion loading and flow-induced effects (slugging, Vortex-Induced Vibrations), tracking effective tension, bending moments, von Mises stress, and local buckling [78,84,85]. Recent subsea CO2 flowline studies demonstrate the need for coupled hydrodynamic–structural modeling to keep stress ranges within fatigue design curves [78].
Ancillary components (interfaces and fatigue control)	Bend stiffeners at hang-offs/I-tubes limit curvature to above the riser’s minimum bending radius and reduce cyclic strain accumulation; proper sizing materially improves the fatigue life of flexible/dynamic risers [85,86].
Phase stability and transient safety (blowdown/depressurization)	Rapid depressurization can cross the triple point (≈5.2 bar, −56.6 °C), forming dry ice and hydrates, sharply cooling the fluid and pipe wall; staged/blended blowdown strategies are therefore required [87]. Experiments and models show large temperature drops and potential solid CO2 mass fractions during decompression, reinforcing the need for Emergency Shutdown set points that maintain a margin with respect to the triple point and hydrate lines [64,88,89].

.

Marine carriers, or tankers, serve as a flexible transportation means in the CCUS chain, acting as an alternative solution for the long-distance transport of CO₂ [90]. This is advantageous for facilitating early project deployment where pipeline economics are prohibitive. Liquefied CO₂ vessels are mostly semi-refrigerated vessels, offering an optimal trade-off between managing pressure and temperature [90]. However, to meet the marine CCUS shipping demand, vessels with a capacity of up to 100,000 m³ are required, while existing LPG/ethylene vessels with a capacity of 8000–10,000 m³ are suitable for CO₂ transport [91]. In addition, the operational condition of the liquified CO₂ should be considered [90,92,93].

For large-scale operations, low-pressure conditions (e.g., 7 barg) are emerging as the preferred standard due to greater cost-effectiveness and operational feasibility compared to current commercial practices (normally 15 barg and −30 °C) [66,94]. Despite its advantages, shipping faces considerable challenges. Economically, it incurs higher operational costs than pipelines, and its intermittent delivery schedule necessitates costly interim storage tanks at both loading and unloading terminals [90]. The critical technical hurdle is that offshore unloading and direct injection remain an unproven concept, requiring complex onboard systems to pressurize the CO₂ to 5–40 MPa and heat it before injection, and this process is vulnerable to weather variations [95,96]. This process also introduces risks of material stress from thermal cycling and the formation of dry ice during depressurization [90]. Additional challenges include potential cargo loss from boil-off gas (representing a potential loss of 10% of the load) and persistent regulatory barriers; although a 2019 amendment to the London Protocol has eased restrictions on cross-border transport, the exclusion of shipping from financial incentive schemes like the EU ETS Directive continues to create uncertainty for project developers [90,97]. Overcoming these multifaceted technical, economic, and regulatory issues is essential for marine transport to fulfill its potential in enabling a global CCUS network.

To build a cost-effective and scalable offshore CCUS industry, a strategic shift is underway from simple point-to-point transport towards integrated hybrid systems (Figure 5). This approach combines the distinct advantages of pipelines and marine carriers to create a flexible, efficient, and resilient infrastructure capable of serving diverse industrial emitters [90,98]. A hybrid system leverages the strengths of each transport method: pipelines are ideal for high-volume, continuous flows over shorter distances, offering lower operational costs, while marine carriers (shipping) provide unparalleled flexibility for long-distance transport, smaller volume sources, or early project deployments where the high capital expenditure of a dedicated pipeline is not yet justified [90,99]. By integrating these methods, for example, using ships for long-haul distribution to a coastal hub that then feeds an offshore pipeline, the overall network gains significant operational and economic efficiency [64].

This integration is best exemplified by the “hub-and-spoke” model, where strategic nodes like industrial ports or offshore platforms act as central hubs. These hubs aggregate CO₂ from multiple, dispersed sources, enabling a shift from inefficient single-source-to-sink pairings to a highly efficient multi-source, multi-sink network [64]. The cornerstone of this model is shared infrastructure, which dramatically lowers the per-unit cost of transport through economies of scale and reduces the financial barrier for smaller emitters to join the CCUS value chain [68,90,100]. Furthermore, these hubs can often repurpose existing port facilities and pipeline corridors, further reducing initial investment risk and accelerating deployment [101]. Norway’s Northern Lights project is a world-leading blueprint for the integrated hub model [90,100]. The project uses custom-built ships to transport liquid CO₂ from industrial sources to a coastal terminal, which then feeds a single offshore pipeline for permanent subsea storage. Designed as a flexible, open-access infrastructure to catalyze a European CCUS market, Northern Lights has already secured the first-ever cross-border storage agreement with a facility in the Netherlands [64,90,100,101].

Besides advantages, offshore pipeline and shipping-based CO₂ transport face two main environmental challenges requiring innovative solutions. Pipeline systems present low-probability risks with leaks occurring approximately once every two years per 1000 km in well-engineered systems, but potential ocean acidification and hydrate formation require attention [67]. Maritime transport contributes 3% of global CO₂, 13% of sulfur oxides, and 15% of nitrogen oxides [90]. To address these challenges and comply with International Maritime Organization (IMO) targets for decarbonization [102], the industry is exploring several transformative solution pathways. Alternative fuel transitions from heavy fuel oil to lower-carbon options such as LNG, biofuels, hydrogen, and ammonia offer immediate emission reduction potential [90,103,104]. Among the most promising innovations are Subsea Shuttle Tankers, which are electric-powered autonomous underwater vehicles designed to transport liquid CO₂ from offshore facilities directly to marginal subsea fields for injection [105]. Additional approaches include onboard carbon capture systems using solvents or membranes to capture CO₂ from ship exhaust to comply with the Energy Efficiency Design Index regulations [103,104]. These integrated pathways represent a flexible shift toward sustainable offshore carbon transport, combining risk mitigation with operational decarbonization to support the broader deployment of offshore CCUS infrastructure.

3.3. Offshore Carbon Utilization Technologies

3.3.1. Enhanced Oil Recovery

Figure 6 illustrates the schematic of the enhanced oil recovery (EOR) process, which plays a vital role in the offshore oil industry. EOR is employed to increase the recovery factor of discovered oilfields, as conventional production methods typically extract only about 40% of the original oil in place [106]. Offshore CCUS strategies are inherently linked to EOR using carbon dioxide injection. This practice has emerged as one of the most commercially successful gas injection EOR methods globally, offering the dual benefit of increasing hydrocarbon recovery from mature reservoirs and providing a secure geological storage option for industrial emissions. This approach plays a significant role in increasing the lifespan of reservoirs used through both miscible and immiscible techniques [107,108,109].

The preference for CO₂ over other injection gases, such as nitrogen or hydrocarbon gases, is driven by both technical and environmental factors. On one hand, CO₂ typically has a lower minimum miscibility pressure, which simplifies the achievement of miscibility conditions necessary for highly effective oil displacement [110]. On the other hand, utilizing captured CO₂ from industrial sources for EOR provides a direct pathway for greenhouse gas sequestration, effectively mitigating emissions [111]. The effectiveness of CO₂ for EOR is underpinned by several key mechanisms, including oil swelling and viscosity reduction, which improve oil mobility; interfacial tension reduction or elimination under miscible conditions; and the extraction of light hydrocarbons, which further enhances oil flow. Additionally, CO₂ injection contributes to reservoir repressurization, alters rock wettability towards a more water-wet state, and can be driven by molecular diffusion in tight formations [112]. A variety of operational techniques have been developed to optimize CO₂ injection for different reservoir types. Table 2 summarizes the application, effectiveness, and operational limitations of each method.

Despite its advantages, the deployment of CO₂-EOR faces several challenges. These include the risk of early breakthroughs and low sweep efficiency, the potential for corrosion of wellbore components in the presence of water, and formation damage caused by complex rock–fluid interactions [113]. Economic viability can also be a challenge due to the cost of CO₂ and the complexity of modeling the processes. To address these issues, research has focused on enhancements to CO₂ injection, such as the use of additives/thickeners to improve mobility control, foams to decrease CO₂ mobility and expand the sweep volume, and glycol ether additives to further reduce interfacial tension [113,114,115]. These innovations aim to improve both the oil recovery factor and the efficiency of CO₂ utilization and storage.

Table 2. Common CO₂ injection techniques in EOR.

Technique	Application	Effectiveness	Limitations
Continuous CO2 Injection (Flooding)	- Widely applied in various reservoirs, especially low-permeability, ultralow-permeability, deep-water, and high-sulfur reservoirs [106,116]. - Successfully applied in heavy oil belts [116] - Effective for crude oil with an API gravity higher than 25 [110].	- Recovery of up to 90% original oil in place under miscible conditions [117]. - Increase recovery by 10–20% in low-permeability reservoirs [117,118].	- Early breakthrough, viscous fingering, and gravity override due to low CO2 viscosity/density and gravity effects [106,117,119]. - Poor sweep efficiency (~25%) and low space utilization [106,117].
CO2 Huff ‘n’ Puff (Cyclic Injection)	- Effective for unconventional reservoirs, particularly shale oil and tight oil reservoirs [110]. - Success in heavy oil and oilsands reservoirs [120]. - Successfully applied in conventional light oil reservoirs and several heavy oil cases, including mature oilfields [110,120,121].	- Oil recovery improvement of 30.4–46.5% [111]. - Generally yields a higher oil recovery factor (RF) compared to continuous CO2 flooding [111]. - Less sensitive to reservoir permeability and void gas viscous fingering and early breakthrough [111]. - Contributes significantly to CO2 geological sequestration, with 40–50% of injected CO2 being trapped in the porous medium [120].	- Field–lab gap from reservoir heterogeneity [110]. - Requires well-understood geology and a well-designed strategy [110]. - Low CO2 solubility, unstable foams, and high mobility limit large-scale use [122].
Water Alternating Gas (WAG)/Water-Alternating CO2 (CO2 WAG)	- Can be used in most scenarios, including formations with low permeability and high water cut [106]. - Frequently applied for oilfields that have already undergone water flooding [110]. - Particularly effective in high-heterogeneity–low-permeability fields [106]. - Specifically used to delay gas channeling [121].	- More effective than continuous CO2 flooding in heterogeneous reservoirs. - Significantly enhances oil recovery by improving multiple displacement aspects. - CO2 WAG projects, often miscible, have achieved an average incremental RF of 10%, higher than that of hydrocarbon gas and N2 WAG, which obtained 8% [110]. - The low-salinity CO2 WAG method showed a 4.5% higher RF than high-salinity WAG in a field case simulation [123].	- Highly sensitive to reservoir properties such as heterogeneity, fluid properties, miscibility conditions, and rock wettability [106]. - Difficulty in achieving economically viable recovery in complex geological settings [110]. - May not completely avoid the gravity override phenomenon during CO2 injection [119]. - Field–lab gap from geological complexities and difficulties in engineering control [110].
Hybrid WAG (HWAG)	- Has been proposed to meet different reservoir requirements and address difficulties encountered in hard-to-recover fields [106].	- HWAG has shown results like traditional WAG and GAW in terms of the final recovery factor. - Increases the recovery factor to 57.3% [106]. - Uses a total gas injected volume that is about 4% lower than conventional WAG [106]. - HWAG can lead to a change in wettability to a more favorable state [106].	- Highly dependent on injection strategies (e.g., well pattern, number of cycles, volume of each cycle, injection rate, and pressure) and reservoir properties (e.g., heterogeneity, fluid properties, miscibility condition, and rock wettability) [106].
Hybrid Thermal–NCG Process	- Applied as a follow-up strategy in post-steam injection heavy oil and oilsands reservoirs, including those previously subjected to Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD) [124]. - Can be operated in various modes: cyclic injection (CO2-CSS), continuous injection (CO2-assisted steam flooding) [124].	- For hybrid CO2-CSS, the heat energy required is much lower compared to conventional CSS, and the addition of CO2 also reduces the injection temperature [124]. - CO2-assisted supercritical water (MGA-SCW) flooding can not only enhance oil recovery but also improve the quality of produced oil [125]. - MGA-SCW flooding at 25 MPa and 400 °C resulted in a recovery factor approaching 95% [125].	- Generally requires large amounts of gases and high pressures to achieve miscibility with oil [108]. - Highly sensitive to operating parameters (e.g., injection rate and time, number of cycles, soaking time, pressure) [110,120]. - Poor sweep efficiency and early breakthrough. - Dynamic coupling of temperature, pressure, and physical properties with geological structures in CO2 injection wells requires further research.
CO2 Assisted Gravity Drainage (CO2-AGD)	- Designed for both secondary and tertiary oil recovery stages [126]. - Particularly beneficial for water-flooded reservoirs that still contain a significant amount of “attic oil” located at the top of the reservoir formation [122]. - Can be applied in complex fault block reservoirs characterized by strong heterogeneity, significant edge and bottom water energy, high water cut, and intricate remaining oil distribution [122].	- Achieves an 11.6% higher ultimate oil recovery than free fall gravity drainage [126]. - Leads to high volumetric sweep efficiency and high oil recovery by facilitating the formation of a near-horizontal flood front, and helps in delaying CO2 breakthrough into production wells [126].	- Maintaining stable control of the gas–oil interface is crucial [122]. - Reservoirs with a strong bottom water drive may experience less significant incremental oil recovery from CO2-AGD compared to those with limited or no bottom water drive [126].

Table 2. Common CO₂ injection techniques in EOR.

Technique	Application	Effectiveness	Limitations
Continuous CO2 Injection (Flooding)	- Widely applied in various reservoirs, especially low-permeability, ultralow-permeability, deep-water, and high-sulfur reservoirs [106,116]. - Successfully applied in heavy oil belts [116] - Effective for crude oil with an API gravity higher than 25 [110].	- Recovery of up to 90% original oil in place under miscible conditions [117]. - Increase recovery by 10–20% in low-permeability reservoirs [117,118].	- Early breakthrough, viscous fingering, and gravity override due to low CO2 viscosity/density and gravity effects [106,117,119]. - Poor sweep efficiency (~25%) and low space utilization [106,117].
CO2 Huff ‘n’ Puff (Cyclic Injection)	- Effective for unconventional reservoirs, particularly shale oil and tight oil reservoirs [110]. - Success in heavy oil and oilsands reservoirs [120]. - Successfully applied in conventional light oil reservoirs and several heavy oil cases, including mature oilfields [110,120,121].	- Oil recovery improvement of 30.4–46.5% [111]. - Generally yields a higher oil recovery factor (RF) compared to continuous CO2 flooding [111]. - Less sensitive to reservoir permeability and void gas viscous fingering and early breakthrough [111]. - Contributes significantly to CO2 geological sequestration, with 40–50% of injected CO2 being trapped in the porous medium [120].	- Field–lab gap from reservoir heterogeneity [110]. - Requires well-understood geology and a well-designed strategy [110]. - Low CO2 solubility, unstable foams, and high mobility limit large-scale use [122].
Water Alternating Gas (WAG)/Water-Alternating CO2 (CO2 WAG)	- Can be used in most scenarios, including formations with low permeability and high water cut [106]. - Frequently applied for oilfields that have already undergone water flooding [110]. - Particularly effective in high-heterogeneity–low-permeability fields [106]. - Specifically used to delay gas channeling [121].	- More effective than continuous CO2 flooding in heterogeneous reservoirs. - Significantly enhances oil recovery by improving multiple displacement aspects. - CO2 WAG projects, often miscible, have achieved an average incremental RF of 10%, higher than that of hydrocarbon gas and N2 WAG, which obtained 8% [110]. - The low-salinity CO2 WAG method showed a 4.5% higher RF than high-salinity WAG in a field case simulation [123].	- Highly sensitive to reservoir properties such as heterogeneity, fluid properties, miscibility conditions, and rock wettability [106]. - Difficulty in achieving economically viable recovery in complex geological settings [110]. - May not completely avoid the gravity override phenomenon during CO2 injection [119]. - Field–lab gap from geological complexities and difficulties in engineering control [110].
Hybrid WAG (HWAG)	- Has been proposed to meet different reservoir requirements and address difficulties encountered in hard-to-recover fields [106].	- HWAG has shown results like traditional WAG and GAW in terms of the final recovery factor. - Increases the recovery factor to 57.3% [106]. - Uses a total gas injected volume that is about 4% lower than conventional WAG [106]. - HWAG can lead to a change in wettability to a more favorable state [106].	- Highly dependent on injection strategies (e.g., well pattern, number of cycles, volume of each cycle, injection rate, and pressure) and reservoir properties (e.g., heterogeneity, fluid properties, miscibility condition, and rock wettability) [106].
Hybrid Thermal–NCG Process	- Applied as a follow-up strategy in post-steam injection heavy oil and oilsands reservoirs, including those previously subjected to Cyclic Steam Stimulation (CSS) and Steam Assisted Gravity Drainage (SAGD) [124]. - Can be operated in various modes: cyclic injection (CO2-CSS), continuous injection (CO2-assisted steam flooding) [124].	- For hybrid CO2-CSS, the heat energy required is much lower compared to conventional CSS, and the addition of CO2 also reduces the injection temperature [124]. - CO2-assisted supercritical water (MGA-SCW) flooding can not only enhance oil recovery but also improve the quality of produced oil [125]. - MGA-SCW flooding at 25 MPa and 400 °C resulted in a recovery factor approaching 95% [125].	- Generally requires large amounts of gases and high pressures to achieve miscibility with oil [108]. - Highly sensitive to operating parameters (e.g., injection rate and time, number of cycles, soaking time, pressure) [110,120]. - Poor sweep efficiency and early breakthrough. - Dynamic coupling of temperature, pressure, and physical properties with geological structures in CO2 injection wells requires further research.
CO2 Assisted Gravity Drainage (CO2-AGD)	- Designed for both secondary and tertiary oil recovery stages [126]. - Particularly beneficial for water-flooded reservoirs that still contain a significant amount of “attic oil” located at the top of the reservoir formation [122]. - Can be applied in complex fault block reservoirs characterized by strong heterogeneity, significant edge and bottom water energy, high water cut, and intricate remaining oil distribution [122].	- Achieves an 11.6% higher ultimate oil recovery than free fall gravity drainage [126]. - Leads to high volumetric sweep efficiency and high oil recovery by facilitating the formation of a near-horizontal flood front, and helps in delaying CO2 breakthrough into production wells [126].	- Maintaining stable control of the gas–oil interface is crucial [122]. - Reservoirs with a strong bottom water drive may experience less significant incremental oil recovery from CO2-AGD compared to those with limited or no bottom water drive [126].

3.3.2. Geological Storage: Saline Aquifers, Depleted Reservoirs

Geological caverns offer a vast space for CO₂ storage. Saline aquifers and depleted oil or gas fields are favorable options for CO₂ offshore sequestration [29,127,128,129,130,131]. A recent study reveals that hydraulic regimes significantly affect storage capability [132]. A compactable location for CO₂ sequestration requires permeability and capillary barriers that prevent the CO₂ from escaping [133]. Various studies indicate that sealing layers with high permeability can reduce the pressure front (and the native brine), reducing the propagation through the seals to neighboring formations, and may reach shallow levels in extreme cases. Meanwhile, such considerable vertical leakage would attenuate pressure buildup within the storage formation [132]. No research has been conducted to systematically estimate the area of influence in response to CO₂ storage within multilayer systems where lateral and vertical brine flow may compete [132].

Hydrocarbon production begins with the exploitation of the well fluid from the reservoir and ends with the abandonment of the depleted formation [134]. In a more limited capacity than a saline aquifer, a depleted gas field offers a more reliable space for CO₂ sequestration that has better seals and characteristics for retaining the CO₂ for thousands of years [135,136]. These fields have broadly attracted various scholars for academic research or practical investigations, including well logs, seismic data, pre- and post-pressure of wells, etc. However, external factors such as geological and geomechanical parameters or economic and legal frameworks may facilitate the suitability of the geological storage [137].

Table 3. Summary of previous offshore CCUS projects.

No	Project	Depth	Advantages	Challenges
1	Location: Sleipner field, Norway Start date: 1996 Capacity: 0.9 Mt/yr CO2 Source: Sleipner field [31]	800–1000 m below the sea	This is the 1st offshore CCS in the world. CO2 was injected into the saline, highly porous Utsira Fm through an injection well in the Sleipner field [31]. There is no evidence for CO2 migration [31].	Injectivity due to sand influx. Lack of geophysical and environmental monitoring [140]. High uncertainties regarding the reservoir’s temperature and seismic characteristics [141].
2	Location: Gorgon field, Australia Start date: 2019 Capacity: 3.3–4 Mt/yr CO2 source: LNG plant [34]	2000 m beneath Barrow Island	Gorgon is the world’s largest CCS project [34]. Highly reliable 3-D seismic profile [142].	Temperature and pressure variations [34]. High concentration of solids in produced formation water [142].
3	Location: Northern Lights, Norway Start date: 2024 Capacity: 0.4 t/year CO2 source: cement factory [143]	2600 m below the sea	Deep geological formation [144]. The bridged CCS funding gap [30].	It is a greenfield project, with inadequate subsurface data [145]. Long distance of CO2 transport by vessel and pipeline [144,146].

briefly summarizes the advantages and challenges of the offshore CCUS projects in the world. Generally, offshore deep CO₂ sequestration is an effective method for capturing GHGs and reducing climate change. Deep geological formations accommodate a large amount of CO₂ at the proper temperature and pressure. However, monitoring of the CO₂ immigration in the reservoir is a big issue for most offshore CCUS projects and remains a challenge for scientists, operators, and governors. To ensure the reliability of reservoirs, detailed surveys have been conducted to evaluate the pore space, permeability, and fault stability of formations. During storage, microseismic, fault, and rock behaviors are continuously observed to monitor the leakage of CO₂ [138,139].

3.4. Barriers and Challenges

CCUS is gaining serious traction in the E&P sector, as firms attempt to align with climate goals and leverage their technical strengths. Some projects in the Middle East, the USA, Japan, Australia, and Norway are already operational or injecting CO₂, but many remain in development or pilot phases, especially in the upstream domain [2,147]. These offshore reservoirs are mostly distant from the coastal and industrial areas, which requires more attention to safety issues [148]. The primary challenges hindering the offshore deployment of CCUS include high costs, inadequate regulatory frameworks, subsurface uncertainties, and the lack of shared infrastructure necessary to achieve economies of scale.

Subsurface sediment reservoirs offer the best conditions for CO₂ sequestration in terms of pressure, temperature, and permeability [149,150]. In addition, offshore sequestration can collect CO₂ from offshore point sources such as oil and gas production and carriers [148]. The integration of offshore CCUS technologies and oil and gas platforms inherits the existing facilities for transportation and injection and storage sites for long-term sequestration [22]. However, the risk of leakage from storage sites could undermine public confidence in CCUS technology and negate the benefits of CO₂ capture. Developing reliable monitoring systems to track CO₂ storage and assess potential leakage is essential, but these systems require advanced technology and significant investment [151].

Capital expenditure and operating expenditure mediate the implementation of the offshore carbon sequestration, which remains challenging without supportive policy incentives or market-driven mechanisms [152]. These costs include capture equipment of facilities, transportation, and injection and storage facilities. Capex may come from the modification of the installation or increasing the well integrity for gas sequestration [150]. In addition, carbon pricing has a vital role in the CCUS market [53]. The uncertainty of the carbon market and supportive incentives further complicates the economic landscape for CCUS. Variability in carbon pricing and the lack of clear and consistent government policies create uncertainty for potential investors [153].

Carbon price, public perception, and legal regulations regulate the landscape of CCUS implementation [154,155]. Local policies and international agreements are the main drivers of CCUS technologies and adaptation. However, the lack of clear and consistent policies in the carbon market creates challenges for investors in making decisions [156]. International climate accords may affect nations’ readiness to invest in CCUS technologies, particularly when global emission reduction targets remain disputed. Furthermore, regulations surrounding CO₂ storage introduce additional legal complexities [155]. Therefore, a clear and consistent policy on carbon pricing and the carbon market will be crucial to overcoming the barriers to CCUS deployment [157].

4. Conclusions

This paper provides a comprehensive review of the state-of-the-art technologies for the capture, utilization, and storage of carbon in offshore areas. Findings from this paper indicate the advantages of these methods in the low-carbon economy. Lessons from the Sleipner, Gorgon, and Northern Lights projects offer opportunities to broaden CCS in subsea geological formations, which is a safe, environmentally friendly, and economical solution. However, the lack of systems for monitoring CO₂ leakage in a deep formation makes geological sequestration unpopular. In addition, barriers to large-scale deployment include high capital and operational costs, uncertain carbon pricing, inconsistent regulatory frameworks, and public acceptance concerns.

Furthermore, offshore projects typically incur higher expenses due to their remote locations, complex marine logistics, and stringent technical and safety requirements. In the absence of clear and stable policy incentives—such as carbon price floors, storage credits, or the inclusion of shipping in emission trading schemes—the investment risk remains high. Nevertheless, the convergence of advancing technologies, declining unit costs through the development of CCUS hubs, and strengthening global climate commitments presents a critical window of opportunity for the expansion of offshore CCUS. Future research should prioritize the following:

• Cost reduction through modular capture units, shared infrastructure, and process integration with renewables.
• Improved transport and injection designs for phase stability and safety.
• Enhanced reservoir characterization and CO₂ immigration, rock behavior, and numerical modeling for maximizing storage efficiency and monitoring gas leakage.
• Regulatory harmonization and financial mechanisms for de-risking investments.

In conclusion, offshore CCUS can play an indispensable role in meeting net-zero targets, but its success depends on coordinated technical innovation, supportive policy, and sustained investment. By addressing economic, regulatory, and environmental challenges, offshore CCUS can evolve from niche projects to a global decarbonization pillar.