Overview of Typical Projects for Geological Storage of CO₂ in Offshore Saline Aquifers

Abstract

With the continuous growth of global energy demand, greenhouse gas emissions are also rising, leading to serious challenges posed by climate change. Carbon Capture, Utilization, and Storage (CCUS) technology is considered one of the key pathways to mitigate climate change. Among the CCUS technologies, CO₂ storage in offshore saline aquifers has gained significant attention in recent years. This paper conducts an in-depth analysis of the Sleipner and Snøhvit projects in Norway and the Tomakomai project in Japan, exploring key issues related to the application, geological characteristics, injection strategies, monitoring systems, and simulation methods of CO₂ storage in offshore saline aquifers. This study finds that CO₂ storage in offshore saline aquifers has high safety and storage potential but faces several challenges in practical applications, such as geological reservoir characteristics, technological innovation, operational costs, and social acceptance. Therefore, it is necessary to further strengthen technological innovation and policy support to promote the development and application of CO₂ storage in offshore saline aquifers. This study provides valuable experiences and insights for similar projects worldwide, contributing to the sustainable development of CO₂ storage in offshore saline aquifers and making a greater contribution to achieving global net-zero emission targets.

1. Introduction

The continuous growth in global energy demand, driven by population expansion, technological innovation, and improved living standards, has led to a significant increase in atmospheric greenhouse gases (GHGs), particularly CO₂, which is a primary driver of global warming and climate change. This phenomenon has severe consequences for agriculture, human health, forests, and ecosystems [1]. To meet global economic demands, energy production methods that are intensive in atmospheric pollutants have exacerbated the problem [2]. As international concern about climate change rises, countries are proposing various countermeasures, and the long-term reliance on fossil fuels necessitates the urgent search for new emission reduction methods. Carbon Capture, Utilization, and Storage (CCUS) technology is regarded as a promising new technology for CO₂ emission reduction. According to the “Energy Technology Perspectives 2020” report published by the International Energy Agency (IEA), under the sustainable development scenario, the amount of CO₂ captured and stored will increase annually. By 2070, it is estimated that 6.7 Gt of CO₂ from fossil fuels will be captured, and 6.6 Gt will be stored underground, with a storage ratio of 98.5% [3]. The “IPCC Special Report on Global Warming of 1.5 °C” (2018) assessed 90 scenarios for achieving net-zero emissions in the future, and almost all scenarios require CCUS technology [4,5,6]. It is estimated that by 2050, CCUS technology will contribute to a 10–15% reduction in global CO₂ emissions [7].

CO₂ storage is a crucial component of CCUS technology, but it still faces significant uncertainties and challenges. The main CO₂ storage schemes include geological storage and ocean storage [8,9,10]. Although ocean storage can accommodate large amounts of CO₂, researchers have identified numerous challenges in this process, particularly related to insufficient storage life, high operational and transportation costs, and environmental issues such as ocean acidification. Therefore, based on economic factors, site availability, and storage longevity, geological storage has been identified as the most feasible solution to address this problem [11]. The main geological storage sites for CO₂ include mature (or depleted) oil and gas reservoirs, unmineable coal seams, and deep saline aquifers. Among these, deep saline aquifers are widely distributed globally and possess enormous storage potential, accounting for over 98% of the total geological storage potential, making them one of the most suitable sites for CO₂ storage [12,13,14].

Among the various branches of CCUS technology, CO₂ storage in offshore saline aquifers has attracted significant attention, as shown in Figure 1 [15]. Unlike onshore CCUS, which poses risks such as groundwater contamination and regional environmental impacts, offshore CCUS offers higher safety, lower environmental risks, and greater storage potential. This has garnered considerable interest from governments, industry, and academia worldwide [16,17]. Firstly, the increased safety is attributed to offshore storage sites being distant from aquifers, with seawater acting as an additional pressure barrier above the rock cap, significantly reducing local risks. Secondly, monitoring is facilitated by the chemical similarity between pore water in seabed formations and normal seawater, simplifying pressure management. Lastly, offshore sites offer much greater storage potential, often tens to hundreds of times that of onshore locations. Therefore, for coastal industrial regions constrained by onshore geological storage limitations, offshore saline aquifers emerge as a suitable choice for CO₂ storage [18].

In response to the global challenge of achieving net-zero emissions, we conducted an extensive study of Norway’s Sleipner and Snøhvit projects, along with Japan’s Tomakomai project. These long-operational, data-rich, large-scale initiatives serve as representative examples. Through a comprehensive analysis of their project backgrounds, geological information, injection strategies, monitoring systems, and simulation methods, we aimed to gain a thorough understanding of CO₂ storage applications in offshore saline aquifers across diverse geographical and climatic conditions. The unique attributes of these projects offer valuable insights for similar initiatives worldwide, underscoring the pivotal role of offshore saline aquifer storage technology in mitigating climate change. Additionally, we explored future development potentials and challenges in this field, providing deeper insights toward achieving global net-zero emission goals. This review aims to present viable paths for global carbon reduction and climate change mitigation, thereby fostering sustainable development.

2. Typical Offshore Saline Aquifer Storage Project

2.1. Sleipner

2.1.1. Project Background

The Sleipner CCUS project, located approximately 150 km offshore from the Sleipner gas field in Norway, has a CO₂ content of about 9%. Commercial natural gas must contain no more than 2.5% CO₂; therefore, excess CO₂ must be separated, making this the world’s first CO₂ storage project aimed at reducing atmospheric CO₂ concentrations [19]. This project marked the beginning of large-scale industrial geological carbon storage exploration globally and remains the longest-running CO₂ storage project to date [20,21]. As depicted in Figure 2, the core operation involves extracting CO₂ from adjacent gas fields and injecting it into the Utsira Formation, located approximately 200 km offshore and at a depth of about 1 km [22,23]. Since its inception in 1996, Equinor has successfully injected approximately 1 Mt of CO₂ annually into the Utsira sandstone formation [24,25,26]. The operational objective of this CO₂ storage site is to mitigate CO₂ emissions from natural gas production in the region, originally designed to circumvent Norway’s carbon tax through effective emission management strategies [19].

2.1.2. Geological Information

The Utsira sandstone stretches over 450 km long and 90 km wide and is situated near the UK/Norway median line in the Viking Graben area. It spans between latitudes 58° N to 61°40 N and longitudes 1° E to 3°50 E, covering an area of approximately 26,100 km². This geological formation exhibits an average porosity of 36% and permeability ranging from 1 to 5 D. Its thickness varies between 200 and 300 m, with the top of the formation located approximately 800–1000 m below sea level at injection points, typically positioned at an average depth of 1012 m below sea level [21,27].

The Utsira reservoir is overlain by a caprock sequence several hundred meters thick, comprising three main units: the lower cap, middle cap, and upper cap, as shown in Figure 3. The lower cap, previously known as the shale cap, forms a mudstone basin confinement unit approximately 50 to 100 m thick. This lower cap layer extends well beyond the current area covered by CO₂ injection at Sleipner, indicating its effectiveness as a seal. Empirical data from caprock samples at Sleipner demonstrate effective sealing, with almost no possibility of CO₂ capillary leakage. Above this, the middle cap primarily consists of progressively deposited Neogene sediment wedges, dominated by mudstone in the basin center, gradually transitioning to sandy deposits toward the basin edges. The upper cap layer comprises Quaternary formations, mainly consisting of glaciomarine clays and till [28].

In the Sleipner area, a shale layer approximately 5 m thick, referred to as the “5 m shale”, separates the uppermost sand body from the main reservoir below. This shale layer acts as a critical permeability barrier within the reservoir sand bodies and has been proven to significantly influence the migration and storage processes of CO₂ within the reservoir.

Within the Utsira Sandstone Reservoir, eight sets of mudstone intervals with thicknesses of about 1.3 m, and one set of mudstone intervals with thicknesses of about 5–6.5 m, were developed from the bottom up. These mudstone intervals divide the Utsira Sandstone Reservoir into nine small layers vertically. These mudstone interlayers vertically separate the reservoir, buffer and separate CO₂ transport, and improve the overall reservoir utilization efficiency.

The shale consists primarily of multiple thin layers of mudstone or shale, typically about 1 m thick. The Utsira sands have the potential to store about 2~15.7 Gt of CO₂ and have become a major reservoir in the neighboring region with porosities generally ranging from 27% to 31%, and locally up to 42%. Laboratory experiments to determine the porosity of the cores show a range of 35% to 42.5% [21,29].

2.1.3. Injection Information

On 15 September 1996, the Sleipner CCUS project began CO₂ injection at injection well 15/9-A-16, located at coordinates (x: 436,137.42, y: 6,470,282.86). Over the subsequent 12 years (1999–2010), the injection well experienced multiple changes in operational rates, as shown in Figure 4 [30]. In the early stages of CO₂ injection, weak reservoir cementation led to sand production flowing into the well, which reduced injection capacity. This issue was resolved in August 1997 by re-perforating the injection intervals, installing 300 μm sand screens, and filling with gravel [31,32]. Following these interventions, the injection rate gradually stabilized. In the initial years, the annual injection rate was approximately 0.9 Mt. Later, the injection rate slightly declined due to reduced natural gas flow from Sleipner Vest. Since 2014, CO₂ from the Gudrun field has also been processed through the Sleipner CCUS facility [33].

The injected CO₂ is a byproduct of natural gas production from the Sleipner Vest reservoirs, where the natural CO₂ content is about 4–9.5%. The natural gas is transported via pipeline to the Sleipner T platform, where the CO₂ is separated, compressed, and, in a subsequent step, re-injected into the Utsira Formation. It is important to note that the injected CO₂ is wet and contains 0.5–2% methane, and in order to meet wellhead pressure requirements, the CO₂ must undergo four compression stages. In the case of a prolonged shut-in of the Sleipner well, the temperature at the top of the well may drop to 50 °C and the pressure may drop to 40 bar, in which case hydrate suppression becomes essential. The injection well has a slope of 83° to the platform, a lateral extension of 2.4 km, a depth of 1 km, and a gradient of only 10–20 m under gentle slopes, with possible leakage points in three directions. To maintain stability, the wellhead temperature was controlled at 25 °C, allowing the pressure to remain stable in the phase change pressure range (~62–65 bar). Although bottomhole pressures were not directly measured, stabilized injection and 4D seismic images indicate that there is only a small pressure buildup in the reservoir, suggesting pressures only slightly above hydrostatic pressure. The bottomhole temperature for CO₂ injection is estimated to be approximately 48 °C, which is approximately 13 °C higher compared to the original gas reservoir temperature. Injections have been carried out at regular intervals on a scheduled basis, with major interruptions only during the four-week period each year when the platform undergoes well workovers, during which a small fraction of the captured CO₂ is vented to the atmosphere. At Sleipner, there is sufficient injection capacity and reservoir storage to eliminate the need for reservoir management.

2.1.4. Monitoring

Due to the lack of monitoring guidelines or regulations at the start of the Sleipner injection project, Statoil and its partners opted for a large number of test methods, which were often repeated and covered a wide range of areas. A proposal to recommend dedicated monitoring wells early in the project was initially rejected on the grounds of increased cost and risk. The project therefore focused on the use of remote geophysical monitoring methods. To monitor injected CO₂, the Sleipner project initiated a separate Salt CO₂ Storage (SACS) project in 1998 to establish a baseline by conducting the first 3D seismic survey. The seismic monitoring successfully imaged the movement of CO₂ within the reservoir for the first time, setting a milestone in the industry. In addition, it used seismic data to validate available models and tools (originally developed for hydrocarbons and water) that have been applied to CO₂ and water systems [22,34].

Baseline surveys prior to the start of injection were combined with subsequent 3D seismic surveys to form a unique dataset depicting the development of the plume [35]. Monitoring of the CO₂ transport distribution consisted of one 3D seismic survey, eight 4D seismic surveys, four seafloor 4D gravity surveys, one EM survey, and two seafloor imaging surveys. A permanent seafloor datum was deployed on Sleipner’s CO₂ plume in 2002, and a baseline for the gravity surveys was obtained in the same year, followed by subsequent surveys in 2005, 2009, and 2013. Surveys have found that the amount of CO₂ monitored from gravity monitoring is the same as the amount injected, and these surveys have contributed to a detailed understanding of CO₂ behavior in the sequestration unit [24,36]. The time-shifted seismic data clearly depict the gradual development of the CO₂ plume, which forms a prominent multilayered feature consisting of numerous bright subhorizontal reflections interpreted as coming from discrete layers of CO₂, each up to a few meters thick, that accumulate mainly beneath the mudstone within the reservoir, as shown in Figure 5. Nine CO₂ accumulation layers were identified from seismic data. The topography (lateral extent, continuity, etc.) of each layer shows significant differences, and layer 9 is in direct contact with the overlying seal cap layer [37].

Of the data obtained, layers 5 through 9 were better imaged, while imaging of layers 1 through 4 was challenging. Reasons for the degradation of the deep signal may include inelastic attenuation, loss of signal transmission through the CO₂ layer, and the compounding effect of CO₂ migration/propagation. Based on the shallowest bright reflections in the seismic data, only the uppermost CO₂ plume in the “sand wedge” unit (layer 9) is separated by a 5 m shale unit as its lower boundary, and CO₂ accumulation over time has been quantified in this layer [38,39]. In addition, the interpretation of the lower CO₂ plume is influenced by the overlying bright seismic reflections, and thus the current study focuses on the uppermost CO₂ storage [40]. The CO₂ layer was formed early in the evolution of the smokestack column (1999) and is still recognizable today, with the upper layer continuing to diffuse laterally with a general increase in brightness, whereas the lower layer stabilizes in size and gradually becomes darker. Vertical linear features within the plume characterized by reduced reflection amplitudes and local velocity downthrusts have been interpreted as “chimneys” of moderate or high CO₂ saturation [41]. The most prominent portion of this chimney, located roughly above the injection point, is interpreted as the main conduit for CO₂ transport upward through the reservoir and the main feeder to the laterally diffusing thin layer. This chimney suggests that the continuity of shale layers within the formation is broken at the same location as these shale layers. It is almost impossible for this vertical stacking of highly permeable layers to have existed by chance prior to injection, so it is more likely that it was produced by the injection process. It may be due to mechanical instability (liquefaction and fluidization) as a response to concentrated vertical CO₂ flow, and may be amplified by local carbonate dissolution and matrix collapse along the flow path [24]. Within the reservoir overburden, there is no evidence of systematic changes in seismic signatures that would indicate the presence of CO₂ in the reservoir [38].

Up to 300 testing wells have been drilled, among which are 30 wells within 20 km of the injection site. Information collected from the wells includes lists of formation top, geophysical logs, reservoir core material, selected cuttings of caprock and reservoir rocks, and reservoir pressure measurements [42]. CO₂ plume monitoring observations at Sleipner can be used to indicate an overall storage efficiency of around 5% of the pore volume, with approximately one tenth of this volume dissolved in the brine phase. These estimates are consistent with the fluid dynamics of CO₂ injection in which gravity dominated processes are expected to give efficiencies in the range of 1–6%. The presence of the Sleipner shale barrier produces a multilayered plume that counteracts the effects of buoyancy, which would otherwise result in the plume rising rapidly to the top of the sandstone unit [43].

The major success of the SACS/SACS2 project is that conventional time-shifted seismic data can be used as a successful monitoring tool for CO₂ injected into saline aquifers. CO₂ accumulations down to ~1 m in thickness can be detected by inducing significant, observable, and measurable changes in the seismic signal. Seismic surveys clearly show the behavior of injected CO₂ in the saline aquifer [44]. This dominant effect of time-lapse seismic signals on relatively thin CO₂ accumulations gives us confidence that any major leakage from the upper overburden will be detected. Although there is no evidence to date that CO₂ stored in the Sleipner model could leak into the atmosphere, monitoring the storage process and managing the risk of leakage will remain critical throughout the project. Reliable and cost-effective monitoring will be an important component in making geologic storage a safe, effective and acceptable method of CO₂ control. Monitoring will be conducted as part of the subsurface injection permitting process and will be used for many purposes, such as tracking the location of injected CO₂ plumes, ensuring that injection and abandonment wells are not leaking, and verifying the amount of CO₂ that has been injected into the subsurface. Monitoring is essential to ensure the reliability and safety of geologic storage; it does not guarantee safety by itself, but it determines the safe storage of injected CO₂ [30,32].

2.1.5. Modeling

Many researchers have attempted to better understand plume transport in the Sleipner area and to find a satisfactory match to the CO₂ plume transport history. Injected CO₂ is safely trapped in the subsurface mainly through mechanisms of structure (buoyancy, separated phases), residual (capillary), solubility, and mineral trapping. The first two mechanisms are physical trapping and the latter two are geochemical trapping. These trapping mechanisms operate on different time scales, ranging from decades to thousands of years [45,46]. Therefore, numerical modeling of these storage mechanisms is essential for the purpose of storage safety and consistency, as it can be used to assess the long-term safety of CO₂ storage. Detailed interpretation and flow modeling for matching and prediction purposes has been a challenge for Sleipner. It is clear that most of the flow is controlled by topography. The injected CO₂ flows in nine different highly saturated layers, no more than a few meters thick, overlying thin layers of sand and shale. Stronger gravitational polarization causes CO₂ to flow upward in the reservoir, and the plume morphology mainly resembles the topography of the reservoir. To date, no previous dynamic model has accurately reproduced the CO₂ plume morphology in the uppermost layers of the Utsira sands.

Figure 6 illustrates the changes in CO₂ capture mechanisms over 1000 years, where the molar amount of injected CO₂ is normalized by the total amount of injected CO₂ (12 Mt in 2010). During the first 12 years of injection, the dominant trapping mechanism was structural trapping, which accounts for ~70% of the injected CO₂ at the end of the injection period. After well shut-in, the amount of residual trapping increased, and the amount of structural trapping decreased dramatically. Solubility capture continued to increase during well shut-in. Over 70% of the injected CO₂ becomes dissolved in formation brine over the modeled 1000-year time frame [26].

The primary targets for CO₂ storage injection are deep, porous rock layers in sedimentary formations (located over 1000 m below the surface) that are primarily composed of silicate, aluminosilicate, and carbonate mineral grains. At these depths, pressures and temperatures typically range between 10 and 30 MPa and 310 to 380 K, enabling CO₂ to exist in a supercritical state (with a critical point of approximately 304 K and 7.4 MPa, depending on the salinity of the formation water). Supercritical CO₂ exhibits high density, low viscosity, and excellent mobility, all of which contribute to its effective storage in saline aquifers.

Upon injection into saline formations, CO₂ initially fills the pore spaces within the rock matrix. As injection continues, a portion of the CO₂ gradually rises due to its lower density relative to brine, where it becomes trapped beneath the caprock layers at the top of the formation. Over time, a combination of geological and brine interactions enable multiple trapping mechanisms—such as structural, residual, dissolution, and mineral trapping—that work together to achieve permanent storage. These mechanisms are interdependent and, collectively, enhance the security of CO₂ storage as time progresses. Consequently, a central consideration for storage safety is to ensure that the buoyant nature of supercritical CO₂ relative to formation water does not result in its migration toward the Earth’s surface [20].

The primary mechanism driving CO₂ flow is gravity, with CO₂ floating up until it reaches the shale within the reservoir [47]. These thin shale layers form at least a temporary barrier to CO₂ flow, but are not expected to be completely tight [48]. Reservoir simulations indicate (Prediction of migration of CO₂ injected into a saline aquifer: Reservoir history matching to a 4D seismic image with a compositional Gas/Water model) that most of the CO₂ remains trapped in the relatively thin, highly saturated reservoir beneath the shale layer and follows its topography. Figure 7 shows an example reservoir simulation from the 1999 time-lapse seismic survey.

2.2. Tomakomai

2.2.1. Project Background

The Tomakomai Saltwater Sequestration Project (TSSP) in Japan is a major Carbon Capture and Storage (CCUS) demonstration project promoted by Japan CCUS Corporation (JCCUS) in 2012 in the sea area near the port of Tomakomai, Hokkaido, with financial support from the Ministry of Economy, Trade and Industry (METI) of Japan [49,50]. As shown in Figure 8, the Tomakomai CCUS project is the first offshore CCUS-integrated industrial demonstration project in Japan, which includes various aspects such as capturing and compressing CO₂ from hydrogen production exhaust gas, and injecting and sequestering CO₂ [51]. During the first four-year period from 2012 to 2015, the project completed the preparation and construction of all necessary facilities and systems. In particular, CO₂ was captured from the off-gas of the hydrogen production unit at the Idemitsu Kosan refinery in Hokkaido, and the construction of the capture unit was completed in 2015, as well as the construction of the CO₂ surface injection facility in the same year. In terms of well construction, an existing investigation well was converted into a monitoring well, and the drilling of two monitoring wells and two injection wells was completed [52]. In the pre-injection phase of CO₂, in order to verify that CO₂ injection into the reservoir would not affect the surrounding environment, JCCUS established a monitoring system to record seismic data of the reservoir and obtained baseline data before injection. The project implemented three years of CO₂ injection and five years of microseismic activity, natural seismicity, and marine environmental monitoring [53]. The captured CO₂, after being pressurized to the pressure required for injection (up to 23 MPa), was injected into two offshore saline aquifers at different depths, Moebetsu and Takinoue, through two separate directional injection wells under the seabed in the offshore waters of the Port of Tomakomai, starting from April 2016 and injecting about 0.1 Mt per year. On 22 November 2019, the Tomakomai CCUS project achieved its cumulative injection target of 0.3 Mt and ceased injection.

The objective of the project is to validate the feasibility of a full-chain CCUS system—from CO₂ capture and injection to storage in saline aquifers—at a practical scale. It also aims to establish CCUS technology for practical use by around 2020 and to support the future deployment of CCUS projects in Japan [54]. The demonstration project has the following main features: the first full-chain implementation of CCUS in an earthquake-prone country, low energy consumption of the entire CO₂ capture process, application of large, inclined injection wells, extensive ocean monitoring system, and the world’s first CCUS project reflecting the London Protocol.

2.2.2. Geologic Information

There are two target reservoirs in the Tomakomai CCUS project, as shown in Figure 9. The shallow reservoir is a sandstone layer of the Moebetsu Formation, which is located at a depth of about 1000~1200 m below the seafloor. This reservoir is a Quaternary saline aquifer with a thickness of about 200 m, a porosity of 5~40%, a permeability of 9~25 mD, and is overlain by the mudstone layer of the Moebetsu Formation. The deeper reservoir is the Takinoue Formation, which is located below the seafloor at a depth of about 2400~3000 m. The reservoir is a Miocene saline aquifer consisting of volcanic and volcaniclastic rock, with a thickness of about 600 m, a porosity of 10~40%, and a permeability of 10~25 mD. The reservoir is a Miocene saline water layer composed of volcanic and volcanic clastic rocks with a thickness of about 600 m, porosity of 10~20% and permeability of 0.01~7 mD. The upper cover of the Takinoue Formation is a Miocene mudstone layer (Fureoi Formation, Biratori-Karumai Formation, and Nina Formation), which has a total thickness of about 1000 m. The Takinoue Formation is a dorsal sloping structure with a NNW–SSE strike axis, and the reservoir is located in the northeast flank of the backslope, offshore from the sea floor. The Takinoue Formation is a NNW–SSE strike axis backslope structure, and the planned reservoir is located on the northeastern flank of the backslope, about 4 km offshore. Due to the low permeability of the Takinoue Formation, the injection of 98 t of CO₂ into the Takinoue Formation was halted from February 2018 to September 2018 in order to avoid engineering risks, such as damage to the capping layer, and the Moebetsu Formation has been assumed to be the main reservoir. It should be noted that the Tomakomai CCUS project originally envisioned a reservoir in the deep Takinoue volcanic formation, but an injection well was drilled into the shallow Moebetsu sandstone formation as funds permitted. During the CO₂ test injection, the deep injection well could not be injected at all, and it was successful at the shallow end [54,55,56].

2.2.3. Injection Information

In the injection facility, gaseous CO₂ is directed to two different offshore reservoirs through two dedicated injection wells, both drilled onshore, and the drilling of the injection wells from onshore to the seafloor avoids disruption to port operations and fishing activities and significantly reduces drilling costs compared to offshore drilling, as shown in Figure 10 [54]. The two injection wells are large displacement horizontal wells drilled from onshore nearshore to offshore seafloor with a steeper dip. The injection pressure in each well was adjusted for different reservoir conditions, with a low-pressure compression system for the shallow reservoir (Moebetsu Formation) and a high-pressure system for the deeper formation (Takinoue Formation). The centrifugal compressor was chosen to gain operational data and experience that could benefit future commercial-scale CCUS projects. The CO₂ injection rate for each reservoir depends on the operating load of the refinery during the injection period and the actual conditions of the reservoir.

The IW-1 injection well in the Takinoue Formation has a maximum slope of 72° and was drilled to a depth of 5800 m, a vertical depth of 2753 m, and a horizontal depth of 4346 m, making it the longest horizontal well in Japan. The length of the IW-1 injection well section completed with perforated tailpipe was 1134 m. Brine injection tests after completion of the IW-1 drilling showed that the Takinoue Formation had a rather limited injection capacity, with a permeability of the Nadasi class. In contrast, the IW-2 injection well in the Moebetsu Formation is a large displacement drilling (ERD) well with a maximum inclination of 83°, drilled to a depth of 3650 m, a vertical depth of 1188 m, and a horizontal depth of 3025 m. The ratio of the horizontal distance to the vertical depth (the offset ratio) is greater than two, making it the well with the highest offset ratio in Japan. The IW-2 injection section was 1194 m long, and was drilled using a sand-proof screen tube-covered injection tailpipe completion, which helped to minimize sand flow back into the well [53]. Brine injection tests after the completion of the IW-2 drilling showed that the Moebetsu Formation has a fairly high injection capacity, with permeabilities of hundreds of Darcy orders of magnitude. Based on the results of the injection tests in these two reservoirs, the initial injection program was adjusted.

2.2.4. Monitoring

To ensure the safety and stability of CO₂ injection, the Tomakomai project employed a series of monitoring systems to track the behavior of CO₂ in the reservoir and detect any CO₂ leaks in a timely manner [57,58]. Considering Japan’s sensitivity to earthquakes, the project also monitored natural earthquakes and microseismic activity to verify that they did not negatively affect CO₂ storage and to ensure that CO₂ injection did not cause a detectable increase in seismicity [59]. In particular, the pressure and temperature of injection wells and monitoring wells are continuously monitored, and based on the monitoring data, CO₂ migration in the reservoir is analyzed to monitor reservoir physical properties, fluid flow properties, and changes in reservoir permeability, and to predict storage capacity and geomechanical stability. 2D/3D seismic surveys are used to detect fluid distribution and pressure changes, to monitor CO₂ breakthroughs, and to determine CO₂ movement and migration patterns. The survey results are used to optimize the injection method and quantify the wave coefficients to make the reservoir simulation more accurate. Marine environmental surveys are used to detect changes in sediment, pore fluid/gas or benthic flora and fauna, monitor CO₂ leakage, and measure seawater parameters including pH, CO₂ partial pressure, dissolved oxygen, inorganic and organic carbon, and potential carbon isotopes.

For the injection wells, the system continuously monitors the CO₂ injection rate, bottomhole temperature and pressure, as well as the wellhead temperature and pressure of the injected CO₂. In addition, temperature and pressure sensors and downhole seismometers were installed in three observation wells to provide more detailed subsurface information. In addition, a 3.6 km long permanent undersea cable (OBC), carrying 72 seismometers, was deployed directly above the reservoir storage site, while four undersea seismometers were placed above and around the storage site. A land-based seismic station was also constructed in the northwestern part of Tomakomai City. Monitoring of microseismic activity and natural earthquakes began during the 13 months prior to project initiation, before CO₂ injection began, through the equipment of observation wells, subsea seismometers, seafloor seismometers, and the onshore seismic station.

The Tomakomai injection site is equipped with advanced monitoring technology, including permanent submarine cables, gravity surveys, seafloor sediment and water column analysis, multiple permanent submarine seismometers, instruments in deep monitoring wells, and conventional 3D seismic monitoring using a temporary submarine cable receiver array. To date, no microseismic activity due to CO₂ injection has been observed. In addition, large natural earthquakes occurring approximately 40 km from the project site have not had any impact on the stored CO₂ [60].

Although the direct impacts on local communities may not be the primary concern for offshore CCUS projects, public perceptions must never be overlooked during their development. Researchers have investigated the concerns of coastal and marine stakeholders regarding the Tomakomai CCUS demonstration project in Hokkaido, Japan, and suggest that public acceptance of offshore CCUS will likely depend on the quality of scientific evidence presented to the public and their trust in regulatory authorities [61,62]. Therefore, it is crucial for national marine monitoring and regulatory agencies to have a solid scientific understanding of the entire system associated with offshore CCUS.

2.2.5. Simulation

During CO₂ injection into deep saline formations, CO₂ largely replaces the available pore space initially filled with formation water, resulting in an increase in pressure in the formation. If the pressure exceeds the allowable level, there may be a risk of saline water leakage into the overlying freshwater aquifer or, in the case of a loss of seal integrity in the sealing layer, a risk of CO₂ leakage may be triggered. To mitigate pressure buildup during CO₂ sequestration, a case study was conducted at the Tomakomai test site in Japan to evaluate the effectiveness of two methods to mitigate pressure buildup. The first method involves the use of a dual-mode well, which is used for formation water extraction prior to CO₂ injection. In this way, formation pressure can be reduced, CO₂ injection can be prolonged, and more CO₂ can be stored before critical pore pressures are reached. In addition, the dual-mode wells do not require additional well installations and are, therefore, economically justified. The second method requires a second well for production of formation water, whose extraction occurs simultaneously with CO₂ injection [56].

The researchers performed numerical simulations for three industrial-scale CO₂ sequestration cases, each using an injection rate of 1 Mt/yr. The first case represents the base case where only 100 years of CO₂ is injected into the Moebetsu Formation, which should be considered when there is no pre-injection of formation water or when production occurs due to a single well. In the second case, formation water was extracted for 5 years and then CO₂ was injected for 100 years. In this case, the injection wells were initially installed for pre-injection of formation water, so a dual-mode well is assumed. The third scenario assumes that observation well OB-1 is converted into a production well. Therefore, both wells are operated simultaneously, with the injection well injecting CO₂ and producing formation water through the observation well OB-1, and the rate of producing formation water is chosen to be 1 Mt, which is the same as the injection rate. The simulation results are shown in Figure 11.

The results of the study showed that the dual-mode wells could not effectively reduce the pressure for a limited time (5 years) of water production due to the large reservoir volume. In contrast, the method of using formation water production during CO₂ injection is more effective. However, there is a potential risk of using this method, which is the possibility of CO₂ leakage due to production wells. To circumvent this, the placement of injection and production wells needs to be optimized.

2.3. Snøhvit

2.3.1. Project Background

Snøhvit is an offshore CO₂ injection site located in the central part of the Hammerfest Basin in the southwestern part of the Norwegian Barents Sea, in water depths ranging from 250 to 340 m. The project started gas production in 2007, followed by CO₂ injection in 2008. CO₂ separated from natural gas is injected into the saline aquifer at a depth of about 2700 m below the hydrocarbon layer, with a planned injection of about 23 Mt CO₂ over the 30-year life of the project [57,63,64]. The produced natural gas is processed into liquefied natural gas (LNG) through the coastal Melkoya plant. As the natural gas contains 58% CO₂, the CO₂ separated during the liquefaction process is transported back to the field, re-injected, and stored underground in the adjacent block to the north, which is separated from the producing block by a major fault. A 160 km pipeline was constructed to the field to store 0.7 Mt of CO₂ per year, almost half of the plant’s CO₂ emissions. As with the Sleipner project, the main motivation for CO₂ storage in the Snøhvit project was the Norwegian government’s carbon tax exemption [65,66].

In 2008, the Snøhvit project began injecting CO₂ into the Tubåen Reservoir, as shown in Figure 12, and until injection ceased in early 2011, a total of 1.05 Mt of CO₂ was sequestered. The first phase of injection was terminated due to a sustained increase in downhole pressures. A second phase of injection was initiated into the Stø Reservoir in mid-2011, and by the end of 2012, approximately 0.5 Mt of CO₂ had been injected. The results were consistent with expectations, with no significant increase in downhole pressures. The results of the second phase of injection were in line with expectations, with no significant increase in downhole pressure. By the end of 2017, nearly 5 Mt of CO₂ had been successfully injected into the subsurface [43,67].

2.3.2. Geological Information

The Tubåen aquifer is approximately 45~75 m thick and lies below Stø Fm at a depth of 2600 m. The Tubåen Formation is a deltaic to fluvial sandstone sequence deposited in the Early Jurassic that forms highly permeable channels and bars interbedded with siltstone and mudstone. This is overlain by the mud-rich Nordmela Formation, which is capped by the Stø Formation (Early to Middle Jurassic), which was deposited in a shallow marine environment. The Nordmela Formation is sandwiched between the Tubåen and Stø Formations, and the shale-gas-rich Nordmela Formation serves as a CO₂ storage cap. The Nordmela Formation cap layer is 60~100 m thick (east to west), with an average porosity of 13% and an average permeability of 1~23 mD, as shown in Figure 13 [33,57].

The Tubåen is dominated by sandstones, with secondary shales, and contains less coal, with porosity and permeability of 10~15% and 185~883 mD, respectively, reservoir pressures and temperatures of 285 bar and 98 °C, respectively, and aquifer salinities measured at ~160 g/L. The Stø Reservoir is located at a depth of ~2450 m, and has a thickness of typically 85 m. It consists of mainly shallow marine deposits, which are generally less heterogeneous than the Tubåen Formation. It consists mainly of shallow marine sediments and has significantly less stratigraphic heterogeneity than the Tubåen Formation. Logging records show that the Stø Formation has porosity up to 20% and permeability of about 500~700 mD [63].

2.3.3. Injection Information

CO₂ is compressed to 80~140 bar at an onshore LNG plant and then transported offshore through a 153 km long 8-inch pipeline. The injected gas consists mainly of CO₂ (99.8%) and traces of methane and heavy alkanes [69]. Subsea injection was carried out via a subsea template and a near-straight well, originally with three injection zones covering 30 m of the 110 m thick Tubåen Formation. The injection zones were located below the reservoir water layer, near the edge of the gas field. Frequent injection stops produced a unique time sequence of pressure rises and falls, as shown in Figure 14 [68].

The location of the injection well (7121/4-F-2H, or F2H) was selected based on preliminary reservoir simulations conducted by Statoil. The target Tubåen Formation consists of five sand sections of varying reservoir quality: Tubåen 1 (bottom), Tubåen 2, Tubåen 3, Tubåen 4-1, and Tubåen 4-2. As shown in Figure 15, the middle and lower part of Tubåen (Tubåen 1 to Tubåen 3) has been perforated for CO₂ injection. However, the permeability of the lowest Tubåen 1 unit is significantly higher, mainly in the range of 1~4 D, sometimes as high as 12 D. Approximately 80% of the injected CO₂ migrates vertically into this layer [70,71].

During the early stages of injection, the project encountered injectability problems, marked by a sharp pressure increase during the early injection phase [72]. This rapid increase in pressure was mainly due to the low permeability of the reservoir in the near-well zone, while the early pressure rise was caused by salt precipitation near the injector. To solve this problem, the project took the measure of downhole MEG washing. Injection into the Tubåen Formation was limited due to the non-homogeneous nature of the reservoir and the compartmentalization between reservoirs, resulting in higher than expected pressure elevations during operations, as shown in Figure 14 [68]. Over a period of three years, the pressure rose from an initial near-hydrostatic 300 bar (estimated for the Tub Formation based on pressure gauge data) to about 370 bar or so, only 20 bar below the estimated rupture pressure. During this period, some brief pressure drops corresponded to periods of suspended injection. As the pressure continued to increase close to the rupture pressure, the well was sealed above the injection hole in the Tub Formation. Despite the completion of Phase 1 injection operations, it is clear that the total storage capacity of the Tubåen Formation has not reached the expected level. This suggests that the injection process may require further optimization of the operational strategy to improve the storage effect [33].

2.3.4. Monitoring

A pre-injection baseline 3D seismic reflection survey was carried out at the Snøhvit project in 2003, and several 3D surveys were carried out in 2009, 2011, and 2012. As shown in Figure 16, the upper figure highlights the geological structure of the Snøhvit area, and the lower figure presents the stratigraphic changes from 2003 to 2009 and after 2009 using difference data [73].

Seismic monitoring as of 2012 shows that the Phase II injection has injected approximately 0.55 Mt of CO₂ into the subsurface reservoir through a single shot hole, and that the injected CO₂ has spread radially outward from the wellbore to form a conical plume. As shown in Figure 17, the top panel illustrates the difference in delay between the two seismic surveys, and the bottom panel is from the 2003 survey [73]. The black lines indicate the top and bottom of the reservoir, the blue vertical lines indicate the injection wells, and the injected areas are marked with red arrows; these monitoring data provide important information for understanding the propagation of CO₂ through the formation [71].

2.3.5. Simulation

A long-term simulation was conducted at Snøhvit that covered 30 years of supercritical CO₂ injection and subsequent CO₂ storage in the Tub Formation for up to 5000 years. The results of the simulation, without pressure constraints, showed that the pressure reached ~543 bar at the end of the 5000 years simulation (Figure 18a). However, it is noteworthy that the pore bottom pressure rises to extremely high levels, reaching 815 bar at the end of the injection. Considering that 23 Mt of CO₂ are planned to be injected in 30 years, which corresponds to about 1.2 × 10¹⁰ m³ in the standard state, this rate of injection is infeasible, as the pressure rises to a level significantly higher than the fracture pressure.

Fracture pressure varies from formation to formation and also from depth to depth. Based on the fracture pressure data for the Snøhvit field formations, the average bottomhole pressure at the depth of injection is about 440 bar. If this value is taken as the maximum allowable bottomhole pressure and the injection rate is reduced when this value is reached, the amount of CO₂ that can be injected over a 30-year period will be significantly reduced. As can be seen from the BHP (bottomhole pressure) constraints in Figure 18, the amount of CO₂ injected is significantly reduced to only one-third of the planned amount. This highlights the importance of more careful management and control of the injection process to ensure the feasibility and safety of CO₂ injection [70].

Figure 19 shows the distribution of the CO₂ plume in terms of moles of CO₂ per rock unit after 30 years of injection and 5000 years of sequestration. After 5000 years, some of the CO₂ has reached the caprocks and has the potential to penetrate the caprocks.

3. Revelations and Outlook

3.1. Implications

When looking at the Sleipner and Snøhvit projects in Norway and the Tomakomai project in Japan, we can draw the following more detailed insights:

Impact of geological features on storage safety: The geological features of these projects have had a significant impact on the safety of CO₂ storage. Sleipner selected a large sedimentary body with a local tectonic setting and a stable distribution, while Snøhvit’s previous selection of reservoirs, with poor physical properties and small volumes, led to a rapid build-up of pressure and limited injection. Tomakomai faced challenges such as rising water tables and complex subsurface geological formations. These experiences show that when selecting a storage site, it is important to take into account the stability and suitability of the geological conditions to ensure the safety and long-term stability of the storage process.

Operations management and technology innovation: These projects have achieved a number of successes in terms of operational management and technological innovations. The Sleipner project has become a global pioneer in the field of storage by effectively reducing greenhouse gas emissions through the implementation of CO₂ capture and storage technology. The Snøhvit project has provided valuable experience in marine storage technology through the delivery of CO₂ through pipelines and subsea injection. The Tomakomai project has adopted innovative measures such as dual-mode wells and formation water production to effectively reduce formation pressure and improve the efficiency of CO₂ storage. These experiences show that operation management and technological innovation are important factors in guaranteeing the successful implementation and long-term operation of storage projects, and that future projects will need to continue to promote technological innovation and improve operation and management in order to cope with challenges and problems.

Monitoring system and risk management: These projects have established a comprehensive monitoring system, which can identify and solve potential problems in a timely manner and ensure the safety and stability of the storage process. The Sleipner project has realized comprehensive monitoring of the storage process by monitoring the underground CO₂ storage volume and injection efficiency. The Snøhvit project monitors the injection of CO₂ by means of seismic surveys and time-delayed seismic data, which provides a basis for CO₂ propagation in the formation. Tomakomai project reduced the formation pressure and the risk of CO₂ leakage by optimizing the wellbore arrangement and injection strategy. These experiences show that the establishment of a sound monitoring system and risk management mechanism is crucial to the successful implementation of a storage project, and future projects should strengthen the research and development and application of monitoring technologies to improve the ability to identify and respond to potential risks.

By summarizing these more detailed revelations, we can gain a deeper understanding of the key success factors and challenges of marine saline CO₂ storage projects. These insights provide important lessons learned and guiding principles for the planning and implementation of similar projects in the future, helping to ensure the safety, feasibility, and sustainability of storage technologies.

3.2. Outlook

Overall, despite the achievements of the Sleipner, Snøhvit, and Tomakomai projects in CO₂ storage technology, there are still a number of technical issues that need to be addressed.

The current operating cost of CO₂ sequestration is still high. Future research should be devoted to technological innovations, such as the development of more efficient CO₂ capture technologies, methods to improve injection efficiency, and novel engineering solutions to reduce storage costs. At the same time, the economic viability of different storage technologies needs to be further studied and evaluated to ensure the sustainability of CO₂ storage projects. It is important to determine the cost curves involved in the entire storage chain, such as the geographical relationship between CO₂ sources and storage sinks. This will play a key role in decision-making, especially during large-scale CCUS deployments. Prior to deploying a storage technology, it is important to identify key storage site assessment criteria in order to assess whether the technology is credible, safe, secure, reliable, trustworthy, environmentally friendly, and economically viable. The identification of key evaluation criteria and recommendations during the site evaluation process should provide clear inputs for cost–risk–investment business decisions. The study of siting and evaluation criteria for CO₂ storage in geological formations emphasized that the main criteria to be considered are geology, geothermal, geohazards, hydrodynamics, hydrocarbon potential, and basin maturity, as well as economic, social, and environmental issues.

On the basis of circling the target area for carbon sequestration, it is proposed to implement a demonstration project for marine geological carbon sequestration in cooperation with enterprises, so as to realize the technical demonstration of the whole process of carbon capture, transportation, injection, and monitoring. Deeply excavate the geological support in the process of marine geological carbon storage, plan ahead, and form a technical reserve in the delineation of the target area, site selection, routing construction, environmental monitoring, etc., so as to lay a foundation for the development of global marine geological carbon storage work.

In order to better evaluate the integrity of faults and cap layers, especially in deep saline aquifer, models with higher performance than the existing ones are needed to establish and calibrate 3D pre- and post-injection simulations of reservoir geomechanics. These models should account for critical pore pressures for fault activation. And it is necessary to demonstrate the stability of the borehole seals over the longer term, since their failure will control CO₂ leakage regardless of the quality of the cap layer. It will also be necessary to demonstrate the ability to remediate in the unlikely event of a well leak.

CO₂ sequestration projects may have certain impacts and risks to groundwater quality, geologic formation stability, and ecosystems. Therefore, future research should strengthen the assessment of environmental impacts and ecological risks of CO₂ storage projects, and carry out appropriate monitoring and management work to minimize adverse impacts on the environment and ecosystems.

Successful implementation of CO₂ storage projects depends not only on technological sophistication, but also requires broad support from the public and policy makers. Further progress is needed in the area of CCUS legislation, and communities living near CO₂ storage sites need to become participants in CCUS projects, rather than being seen as passive bystanders with no stake in what is going on. Ignoring these lessons can lead to strong resistance that is enough to hinder local programs and give CCUS a bad name nationally. Therefore, future research should focus on how to increase social acceptance of CO₂ storage technology and develop appropriate policy measures to support the development of CO₂ storage programs. This includes strengthening public education and awareness-raising to increase social recognition and acceptance of CO₂ storage technology; formulating sound laws, regulations, and policy measures to provide policy support and legal protection for CO₂ storage projects; and establishing a multi-stakeholder cooperation mechanism to facilitate the participation and collaboration of all parties to jointly promote the implementation and development of CO₂ storage projects.

CO₂ storage is a global challenge that requires the joint efforts and cooperation of the international community. Future research should strengthen international cooperation and exchanges, share experiences and lessons learned from CO₂ storage projects, and work together to solve common problems in technology, policy, and management. This includes the establishment of an international cooperation mechanism, the promotion of transnational project cooperation, and the strengthening of the coordination and support of international organizations.

Through detailed consideration and planning of these aspects, more comprehensive and effective guidance can be provided for the planning and implementation of future CO₂ sequestration projects, which will promote the further development and application of CO₂ sequestration technology and make a greater contribution to the realization of the global goal of net-zero emissions.

4. Conclusions

This study provides an in-depth analysis of the Sleipner and Snøhvit projects in Norway and the Tomakomai project in Japan, and summarizes their key experiences and lessons learned in the field of CO₂ storage. Based on our review, the following conclusions can be drawn:

The technology of CO₂ storage in saline aquifers has significant potential in addressing climate change and achieving carbon reduction, especially in the context of the growing global focus on climate issues.

While CO₂ storage technology still presents challenges at the technical level, public acceptance is a crucial factor. Successful experiences from existing projects show that comprehensive site evaluation and continuous monitoring are crucial to project stability.

To facilitate the future development of the technology, focus needs to be placed on technological innovation, the development of diversified storage options, and social and policy support to ensure the sustainability and broad application of CO₂ storage technology.

International cooperation plays an important role in promoting CO₂ storage technology in marine saline aquifers. Governments, scientific research institutions, and relevant organizations should further strengthen their collaboration to jointly promote research and development of the technology and achieve global carbon emission reduction targets.