Long distance migration assisted structural trapping during CO₂ storage in offshore basin

Abstract

Long-distance migration-assisted structural trapping represents an optimal configuration for offshore geological CO₂ storage. In this study, the trapping efficiency of CO₂ was quantitatively analyzed using CMG software, taking into account aqueous solubility and geochemical reactions. The investigation focused on CO₂ migration behavior, mineralogical changes, pH and porosity variations induced by geochemical processes, and their respective contributions to overall carbon storage. Simulation results show that CO₂ tends to accumulate near the injection wells and subsequently migrates upward along the slightly dipping strata due to density differences between CO₂ and formation brine. After the injection wells are shut in, the CO₂ plume continues to migrate up-dip toward the crest of the anticline structure. A substantial portion of CO₂ remains trapped in the dipping strata due to capillary pressure hysteresis. As CO₂ dissolves into the saline aquifer, it generates H⁺ ions, which promote the dissolution of anorthite, releasing Ca²⁺ and Al³⁺ necessary for the precipitation of calcite and kaolinite over time. Results indicate that kaolinite and calcite predominantly precipitate within the aqueous phase, while anorthite is continuously dissolved throughout the simulation. The interplay of mineral dissolution and precipitation dynamically alters both pH and porosity. Anorthite is not the sole source of Ca²⁺; minerals such as dolomite and limestone can also readily contribute to Ca²⁺ availability, depending on the rock’s mineral composition. A localized pH decrease is observed along the CO₂ migration pathway. Porosity slightly decreases in the near-well zone but increases in the structurally elevated areas. The proportion of structurally trapped CO₂ increases during the injection phase but decreases during the subsequent long-distance migration phase. Residual gas trapping exhibits an initial rise followed by a decline, driven by capillary pressure hysteresis. Overall, the mechanism of long-distance migration-assisted structural trapping significantly enhances the long-term security and effectiveness of CO₂ geological storage.

Introduction

Human development is facing a hotspot issue called global climate change that is being increasingly noticed by all sectors of society^1,2,3. Anthropogenic climate forcing has led to a measurable rise in global average temperatures, making climate change a shared responsibility for all humanity. In the past six meetings of the IPCC, it has become apparent that human activities are significantly contributing to and impacting climate change. Global emissions must reach net-zero by mid-century to limit warming to 1.5 °C⁴. Changes in ecosystem structure and function will be caused by land use change, which will impact carbon emission and carbon sink processes⁵. The World Meteorological Organization (WMO) has officially confirmed that 2023 is the warmest year in the 174-year observational record. Extreme weather events are occurring more frequently, making it one of the main challenges for the next 10 years. Preventing the serious consequences caused by global warming, cooperations between governments, businesses, communities, and individuals are essential for reducing greenhouse gases (GHGs). Carbon Capture and Storage (CCS) has emerged as a key strategy capable of reducing point-source CO₂ emissions from industrial and energy sectors while supporting the transition to a low-carbon economy.

Geological carbon storage (GCS) is considered to be a vital strategy for reducing GHGs emissions and mitigating global warming. The concept of GCS involves capturing CO₂ from industrial sources and injecting them into deep formation for long-term storage. Among the diverse geological formations available for GCS, saline aquifer, oil and gas reservoir, basalt, coal seam, shale reservoirs are emerged as promising candidates due to their unique storage characteristics^6,7,8. Deep saline aquifers offer substantial storage capacity due to their high porosity and permeability, which are widespread in onshore and offshore sedimentary formations (Fig. 1). The carbon storage capacity differs considerably across different regions, with North America, Russia, Africa, and Australia holding substantial carbon storage capacity. The total global estimated carbon storage capacity, both onshore and offshore, is between 8000 Gt and 55000 Gt. It is estimated that the offshore carbon storage capacity is between 2000 Gt and 13000 Gt^{9,10,11,12,13}.

Fig. 1

Global theoretical CO₂ storage capacity by region. Data source: CCUS in Clean Energy Transitions (Map generated using Coreldraw Graphics Suite 2018, https://www.coreldraw.com/cn/).

Government CCS policies are instrumental in driving promoting and accelerating the implementation of the CCS projects. The United States Department of Energy has been actively involved in projects related to geological carbon storage in offshore basins, promoting and assessing a subsurface geologic CO₂ storage complex offshore in Corpus Christi, Texas¹⁴. DOE is executing through the Carbon Storage Assurance Facility Enterprise (CarbonSAFE) program to support commercial-scale deployment of safe and durable geologic storage of captured CO₂. The U.S. Department of Energy’s Office of Fossil Energy (FE) has funded two projects to receive $8 million to advance the development and validation of CO₂ storage technology in offshore Gulf of Mexico. Northern Lights Project (Norway) is a collaborative endeavor led by Shell, TotalEnergies and Equinor to form a full-scale CCS chain for capturing and storing CO₂ on the Norwegian Continental Shelf in Europe¹⁵. Sleipner CCS Project (Norway) is operated by Equinor, involving capturing CO₂ from natural gas production at Sleipner oil field and injecting it into the deep saline aquifer in the North Sea¹⁶. Tomakomai CCS Demonstration Project (Japan) aims to transport the captured CO₂ via pipeline to offshore injection wells in the Tomakomai area of Hokkaido¹⁷. Quest CCS Project, located at the Scotford upgrader near Edmonton, Alberta, cuts down about one-third of direct CO₂ emissions from industrial sources¹⁸. Petra Nova Project (USA), attached to a coal-fired power plant near Houston, adopts the captured CO₂ for enhanced oil recovery (EOR)¹⁹. The Chevron-operated Gorgon Project, located on Barrow Island, captures CO₂ from natural gas processing and stores it underground²⁰. The deployment of onshore and offshore CCS projects in China is navigated by the National Energy Administration (NEA) and the Ministry of Ecology and Environment (MEE), examining the challenges, opportunities and implications for CO₂ storage. China has been actively involved in onshore carbon capture and storage (CCS) projects, such as Shenhua Group CCS Project, PetroChina CCS Project, Sinopec CCS Project, Nanjing CCS Project and GreenGen CCS Project. The EnPing CCS project, China’s first offshore CCS demo project, aimed to establish an offshore industrial-scale carbon capture and storage chain. The EnPing CCS project has an annual storage capacity of 300,000t CO₂, storing CO₂ in a saline aquifer at depths of 830–920 m.

In addition to saline aquifer, basaltic rocks and organic-rich shales have recently displayed great potential for permanent immobilization of CO₂²¹. Basalt is a rock type rich in minerals such as olivine and pyroxene, which contain significant amounts of Ca, Mg, and Fe. These elements contribute to the precipitation of carbonate minerals including calcite, magnesite, siderite, aragonite, ankerite, and dolomite^22,23. The reaction between basalt and CO₂ is rapid, and 95% of the injected CO₂ is mineralized in less than 2 years of the initial CO₂ injection in Iceland²⁴. Apart from the basalt utilized in the Carbfix project, it has been documented that CO₂–H₂O mixtures were permitted to react with the basalt in Columbia River, Central Atlantic Mafic, Newark Basin, Karoo, and Deccan basalt^25,26,27,28. Coal permeability is the key parameter influencing the efficiency of enhanced coalbed methane recovery with CO₂ sequestration, and there is an association between CO2 adsorption and the strength of the coal^29,30. Nonetheless, not all porous reservoir can be suited for permanent carbon storage, and some may lack the requisite storage conditions, caprock sealing, or trapping mechanisms.

There are four classical CO₂ trapping mechanisms: structural or stratigraphic, residual gas, solubility and mineral trapping^{31,32,33,34,35}. Structural trapping refers to the injected CO₂ is stored below a non-permeable caprock, suitable for storing large volume of CO2 safely. Residual gas trapping illustrates that the injected CO₂ is being trapped in the smaller pore spaces of the reservoir due to capillary forces³⁶. Solubility trapping means injected CO₂ being dissolved in saline aquifer, and CO₂ becomes less buoyant and is less likely to migrate upward³⁷. Mineralization or mineral carbonation refers that CO₂ reacts with minerals to form stable carbonate minerals underground. The wetting behavior of caprocks for CO₂-brine systems is a crucial physicochemical factor influencing the structural trapping capacity³⁸. Carbon storage efficiencies are influenced by factors such as reservoir temperature, caprock properties, wettability, vertical to horizontal permeability ratio, heterogeneity, and injection well configuration^39,40. Many previous studies have extensively investigated the effect of the geological heterogeneity on CO₂ dissolution efficiency. In general, structural trapping is the predominant mechanism and is essential for geological sequestration. In basalt formations, mineral trapping serves as an effective mechanism for long-term CO₂ immobilization^24,41,42. Homogeneous and heterogeneous porous media laboratory experiments are adopted to investigate the convective mixing driven by gravitational instabilities, and connective mixing is the dominant trapping mechanism in reservoir with medium and high permeabilities³⁴. Quantifying capillary pressure and thermal effects via high-resolution simulations show that the presence of the capillary zone can significantly reduce the onset time and enhance dissolution rate⁴³. Darcy-scale multiphase flow experiments were used by Kim et al.⁴⁴ to obtain CO₂ saturation during both drainage and imbibition, and capillary heterogeneity becomes more significant with higher initial CO₂ saturations. The impacts of reservoir heterogeneities on geological carbon storage capacity and the migration of the CO₂ plume were examined. heterogeneously distributed wettability and higher temperature accelerated the vertical CO₂ migration significantly and reduced storage capacity⁴⁵. Their findings suggested that the heterogeneously distributed wettability and higher temperature could accelerate the vertical CO₂ migration and reduce storage capacity. By controlling the injection rate or alternating water and CO₂ injection, capillary trapping enhanced to improve to the storage efficiency of the carbon project⁴⁶. Additionally, mineral sequestration is the result of the interactions among rock, fluids, and CO₂, encompassing geochemical reactions of reservoir minerals like calcite, dolomite, siderite, etc^47,48,49,50. A numerical sensitivity analysis of the CO₂ mineralization trapping mechanism is adopted to investigate the efficiency of carbon mineralization and geochemical-induced alterations resulting from mineralization trapping⁵¹. Solubility and mineral trapping mechanisms are intricately interconnected, and the solubility of CO₂ in brine affects the mineral trapping^52,53. Although several studies have explored the traditional four trapping mechanisms, there are very limited researches regarding quantitative analysis of each mechanism during GCS.

Notable CCS examples and highlight the maturity of CCS technologies and provide valuable experience for developing similar systems in offshore basins such as the Wushi Basin in China. The main objective of this investigation aims to reveal the carbon trapping mechanism of long-distance migration assisted structural trapping during CO₂ storage in offshore basin. This study focuses on aqueous solubility, geochemistry reactions within the gas/brine system and storage contribution of each trapping mechanism. A stratified offshore formation was taken into account, and the influences of both dissolution and precipitation of the minerals on CO₂ storage were analyzed during the simulation. CO₂ migration, spatial distributions of ions and minerals, and storage contribution of each trapping mechanism are examined in Wushi basin.

Materials and methods

CO₂ solubility

Peng–Robinson equation of state (PR-EOS) was adopted to calculate the gas fugacity of component⁵⁴. Henry’s Law is adopted to model the solubility in the aqueous phase, and the fugacity formula is:

$$\text{f}=\text{x}*\text{H}$$

(1)

where $\:f$ is the fugacity of the component, $\:x$ composition of the component in the aqueous phase and $\:H$ Henry’s Law constant (atm L/mol).

Henry’s Law constant, at any pressures, $\:p$, is calculated as follows:

$$\:ln\left(H\right)=ln\left({H}^{\text{*}}\right)+v(p-{p}_{ref})/RT$$

(2)

where $\:H$ is the Henry’s Law constant (atm L/mol), $\:{H}^{*}$ the Henry’s Law constant at reference pressure (often 1 atm), $\:v$ partial molar volume of the dissolved gas (m³/mol), $\:R$ universal gas constant (8.314 J mol⁻¹K⁻¹), $\:T$ absolute temperature (K) and $\:{p}_{ref}$ the reference pressure (MPa).

Gas relative permeability

The assumption is that the saline aquifer is nearly fully saturated with brine and contains a negligible concentration of a trace gas⁵⁴. Achieving convergence in the simulator requires incorporating a minimal representation of residual gas to account for fluid compressibility⁵⁵. Methane was selected as the trace gas in the CMG simulator, and the component of the fluid (CO₂, CH₄, H₂O) were modeled using the Peng–Robinson equation of state (PR-EOS)⁵⁶.

The required solubility parameters were calculated based on the investigation conducted by Li and Nghiem, and then added to the CO₂ and CH₄ components⁵⁷. The gas and aqueous phases are in thermodynamic equilibrium, and the fugacity formula is:

$$\:{f}_{i}^{g}-{f}_{i}^{w}=0,\:\:\:i=1,\dots\:,{n}_{g}$$

(3)

where $\:{f}_{i}^{g}$ is the fugacity of the $\:i$ component in gas state, atm; $\:{f}_{i}^{w}$ is the fugacity of the $\:i$ component in aqueous state; $\:{n}_{g}$ is the number of gaseous components, atm.

Due to wettability and capillary effects, the flow dynamics of CO₂ is path-dependent when passing through a water-wet reservoir⁵⁸. The amount of CO₂ that could be extracted from the reservoir is less than the volume of CO₂ injected and absorbed by the reservoir. The extractable CO₂ from the reservoir is estimated to be approximately 20–25% of the total injected CO₂, while the remaining 75–80% is retained within the formation through residual gas trapping, dissolution, and mineralization processes. The imbibition process will start when CO₂ injection stops, leading to the saturation of residually trapped gas⁵⁹. The reservoir will experience a conventional drainage process, leading to an increase in gas saturation until it reaches the maximum level⁶⁰. The relative permeability of CO₂ (K_rg) versus gas saturation (S_g) is shown in Fig. 2. The corresponding residually trapped gas saturation is calculated by the following equation⁶¹:

$$\:{S}_{gt}={S}_{gcrit}+\frac{{S}_{g,max}-{S}_{gcrit}}{1+C\cdot\:\left({S}_{g,max}-{S}_{gcrit}\right)}$$

(4)

where $\:{S}_{gt}$ is the residually trapped gas saturation; $\:{S}_{gcrit}$ is the critical gas saturation; $\:{S}_{g,max}$ is maximum gas saturation when the transition to drainage takes place; $\:C$ is the Land parameter.

Fig. 2

K_rg vs. S_g during gas injection and after injection.

Mineral dissolution and precipitation reactions

The rate of mineral reaction in the solution is represented as rate-dependent reactions^61,62:

$$\:{r}_{j}={\widehat{A}}_{j}{k}_{j}\left(1-\frac{{Q}_{j}}{{K}_{eq,j}}\right),\:\text{j}=1,\dots\:,{R}_{mn}$$

(5)

where $\:{r}_{j}$ is the rate of j-th mineral reaction, mol/s; $\:{\widehat{A}}_{j}$ is the reactive surface area for j-th mineral, m²; $\:{k}_{j}$ is the rate constant of mineral reaction, mol/s/m²; $\:{K}_{eq,j}$ is the chemical equilibrium constant for mineral reaction; $\:{Q}_{j}$ is the activity product of the aqueous reaction.

The saturation index is $\:{Q}_{j}/{K}_{eq,j}$, determining the direction of the mineral reaction. Precipitation reaction occurs if saturation index is greater than 1, and dissolution reaction occurs if saturation index is less than 1.

The rate constant of mineral reaction is calculated at a reference temperature, $\:{T}_{0}$⁶²:

$$\:{k}_{\beta\:}={k}_{0\beta\:}exp\left[-\frac{{E}_{a\beta\:}}{R}\left(\frac{1}{T}-\frac{1}{{T}_{0}}\right)\right]$$

(6)

where $\:{k}_{0\beta\:}$ is the rate constant for reaction $\:\beta\:$ at $\:{T}_{0}$; $\:{E}_{a\beta\:}$ the activation energy of the mineral reaction $\:\beta\:$, J/mol; $\:R$ is the universal gas constant, 8.314 J$\:\cdot\:$K⁻¹$\:\cdot\:$mol^{− 1}; $\:T$ is the temperature, K.

The reactivate surface area of the j-th mineral reaction is obtained⁶²:

$$\:{\widehat{A}}_{j}={\widehat{A}}_{j}^{0}\cdot\:\frac{{N}_{j}}{{N}_{j}^{0}}$$

(7)

where $\:{\widehat{A}}_{j}^{0}$ is the reactive surface area at the initial time, $\:{N}_{j}$ the mineral mole number per unit grid block volume at current time, and $\:{N}_{j}^{0}$ the mineral mole number per unit grid block volume at initial time.

With mineral dissolution and precipitation, the Kozeny-Carman equation is used to calculate the absolute permeability⁶²:

$$\:\frac{k}{{k}_{0}}={\left(\frac{\phi\:}{{\phi\:}_{0}}\right)}^{3}\cdot\:{\left(\frac{1-{\phi\:}_{0}}{1-\phi\:}\right)}^{2}$$

(8)

where $\:{k}_{0}$ and $\:{\phi\:}_{0}$ are the initial permeability and porosity, respectively.

CO₂ trapping calculations

Trapping efficiency is expressed as the percentage of total injected CO₂, and the formulas below were adopted:

$$\:\text{S}\text{t}\text{r}\text{u}\text{c}\text{t}\text{u}\text{r}\text{a}\text{l}\:\text{T}\text{r}\text{a}\text{p}\text{p}\text{i}\text{n}\text{g},\text{\%}=\frac{\text{S}\text{u}\text{p}\text{e}\text{r}\text{c}\text{r}\text{i}\text{t}\text{i}\text{c}\text{a}\text{l}\:\text{P}\text{h}\text{a}\text{s}\text{e}-\text{T}\text{r}\text{a}\text{p}\text{p}\text{e}\text{d}\:\text{S}\text{g}\:<\:\text{S}\text{g}\text{c}\:/\:\text{H}\text{y}\text{s}\text{t}\text{e}\text{r}\text{e}\text{s}\text{i}\text{s}\:}{\text{C}\text{u}\text{m}\text{u}\text{l}\text{a}\text{t}\text{i}\text{v}\text{e}\:{\text{C}\text{O}}_{2}\:\text{i}\text{n}\text{j}\text{e}\text{c}\text{t}\text{e}\text{d}\:}\times\:100\text{\%}$$

(9)

$$\:\text{R}\text{e}\text{s}\text{i}\text{d}\text{u}\text{a}\text{l}\:\text{G}\text{a}\text{s}\:\text{T}\text{r}\text{a}\text{p}\text{p}\text{i}\text{n}\text{g},\text{\%}=\frac{\text{T}\text{r}\text{a}\text{p}\text{p}\text{e}\text{d}\:\text{S}\text{g}\:<\:\text{S}\text{g}\text{c}\:/\:\text{H}\text{y}\text{s}\text{t}\text{e}\text{r}\text{e}\text{s}\text{i}\text{s}\:}{\text{C}\text{u}\text{m}\text{u}\text{l}\text{a}\text{t}\text{i}\text{v}\text{e}\:{\text{C}\text{O}}_{2}\:\text{i}\text{n}\text{j}\text{e}\text{c}\text{t}\text{e}\text{d}\:}\times\:100\text{\%}$$

(10)

$$\:\text{D}\text{i}\text{s}\text{s}\text{o}\text{l}\text{v}\text{e}\text{d}\:\text{T}\text{r}\text{a}\text{p}\text{p}\text{i}\text{n}\text{g},\text{\%}=\frac{\text{D}\text{i}\text{s}\text{s}\text{o}\text{l}\text{v}\text{e}\text{d}\:\text{i}\text{n}\:\text{W}\text{a}\text{t}\text{e}\text{r}\:}{\text{C}\text{u}\text{m}\text{u}\text{l}\text{a}\text{t}\text{i}\text{v}\text{e}\:{\text{C}\text{O}}_{2}\:\text{i}\text{n}\text{j}\text{e}\text{c}\text{t}\text{e}\text{d}\:}\times\:100\text{\%}$$

(11)

$$\:\text{M}\text{i}\text{n}\text{e}\text{r}\text{a}\text{l}\:\text{T}\text{r}\text{a}\text{p}\text{p}\text{i}\text{n}\text{g},\text{\%}=\frac{\text{P}\text{r}\text{e}\text{s}\text{e}\text{n}\text{t}\:\text{i}\text{n}\:\text{A}\text{q}\text{u}\text{e}\text{o}\text{u}\text{s}\:\text{I}\text{o}\text{n}\text{s}+\text{P}\text{r}\text{e}\text{s}\text{e}\text{n}\text{t}\:\text{i}\text{n}\:\text{M}\text{i}\text{n}\text{e}\text{r}\text{a}\text{l}\:\text{P}\text{r}\text{e}\text{c}\text{i}\text{p}\text{i}\text{t}\text{a}\text{t}\text{e}\:}{\text{C}\text{u}\text{m}\text{u}\text{l}\text{a}\text{t}\text{i}\text{v}\text{e}\:{\text{C}\text{O}}_{2}\:\text{i}\text{n}\text{j}\text{e}\text{c}\text{t}\text{e}\text{d}\:}\times\:100\text{\%}$$

(12)

Structural trapping refers to the capture of CO₂ within the pores of porous media and depends on the supercritical phase of CO₂. Residual gas trapping usually occurs when the pressure drops below the critical pressure of CO₂, and CO₂ gas cannot be completely expelled from the pores and is thus “trapped”. Dissolved trapping refers to CO₂ dissolving in water to form carbonic acid, thereby being fixed. Mineral trapping refers to CO₂ undergoing a chemical reaction with minerals in the rock to form stable minerals, thereby being permanently fixed underground.

Geometric model

Wushi basin, located along the southern shoreline of Guangdong Province of China, is an offshore oil and gas field (Fig. 3). Wushi oil field is developed by CNOOC in co-operation with UK based Cairn Energy under a Production Sharing Contract. The target CO₂ injection formation for this investigation is Xiayang group. The Xiayang Formation has a sedimentary thickness of 50 to 150 m and is widely distributed across the Wushi Sag. Its strong lateral continuity supports large-scale CO₂ storage and promotes the formation of a stable reservoir–caprock sealing system. The Xiayang Formation primarily consists of medium- to coarse-grained sandstones, deposited in relatively high-energy environments, which contributed to the development of well-connected pore structures. Core analyses show that the formation has a porosity of 12–20% and a permeability of 100–800 mD, offering favorable pathways for CO₂ injection and migration. The Computer Modeling Group (CMG) software was adopted to construct the 3D long-distance migration assisted structural trapping model comprising 113*47*60 grid blocks, and the permeability of the multilayered reservoir was calculated by the Sequential Gaussian Simulation method, using SGSIM code (Fig. 4). There are four CO₂ injectors and one water injector, and the water perforation location is situated higher than the CO₂ perforation location (Fig. 5).

Fig. 3

Location of the Wushi Basin (Map generated using Coreldraw Graphics Suite 2018, https://www.coreldraw.com/cn/).

Fig. 4

3D model of CO₂ injection in Wushi Basin.

Fig. 5

Sketch of CO₂ and water perforation locations.

Geochemistry system

The static grid model parameters and reservoir parameters are given in Table 1.

Table 1 Summary of the parameters adopted for CO₂ injection.

There are three solubility reactions and three liquid-mineral reaction in the geochemistry system:

$${{\text{H}}_{\text{2}}}{\text{O}} \Leftrightarrow {{\text{H}}^+}+{\text{O}}{{\text{H}}^ - }$$

(13)

$${\text{C}}{{\text{O}}_{\text{2}}}\left( {{\text{aq}}} \right)+{{\text{H}}_{\text{2}}}{\text{O}} \Leftrightarrow {{\text{H}}^+}+{\text{HCO}}_{3}^{ - }$$

(14)

$${\text{HCO}}_{3}^{ - } \Leftrightarrow {{\text{H}}^+}+{\text{C}}{{\text{O}}_{{\text{2}} - {\text{3}}}}$$

(15)

$${\text{Calcite}}\,+\,{{\text{H}}^+} \Leftrightarrow {\text{C}}{{\text{a}}^{{\text{2}}+}}+{\text{HCO}}_{3}^{ - }$$

(16)

$${\text{Anorthite}}\,+\,{\text{8}}{{\text{H}}^+} \Leftrightarrow {\text{C}}{{\text{a}}^{{\text{2}}+}}+{\text{2A}}{{\text{l}}^{{\text{3}}+}}+{\text{ 2Si}}{{\text{O}}_{\text{2}}}\left( {{\text{aq}}} \right)\,+\,{\text{4}}{{\text{H}}_{\text{2}}}{\text{O}}$$

(17)

$${\text{Kaolinite}}\,+\,{\text{6}}{{\text{H}}^+} \Leftrightarrow {\text{2A}}{{\text{l}}^{{\text{3}}+}}+{\text{2Si}}{{\text{O}}_{\text{2}}}\left( {{\text{aq}}} \right)\,+\,{\text{5}}{{\text{H}}_{\text{2}}}{\text{O}}$$

(18)

The composition of the formation initial water condition is in Table 2. The chemical equilibrium constants for the three aqueous reactions are given in Table 3. The fundamental issue of concern revolves around the combined injection of CO₂ and water in the simulation. CO₂ is injected at a constant rate of 20000 m³/day under standard surface gas rate with a maximum bottom-hole pressure of 44500 kPa for first 200 years (2030–2230). Water is injected at a constant rate of 25 m³/day for 100 years (2230–2330). The simulated CMG case are listed in Table 4. The rate constants and activation energies for calcite, anorthite, and kaolinite reactions (Table 5) were adopted from Bethke⁶¹ and the LLNL thermochemical database⁶², which compile laboratory-derived kinetic data. These parameters were further cross-validated by reproducing mineral dissolution–precipitation trends consistent with Xu et al.⁴⁷ and Gaus et al.⁴⁹.

Table 2 Initial concentrations of the aqueous species.

Table 3 Chemical equilibrium constants for aqueous reactions.

Table 4 Injection schemes for carbon storage.

Table 5 Summary of the parameters adopted for GCS^61,62.

Results

CO₂ migration

Figure 6 displays the injection profile of the supercritical CO₂ and water throughout the simulation period. The initial well bottom-hole pressure of CO₂ injector was approximately 17.5 MPa, and it increased to about 32.5 MPa after 200 years of uninterrupted injection. After the CO₂ injection wells shut-in, the water well bottom-hole pressure was approximately equivalent to that of the CO₂ injector.

Fig. 6

Injection profile of the supercritical CO₂ and water during simulation time.

Sg (CO₂ saturation) is defined as the ratio of the volume of CO₂ to the total pore volume of the rock formation^63,64,65. Spatial distribution of CO₂ over time is shown in Fig. 7. Due to the disparity in density between the supercritical CO₂ and the aqueous phase, CO₂ with low viscosity tends to move towards the upper layers of the geological formation. Before CO₂ injection wells shut in (2230-01-01), CO₂ concentrates near the injection wells and migrates upward along the slightly dipping strata. The maximum migration distance of CO₂ plume is approximately 3.5 km. After the CO₂ injection wells shut-in, CO₂ continues to migrate 7.0 km along the dipping strata to the top anticline at the end of simulation period (9800-01-01). Due to wettability and capillary effects, certain CO₂ is still trapped in the migration area.

Fig. 7

Spatial distribution of CO₂ saturation at various simulation times for CO₂ injection.

Mineral mole changes

Figure 8 displays the variations in mineral moles of anorthite, calcite and kaolinite for the whole domain in the simulation. Negative values are commonly employed to predict dissolution, while positive numbers indicate precipitation⁶⁶. It can be observed that the kaolinite and calcite are overall precipitated in the aqueous phase while the anorthite is dissolved during the simulation. The moles changes for anorthite, calcite and kaolinite are − 4.43*1010, 4.07*1010 and 3.82*1010 at the end of the simulation, respectively. CO₂ injection altered the chemical composition of the formation water, and the continuous dissolution of anorthite throughout the whole storage period demonstrates its superior mineral trapping capacity. Furthermore, the dissolution of anorthite provided Ca²⁺ and Al³⁺ required for the precipitation of calcite and kaolinite over time. Mineral moles changes of anorthite, calcite and kaolinite (9800-01-01) are illustrated in Fig. 9, and the ion moles changes (9800-01-01) are displayed in Fig. 10. Mole change of Al³⁺ is more obvious than that of Ca²⁺ after the simulation time of 7770 years.

Fig. 8

Evolution of mineral mole changes at various times for the whole domain.

Fig. 9

Spatial distribution of mineral changes after simulation time of 7770 years.

Fig. 10

Spatial distribution of ion changes after simulation time of 7770 years.

Geochemical induced PH and porosity variations

PH and porosity variations of the reservoir model due to mineral reactions are depicted in Figs. 11 and 12, respectively. The primary factors influencing PH and porosity changes, resulting from CO₂ front propagation, are the dynamics of mineral dissolution and precipitation. As CO₂ being dissolved in the aqueous phase, there is a PH decrease in the long-distance CO₂ migration areas. Porosity is slightly reduced in the near-well region, with a modest increase observed in structurally elevated zones.

Fig. 11

PH variation at the end of the simulation for CO₂ injection (9800-01-01).

Fig. 12

Porosity variation at the end of the simulation for CO₂ injection (9800-01-01).

CO₂ storage contribution

A comparative analysis of different CO₂ phases is more accurate evaluation of CO₂ storage mechanism, evolution of CO₂ mole changes at various times is illustrated in Fig. 13. The moles of CO₂ super-critical, trapped, dissolved and aqueous ions are 10.2*10¹⁰, 3.96*10¹⁰, 6.6*10¹⁰ and 4.4*10¹⁰ at the end of the simulation, respectively.

Fig. 13

Evolution of CO₂ mole changes at various times.

CO₂ moles of structural, residual gas, solubility, ionic and mineral are displayed in Fig. 14. The proportion of structural trapping is continuously increasing during the CO₂ injection period, and 86.05% of the primary 2.482*10¹¹ moles of injected CO₂ was trapped by structural trapping (2230-01-01), as shown in Fig. 15a. Meanwhile, continuous CO₂ injection leads to a decreased percentage of solubility and residual gas trapping at the end of CO₂ injection stage. Throughout the period of CO₂ long-distance migration, residual gas trapping displays the initially increasing and then decreasing trend, as illustrated in Fig. 15b. A large amount of CO₂ is trapped due to capillary hysteresis during CO₂ migration stage. The proportion of structural trapping is continuously decreasing. Storage contributions of solubility, and ionic and mineral trapping increases with time during the CO₂ migration period. At the end of the simulation as illustrated in Figs. 16 and 25.10%, 17.37%, 26.3%, 14.82% and 16.41% of the injected CO₂ were stored by structural, residual gas, solubility, ionic and mineral trapping, respectively.

Fig. 14

CO₂ moles of different trapping mechanisms.

Fig. 15

Storage contributions of different trapping mechanisms (9800-01-01) (a) CO₂ injection period (b) CO₂ long-distance migration period.

Fig. 16

Proportional distribution of CO₂ geological storage mechanisms (9800-01-01).

Discussion

This study provides a detailed evaluation of CO₂ migration and trapping mechanisms in an offshore basin, highlighting how long-distance migration enhances structural trapping. Simulation results offer crucial insights into CO₂ behavior under controlled injection and storage. Supercritical CO₂ is injected at a constant rate for 200 years, followed by water injection to facilitate migration along dipping strata. The CO₂ plume migrates up to 7.0 km, indicating effective movement toward anticlinal structures ideal for structural trapping.

A key finding is the dominance of structural trapping, which secures 86.05% of the injected CO₂ during the initial phase. Over time, structural trapping decreases, while solubility, residual gas, and mineral trapping become more prominent. This shift highlights the dynamic interaction between physical migration and geochemical reactions^67,68,69,70. Mineralogical analysis reveals the dissolution of anorthite and precipitation of calcite and kaolinite, driven by CO₂-brine interactions. These reactions not only enhance the structural stability of the trap but also improve long-term storage security via mineral carbonation.

Furthermore, pH and porosity changes offer critical insights into reservoir evolution. The advancing CO₂ front triggers a pH drop, especially in long-distance migration zones, signaling significant acidification. Porosity changes are location-dependent: porosity shows a slight reduction near the injection wells, whereas it becomes higher in the structurally uplifted regions. This spatial heterogeneity indicates that CO₂ migration and mineral trapping are non-uniform, with localized reactions playing a critical role in reservoir capacity.

The study also emphasizes the influence of capillary hysteresis during CO₂ migration, which affects residual gas trapping efficiency. This effect intensifies with migration, leading to a non-linear trend in residual trapping. The simulations indicate that although structural trapping is vital initially, long-term storage increasingly relies on solubility and mineral trapping as CO₂ migrates and reacts with the formation.

The study considers a simplified two-phase (CO₂-brine) system. Expanding the model to multi-phase conditions, including hydrocarbons, could yield more realistic migration patterns, particularly in hydrocarbon-bearing offshore reservoirs.

Conclusions

Long-distance migration-assisted structural trapping represents an ideal configuration for offshore geological carbon storage. A quantitative analysis of carbon trapping efficiency was conducted using CMG software, accounting for aqueous solubility and geochemical reactions. The main findings are as follows:

• (1) Long-distance migration assisted structural trapping is an ideal structural for offshore geological carbon storage. CO₂ plume tends to migrate upward along the slightly dipping strata, transporting towards the upper anticline.

• (2) The injection of CO₂ changed the composition of the initial aqueous phase, and calcite is initially in the dissolved state, gradually transformed to the precipitated state as a result of the continued geochemistry reactions during CO₂ migration period. Dissolution of anorthite throughout the whole storage period demonstrates its superior mineral trapping capacity.

• (3) Dynamics of mineral dissolution and precipitation influence PH and porosity changes. PH is decreasing in CO₂ migration areas. Porosity decreases in the near-well zone, while it slightly increases in the structurally high areas.

• (4) The proportion of structural trapping is continuously increasing during the CO₂ injection period, and is decreasing during CO₂ long-distance migration stage. Residual gas trapping displays the initially increasing and then decreasing trend due to wettability and capillary effects throughout the CO₂ migration period.

• (5) Future work will integrate coupled THMC simulations to quantitatively assess the stress–strain evolution of the caprock during and after CO₂ injection, evaluate fault slip potential and fracture propagation in the Wushi Basin, and incorporate seismic imaging and field-monitoring data for site-specific mechanical calibration of sealing integrity.