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Residual Saturation Effects on CO_{2} Migration and Caprock Sealing: A Study of Permeability and Capillary Pressure Models

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## Abstract

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_{2}geological storage, multiphase flow plays a vital role in the movement and distribution of CO

_{2}. However, due to the limitations of fluid buoyancy and capillary forces, CO

_{2}encounters challenges in penetrating the caprock, and the potential for leakage remains a concern due to variations in injection conditions. The migration and distribution of CO

_{2}in the process of CO

_{2}geological storage in saline formations are determined by relative permeability and capillary pressure, which are key factors. Consequently, this study focuses on two essential models: relative permeability and capillary pressure models. A two-dimensional isothermal reservoir–caprock model was constructed, utilizing data from the Shenhua CCS demonstration project. The analysis indicates that the core parameters in the model are residual gas saturation and residual water saturation. Specifically, residual gas saturation governs the diffusion distance of CO

_{2}within the reservoir–caprock system, while its combined effect with residual water saturation affects the permeation rate of CO

_{2}. Through the application of the Analytic Hierarchy Process (AHP) to analyze the impact of different models on caprock integrity, it was determined that when selecting caprock models and optimizing parameters, precedence should be given to models with lower residual saturation and caprocks that offer sufficient capillary pressure for optimal sealing effects. These research findings can serve as references for practical CO

_{2}storage projects, providing guidance on activities such as adjusting water injection strategies and controlling gas injection pressures to optimize geological storage efficiency.

## 1. Introduction

_{2}emissions and has been proposed as an innovative approach for efficient decarbonization and mitigation of global climate change [3]. This approach offers the possibility of reducing atmospheric CO

_{2}while simultaneously continuing to use fossil fuels [4]. CO

_{2}sequestration is the final step in the entire CCS process, which is mainly accomplished by geological and ocean storage, as well as mineral carbonation [5,6,7]. Among them, geological storage, such as deep saline aquifers (DSAs), depleted oil and gas reservoirs, unmineable coal seams, gas hydrate storage, and enhanced geothermal systems, is considered to be the most viable solution for reducing CO

_{2}emissions [3,6,8,9,10]. Deep saline aquifers (DSAs) are widely distributed, have good sealing capabilities, and provide the most promising and feasible geological reservoir for carbon dioxide storage due to their vast storage capacity [11,12].

_{2}in deep saline aquifers. However, this method still faces various challenges, such as leakage detection, capacity assessment, the impact of heterogeneity on CO

_{2}migration in the subsurface, and pressure buildup caused by CO

_{2}injection. It has been proposed to store CO

_{2}in deep saline aquifers in a supercritical state [5,13,14]. Supercritical CO

_{2}exhibits physical properties that lie in between gas and liquid phases, with lower viscosity and better flowability compared to the liquid phase, as well as higher density compared to the gas phase. The higher density enables greater storage within the same volume, with supercritical CO

_{2}having a density of approximately 0.6–0.7 g/cm

^{3}in saline aquifers, which is lower than the density of formation water [15]. Due to buoyancy effects, CO

_{2}rises to the top of geological structures and is hindered from penetrating the caprock by fluid weight and capillary forces. Despite this, there still remains a potential risk of leakage, which not only leads to atmospheric pollution, but also poses a serious threat to groundwater and human safety [16,17]. Therefore, studying the risks of CO

_{2}leakage in geologic storage systems is of the utmost importance. In the process of CO

_{2}storage in deep saline aquifers, multiphase flow is inevitable due to the inherent differences in properties between the injected phase and the existing formation fluids [1,18]. This introduces the effects of relative permeability and capillary pressure, in contrast to the single-phase flow of traditional groundwater. Many empirical parameters in models for relative permeability and capillary pressure lack clear physical meanings [19]. Additionally, uncertainties may arise from changes in pore morphology due to pressure release, even when core samples are measured from the reservoir [20]. Various parameters have a significant impact on the distribution, migration, and sealing effectiveness of CO

_{2}in models [21], some of which are determined by actual geological conditions and others by engineering injection strategies. Therefore, studying the effects of these parameters in the models can help adjust and optimize CO

_{2}geologic storage strategies.

_{2}capture and geological storage project in deep saline aquifers. Specifically, it is located in the northeastern part of the Yimeng Uplift in the Erdos Basin. This region boasts a wide distribution of deep saline aquifers with multiple sets of suitable reservoir and caprock combinations for CO

_{2}geological storage [22]. As a result, it has the potential to store billions of tons of CO

_{2}. With its well-documented CO

_{2}storage data [23], the project provides valuable background information for this study. Therefore, this study uses the Erdos Shenhua CCS demonstration project as a case study and establishes a numerical model for CO

_{2}geologic storage based on TOUGH [24]. The analysis focuses on the CO

_{2}gas saturation distribution and assesses the impact of each parameter in the models for relative permeability and capillary pressure on the migration and distribution of CO

_{2}. Moreover, the study employs the Analytic Hierarchy Process (AHP) [25], a systematic and quantitative approach, to evaluate the influence of different models on the sealing effectiveness of CO

_{2}storage reservoirs. The findings from this research offer relevant theoretical support for the advancement of carbon dioxide geologic storage technology.

## 2. The Relative Permeability and Capillary Pressure Models

_{2}geological storage in saline aquifers, the sequestration of CO

_{2}is accomplished through its flow and diffusion in the formation’s pores. The size and distribution range of pores in the formation resemble those found in soil and rocks. The van Genuchten model [26] can be utilized to describe the permeability and capillary pressure characteristics of pores in rocks or soil, particularly for pore scales ranging from tens of micrometers to millimeters. Therefore, the van Genuchten model is employed in the models of liquid-phase relative permeability and capillary pressure. When the residual gas saturation is greater than zero, the model proposed by Corey is utilized to determine the relative permeability of the gas phase, leading to more accurate results [27].

_{2}to displace from the reservoir into the caprock, and it is determined based on the specific site conditions of the sequestration field.

_{2}) demonstrates an inverse relationship: it increases with increasing residual water saturation and decreases with increasing residual gas saturation. This indicates that when more pore spaces are occupied by residual gas, the flowability is affected.

## 3. Project Overview

_{2}sequestration. This represents China’s inaugural pilot-scale, full-chain demonstration initiative for the deep saline aquifer storage of CO

_{2}. Spanning an area of 11,200 m

^{2}, the storage site incorporates one injection well and two monitoring wells. Monitoring well 1 is situated at a distance of 70 m from the injection well, while Monitoring well 2 is situated 31.61 m away (refer to Figure 2c). Real-time transmission of monitoring data, encompassing parameters such as pressure and temperature, is realized within both the injection and monitoring wells. The injection well has a depth of 2826 m and includes casing with a radius exceeding 1500 m, featuring an inner diameter of 30 mm. Below the 1500 m threshold, the well transitions into an open hole with a radius of 62 mm. Four reservoir–caprock combinations have been identified, namely the Majiagou, Shanxi, Shihezi, and Shiqaingfeng Formations.

_{2}, which is sourced from direct coal liquefaction facilities, into saline aquifers characterized by low permeability. The carbon dioxide is intended to be stored at subsurface depths ranging between 1600 and 2500 m, within an anticipated timespan of three years. Contrary to these projections, the actual injection phase spanned an extended timeframe, commencing in May 2011 and concluding in April 2015 [15]. By analyzing actual monitoring data, it was revealed that over 80% of the CO

_{2}is absorbed by the Liujiagou Formation and the Shiqaingfeng Formation, with the upper reservoir exhibiting a higher production coefficient and the most substantial effective pressure gradient [23].

**Figure 2.**Shenhua CCS Project Location (adapted from Xie et al. [30]). Geographic location of the site in the Ordos basin (

**a**,

**b**), and the relative location of the monitoring wells to the injection well (

**c**).

## 4. Model Establishment

#### 4.1. Modeling Approach and Modeling Tools

_{2}as a supercritical fluid into a saline aquifer. The primary focus is on modeling the flow of multiphase fluids (H

_{2}O-CO

_{2}-NaCl) in porous media. To achieve this, we employ the TOUGH (ECO2N) module which is tailored for CO

_{2}geological storage in saline aquifers [31]. ECO2N, a fluid property module for the TOUGH2 simulator (Version 2.0), includes a comprehensive description of the thermodynamics and thermophysical properties of H

_{2}O-NaCl-CO

_{2}mixtures. These properties accurately replicate fluid behavior under the temperature, pressure, and salinity conditions of interest (283.15 K ≤ T ≤ 383.15 K; P ≤ 600 bar; salinity up to full halite saturation). In this modeling approach, water (brine) acts as the wetting phase, while CO

_{2}is considered a non-wetting fluid. The flow process takes place within a fully saturated porous region filled with water (brine), and it can be simulated under both isothermal and non-isothermal conditions [32]. We develop a two-dimensional isothermal model to analyze the distribution and migration behavior of carbon dioxide (CO

_{2}) in the reservoir–caprock. The simulation processes were exclusively performed using TOUGH (ECO2N), with the controlling equations specified in Table 1 and a comprehensive nomenclature presented at the conclusion of this research paper.

#### 4.2. Spatial Discretization and Model Parameters

_{2}are unified as a non-wetting phase referred to as “gas”, while the potential occurrence of salt precipitation is not accounted for in this study.

#### 4.3. Initial Conditions and Boundary Conditions

_{2}in the original formation is assumed to be 0. The initial temperature and pressure conditions are established in accordance with the equations specified in Table 3 [34].

_{2}distribution does not consider the heterogeneity of all formations. The coupled equations for determining the primary variables assume that the porous medium consists of rigid rock and both fluids are incompressible. Additionally, the dynamic viscosity of the fluids is assumed to be constant, and all source and sink terms are ignored.

## 5. Results and Discussions

#### 5.1. Distribution and Migration Behavior of CO_{2} in the Reservoir–Caprock System

_{2}injection, the lateral spread of the CO

_{2}plume is sustained by concentration gradients, capillary forces, and hydrostatic pressure differences. Simultaneously, buoyancy facilitates the vertical migration of CO

_{2}, leading to its eventual accumulation at the caprock’s base and resulting in a pattern resembling a “plume” distribution [35]. Nevertheless, with prolonged injection of CO

_{2}at high concentrations, its intrusion into the caprock induces a distinctive transition in the morphology of the CO

_{2}plume at the interface between the reservoir and the caprock. Various models portraying the distribution of CO

_{2}gas saturation in the Liujiagou formation, as depicted in Figure 4, demonstrate this phenomenon. It is evident from the figure that different relative permeability and capillary pressure models yield diverse impacts on the distribution and migration of CO

_{2}.

_{2}gas saturation curve along the horizontal monitoring line of different models (Figure 5a), it is observed that the gas saturation increases successively at the same spatial point when the residual water saturation decreases while keeping the residual gas saturation constant. This observation suggests that as the residual water saturation decreases, the relative permeability of the gas phase decreases, while the relative permeability of the liquid phase increases, resulting in a weaker gas flow ability [19]. However, it is noteworthy that the farthest diffusion distance of CO

_{2}remains unchanged (the curves have the same zero point), indicating that the residual gas saturation remains constant. In other words, the change in residual water saturation does not affect the farthest diffusion distance of CO

_{2}, yet it does enhance the likelihood of gas migration upwards and subsequent accumulation as CO

_{2}at the bottom of the caprock.

_{2}saturation at the same spatial point (Figure 5b). This is due to the enlargement of the non-wetting condition of the rock formation as the residual gas saturation increases. During the displacement phase, the saturation of water decreases, leading to a decrease in the relative permeability of the liquid phase. Although CO

_{2}experiences buoyancy, the ability of saltwater to displace the space occupied by CO

_{2}diminishes, resulting in a weakened ability of CO

_{2}to occupy new saltwater spaces. Moreover, as the non-wetting characteristic of the rock formation intensifies and the residual gas saturation increases, a larger quantity of CO

_{2}becomes trapped in the minuscule pores of rock particles. Additionally, the larger the residual gas saturation, the shorter the horizontal diffusion distance of CO

_{2}. This indicates that a change in residual gas saturation, even when the residual water saturation remains unchanged, can impact the maximum diffusion distance of CO

_{2}.

_{2}saturation at equidistant spatial points (Figure 5c). During the initial injection stage of CO

_{2}, as it tries to enter water-saturated pores, capillary pressure poses resistance, making it more difficult for CO

_{2}to penetrate the pores. However, as CO

_{2}injection continues, it surpasses the capillary displacement pressure and gains entry into the pores. Once injection ceases, capillary pressure restrains CO

_{2}from escaping the occupied pores. Hence, higher capillary pressure increases the probability of CO

_{2}becoming trapped within the pores, resulting in a greater CO

_{2}saturation. Notably, different capillary pressure models exhibit distinct characteristics, but they share the same zero point when the relative permeability model remains unchanged. This finding suggests that the capillary pressure model does not exert influence on the maximum diffusion distance of CO

_{2}.

_{2}plumes is limited by residual gas saturation. However, our study offers additional insights into the migration distance of carbon dioxide, which has not been explicitly explored in previous research. This observation necessitates further investigation into the influence of residual gas saturation. It is noteworthy that regardless of variations in residual water saturation, the maximum migration distance remains unchanged, indicating that residual gas saturation could potentially play a crucial role in determining the extent of CO

_{2}plumes.

#### 5.2. Assessment of the Sealing Efficacy of the Caprock

_{2}geological storage. The integrity of the caprock directly affects the long-term effectiveness of CO

_{2}storage. Caprock acts as a natural barrier in underground storage systems, playing a vital role in preventing CO

_{2}leakage. Inadequate caprock integrity can lead to CO

_{2}permeating through pores or spreading through fractures to the surface, posing environmental and human health risks and potentially compromising the sustainability of the storage system. Thus, evaluating the integrity of the caprock is of the utmost importance. Common evaluation methods include the safety diagnostic factor method introduced by the GeoNOC-CO

_{2}team and the Net–Gross method [38]. Figure 6 presents a comparative analysis of the farthest diffusion distance, total infiltration amount, average flow rate, and maximum pressure values among different intrusion models, based on the findings from the TOUGH simulation. Significant variations in the total infiltration amount, farthest diffusion distance, and maximum pressure values are observed among the different models. However, the farthest diffusion distance increases only with an increase in residual gas saturation. Furthermore, changing the residual water saturation parameter does not affect the farthest diffusion distance when the residual gas saturation remains constant, which aligns with the earlier findings (see Figure 5 and Figure 6).

_{2}storage. Excessive pressure can cause the caprock to fracture, while excessively low pressure can result in CO

_{2}upward invasion. According to the analysis of the judgment matrix, the maximum dispersion distance of CO

_{2}is also an important indicator for evaluating CO

_{2}leakage. It has a reasonable weight and practical geological significance.

_{2}invasion into the caprock. Conversely, RP (0.2–0.05) exerts the least influence and is the most advantageous for caprock sealing due to its low residual saturation, impeding CO

_{2}infiltration. The detrimental effect on sealing performance increases in RP models with higher residual saturation. CP (0.3) outperforms CP (0.1) and CP (0.0) due to its elevated capillary pressure, enhancing resistance against CO

_{2}. In relative permeability models, residual saturation holds critical significance, with higher residual gas saturation intensifying the negative impact on sealing performance through increased CO

_{2}penetration. Capillary pressure serves as another crucial factor affecting caprock sealing. Appropriately augmenting residual water saturation in the capillary pressure model enhances the caprock’s ability to withstand CO

_{2}, thereby improving sealing performance.

_{2}migration through aquifers [40]. This lead to improved reservoir storage capacity and reduced leakage risk, in line with the outcomes presented in this study. The notion that higher capillary pressure enhances CO

_{2}storage effectiveness has garnered considerable support from the investigations conducted by Song (2013) and Ali (2022) [8,41]. Consequently, these works serve to further substantiate the accuracy of the analytical and evaluative outcomes of the present study.

_{2}storage and attaining optimal sealing effects. Notably, the parameter values for this influence range between 0.4 and 0.1. This observation may indeed be linked to the artificial influence present in AHP analysis. Thus, it warrants further exploration in subsequent research, which can be conducted through experimental studies or numerical simulations [25].

## 6. Conclusions and Outlook

_{2}caprock seals. The analysis of our findings leads to the following conclusions:

_{2}. Remarkably, the extent of CO

_{2}diffusion is solely limited by residual gas saturation, negating the role of residual water saturation.

_{2}permeating through the caprock, jeopardizing containment. Additionally, capillary pressure models demonstrate that higher residual water saturation increases the caprock’s barrier capabilities against CO

_{2}. This signifies the necessity to prioritize models and caprocks that provide superior capillary pressure for optimal sealing.

_{2}containment. The study identifies an optimal range for this parameter to be between 0.4 and 0.1.

_{2}geologic storage in saline aquifers. It offers a novel framework for evaluating the interplay between residual saturations, relative permeability, and capillary pressure. Importantly, we introduce the concept that residual gas saturation has a controlling role in CO

_{2}migration, a factor often overlooked in prior numerical simulations. While the study provides a robust analytical base, it does have limitations tied to the Analytical Hierarchy Process (AHP) analysis, which may introduce human subjectivity into the scoring criteria. Future investigations should focus on defining the specific conditions and rock properties influencing residual gas saturation. This analysis provides valuable insights for practical CO

_{2}storage projects. During the CO

_{2}injection process, optimization of the geologic storage strategy can be achieved through adjustments to water flooding strategies (which affect residual water saturation) and control of gas injection pressure (which affects residual gas saturation). We strongly recommend the execution of further experimental and simulation studies to substantiate the relationship between residual saturation, relative permeability, capillary pressure, and CO

_{2}migration patterns.

## Author Contributions

## Funding

## Data Availability Statement

## Conflicts of Interest

## Nomenclature

${\mathit{F}}^{\mathit{\kappa}}$ | mass or heat flux of component $\mathit{\kappa}$ |

$\mathit{f}$ | apparent friction coefficient |

${\mathit{h}}_{\mathit{\beta}}$ | specific enthalpy of phase $\mathit{\beta}$ |

$\mathit{k}$ | absolute permeability |

${\mathit{k}}_{\mathit{r}\mathit{\beta}}$ | relative permeability of phase $\mathit{\beta}$ |

${\mathit{M}}^{\mathit{k}}$ | mass or energy per volume of component $\mathit{k}$ |

$\mathit{P}$ | pressure |

${\mathit{P}}_{\mathit{\beta}}$ | fluid pressure in phase $\mathit{\beta}$ |

${\mathit{q}}^{\mathit{\kappa}}$ | sinks and sources of component $\mathit{\kappa}$ |

${\mathsf{\Gamma}}_{\mathit{n}}$ | closed boundary surface of ${\mathit{V}}_{\mathit{n}}$ |

${\mathit{\rho}}_{\mathit{R}}$ | grain density of the rock |

$\mathit{\varphi}$ | porosity |

${\mathit{C}}_{\mathit{R}}$ | specific heat of the rock |

${\mathit{s}}_{\mathit{\beta}}$ | saturation of phase $\mathit{\beta}$ |

$\mathit{t}$ | time |

$\mathit{T}$ | temperature |

${\mathit{u}}_{\mathit{m}}$ | mixture velocity (velocity of mass center) |

${\mathit{u}}_{\mathit{\beta}}$ or ${\mathit{u}}_{\mathit{\beta}}$ | velocity of phase $\mathit{\beta}$ |

${\mathit{U}}_{\mathit{\beta}}$ | specific internal energy of phase $\mathit{\beta}$ |

${\mathit{V}}_{\mathit{n}}$ | subdomain of the flow system |

${\mathit{X}}_{\mathit{\beta}}^{\mathit{\kappa}}$ | mass fraction of component $\mathit{\kappa}$ present in phase $\mathit{\beta}$ |

$\mathit{\lambda}$ | thermal conductivity |

${\mathit{\rho}}_{\mathit{\beta}}$ | density of phase $\mathit{\beta}$ |

gorg | gravitational acceleration |

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**Figure 3.**Illustration of stratigraphic simulation: (

**a**) represents the entire Shenhua CCS demonstration project’s simulated stratigraphy, (

**b**) represents the Liujiagou Formation in the demonstration project.

**Figure 4.**The spatial distribution of gas saturation in different relative permeability models and capillary pressure models, with the enlarged region in the figure representing the Liujiagou reservoir–caprock interval. (

**a**–

**e**) represent RP (0.4–0.05), RP (0.4–0.2), RP (0.1–0.05), CP (0.1), CP (0.3) respectively.

**Figure 5.**(

**a**) Changes in residual water saturation in the relative permeability model; (

**b**) Changes in residual gas saturation in the relative permeability model; (

**c**) Changes in residual water saturation in the capillary pressure model.

**Figure 6.**Comparative analysis of farthest diffusion distance, total infiltration amount, mean flow rate and maximum pressure.

Description | Equation |
---|---|

Mass and Energy Conservation | $\frac{d}{dt}{\int}_{{V}_{n}}\text{}{M}^{k}d{V}_{n}={\int}_{{\mathsf{\Gamma}}_{n}}\text{}{\mathit{F}}^{k}\cdot \mathit{n}d{\mathsf{\Gamma}}_{n}+{\int}_{{V}_{n}}\text{}{q}^{k}d{V}_{n}$ |

For Mass | ${M}^{k}=\varphi {\sum}_{\rho}{S}_{\beta}{\rho}_{\rho}{X}_{\beta}^{\mathit{x}},{\mathit{F}}^{\mathit{\kappa}}={\sum}_{\rho}{u}_{\beta}{\rho}_{\rho}{X}_{\beta}^{k}$ |

For Energy | ${M}^{k}=(1-\varphi ){\rho}_{R}{C}_{R}T+\varphi {\sum}_{\beta}{S}_{\beta}{\rho}_{\beta}{U}_{\beta},{F}^{k}=-\lambda \nabla T+{\sum}_{\beta}{u}_{\beta}{\rho}_{\beta}{h}_{\beta}$ |

Darcy’s law | ${\mathit{u}}_{\beta}=-k\frac{{k}_{r\beta}}{{\mu}_{\rho}}\left(\nabla {P}_{\beta}-{\rho}_{\beta}\mathit{g}\right)$ |

Formation | Reservoir Thickness (m) | Cap Thickness (m) | $\mathbf{Logging}\text{}\mathbf{Permeability}\text{}(\times $${10}^{-3}\text{}\mathsf{\mu}$m^{2}) | Porosity (%) | Fracturing Pressure (MPa) | Formation Pressure (MPa) |
---|---|---|---|---|---|---|

R1 | 9 | 1699 | 2.81 | 10.6 | 35.29 | 17.45 |

R2 | 5 | 57 | 5.47 | 12.4 | 37.53 | 17.89 |

R3 | 40 | 191 | 1.431 | 9.7 | 38.95 | 20.15 |

R4 | 8 | 43 | 6.58 | 12.9 | 42.60 | 21.43 |

Caprock | - | - | - | 4.3 | - | - |

Parameters | Values |
---|---|

Porosity | 0.05–0.13 |

Permeability | $\mathrm{R}1\text{:}\text{}20\times {10}^{-3}\text{}\mathsf{\mu}{\mathbf{m}}^{2},\mathrm{R}2-\mathrm{R}4:\text{}1\times {10}^{-3}\text{}\mathsf{\mu}{\mathbf{m}}^{2}$ |

Rock grain density | $2260\text{}\mathrm{k}\mathrm{g}/{\mathrm{m}}^{3}$ |

Specific heat of the rock grain | $920\text{}\mathrm{J}/\mathrm{k}\mathrm{g}\xb7\mathrm{K}$ |

Thermal conductivity | $2.5\text{}\mathrm{W}/\mathrm{m}\xb7\mathrm{K}$ |

Initial temperature distribution | $T\left(D\right)=0.03D+273.1924\text{}\mathrm{K}(D1500\text{}\mathrm{m})$ |

Initial pressure distribution | $P\left(D\right)=1.133\times {10}^{4}D-3.78\times {10}^{6}\text{}\mathrm{P}\mathrm{a}$ |

Relative permeability model | $\lambda =0.5\text{}{\mathrm{S}}_{\mathrm{l}\mathrm{s}}=1.0$ |

Capillary pressure model | $\lambda =0.271\hspace{1em}1/{P}_{0}=4.2\times {10}^{-5}{\mathrm{P}\mathrm{a}}^{-1}\hspace{1em}{\mathrm{S}}_{\mathrm{l}\mathrm{s}}=0.999$ |

Classification | ${\mathit{S}}_{\mathit{w}\mathit{r}}$ | ${\mathit{S}}_{\mathit{g}\mathit{r}}$ | Model Classification |
---|---|---|---|

RP (0.4–0.05) | 0.4 | 0.05 | Relative permeability model |

RP (0.4–0.1) | 0.4 | 0.1 | Relative permeability model |

RP (0.4–0.2) | 0.4 | 0.2 | Relative permeability model |

RP (0.2–0.05) | 0.2 | 0.05 | Relative permeability model |

RP (0.1–0.05) | 0.1 | 0.05 | Relative permeability model |

CP (0.0) | 0.0 | -- | capillary pressure model |

CP (0.1) | 0.1 | -- | capillary pressure model |

CP (0.3) | 0.3 | -- | capillary pressure model |

Caprock Pressure | Maximum Ingress Distance | Total Amount of CO_{2} Ingress | Ingress Rate | Weights | |
---|---|---|---|---|---|

Caprock pressure | 1 | 5 | 5 | 5 | 0.537 |

Maximum ingress distance | 0.2 | 1 | 4 | 5 | 0.279 |

Total amount of CO_{2} ingress | 0.2 | 0.25 | 1 | 3 | 0.121 |

Ingress rate | 0.2 | 0.2 | 0.33 | 1 | 0.063 |

Caprock Pressure | Maximum Ingress Distance | Total Amount of CO_{2} Ingress | Ingress Rate | Comprehensive Weight | Comprehensive Weight | |
---|---|---|---|---|---|---|

Weights | 0.537 | 0.279 | 0.121 | 0.063 | - | - |

RP (0.4–0.05) | 0.154 | 0.111 | 0.125 | 0.146 | 0.138 | 3 |

RP (0.4–0.1) | 0.205 | 0.167 | 0.167 | 0.167 | 0.187 | 2 |

RP (0.4–0.2) | 0.256 | 0.278 | 0.208 | 0.208 | 0.254 | 1 |

RP (0.2–0.05) | 0.077 | 0.111 | 0.104 | 0.104 | 0.091 | 7 |

RP (0.1–0.05) | 0.128 | 0.111 | 0.104 | 0.104 | 0.119 | 4 |

CP (0.0) | 0.154 | 0.111 | 0.125 | 0.146 | 0.138 | 3 |

CP (0.1) | 0.103 | 0.111 | 0.167 | 0.167 | 0.117 | 5 |

CP (0.3) | 0.077 | 0.111 | 0.125 | 0.104 | 0.094 | 6 |

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© 2023 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https://creativecommons.org/licenses/by/4.0/).

## Share and Cite

**MDPI and ACS Style**

Chu, B.; Feng, G.; Zhang, Y.; Qi, S.; Li, P.; Huang, T.
Residual Saturation Effects on CO_{2} Migration and Caprock Sealing: A Study of Permeability and Capillary Pressure Models. *Water* **2023**, *15*, 3316.
https://doi.org/10.3390/w15183316

**AMA Style**

Chu B, Feng G, Zhang Y, Qi S, Li P, Huang T.
Residual Saturation Effects on CO_{2} Migration and Caprock Sealing: A Study of Permeability and Capillary Pressure Models. *Water*. 2023; 15(18):3316.
https://doi.org/10.3390/w15183316

**Chicago/Turabian Style**

Chu, Bingfei, Guanhong Feng, Yan Zhang, Shengwen Qi, Pushuang Li, and Tianming Huang.
2023. "Residual Saturation Effects on CO_{2} Migration and Caprock Sealing: A Study of Permeability and Capillary Pressure Models" *Water* 15, no. 18: 3316.
https://doi.org/10.3390/w15183316