https://orcid.org/0009-0000-7000-4048
Figures
Abstract
Carbon dioxide capture and storage (CCS) technology is considered a crucial tactic for achieving the “dual carbon” goals. However, current CCS technologies face several challenges, such as the absence of a comprehensive and systematic set of criteria for site selection, coupled with the lack of a universally applicable evaluation framework.To address these issues, this study proposes a regional-scale CO2 geological storage suitability assessment and potential estimation framework that can be adapted to similar regions. Using the Yellow River Delta as a case study, a geological storage site selection indicator system was developed, and a model for assessing site suitability was constructed.The model was employed to evaluate the appropriateness of CO2 geological sequestration sites within the study region, and numerical simulations of CO2 storage were performed utilizing the TOUGH2/ECO2N simulator for prospective target zones. This research examines the migration dynamics of CO2 in saline aquifers, the progression of storage mechanisms, and the carbon sequestration capacity of various storage configurations. The research addresses key questions such as: How can the optimal CO2 geological storage target area be selected? How can the best storage strategy matching the target area be determined? How can the migration and distribution characteristics of CO2 after storage be simulated? Are there potential risks in the future?
Citation: Sun W, Liu W, Ren S, Lin G, Wang C, Jiang X (2025) CO2 geological storage site selection and long-term potential assessment framework based on TOUGH2/ECO2N. PLoS One 20(4): e0321715. https://doi.org/10.1371/journal.pone.0321715
Editor: Omeid Rahmani, Independent Researcher, Global Talent Exceptional Promise, UNITED KINGDOM OF GREAT BRITAIN AND NORTHERN IRELAND
Received: November 20, 2024; Accepted: March 10, 2025; Published: April 24, 2025
Copyright: © 2025 Sun et al. This is an open access article distributed under the terms of the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original author and source are credited.
Data Availability: All relevant data are within the paper and its Supporting Information files.
Funding: Science Fund for Creative Research Groups of the National Natural Science Foundation of China (No. 42321002). Professor Wenjie Sun, the grant provider, has contributed to the study design, data collection, analysis, and manuscript preparation, in accordance with the ethical standards of academic collaboration.
Competing interests: The authors have declared that no competing interests exist.
Introduction
With the accelerated advancement of global industrialization and escalating energy demands, anthropogenic carbon dioxide (CO2) emissions have exhibited a sustained upward trajectory, constituting a principal driver of contemporary climate change [1]. Achieving net-zero CO2 emissions by mid-century and limiting global temperature rise to 2°C is crucial for sustainable development and a shared global challenge [2]. The strategies recommended by COP 21 involve boosting energy conservation and efficiency, using renewable and low - carbon fuels, implementing geo - engineering like afforestation, and, most importantly, developing CO2 capture and storage (CCS) techniques [3]. CCS has thus become a key strategy for pursuing sustainable development and combating global warming [4,5].
The choice of geological storage medium is critical to the effectiveness of CO2 geological sequestration. Common storage media include deep saline aquifers, depleted petroleum and natural gas reservoirs, unextractable coal seams, and basaltic formations.Among these, deep saline aquifers are regarded as among the most efficient and viable options for carbon dioxide sequestration [6]. These saline aquifers are located deep underground, where the groundwater is highly mineralized and unsuitable for agricultural or drinking purposes. Such geological structures are more common than oil and gas fields, and they offer greater sequestration potential. A portion of the injected CO2 will undergo dissolution in the aqueous phase, and throughout its migration within the reservoir,CO2 will react with the saline water and surrounding rock, enhancing its storage capacity [7].
The evaluation of CO2 geological sequestration potential mainly relies on experimental conditions, geological characteristics, and theoretical calculations, but there is still no unified standard or methodology for assessment [8]. Researchers typically develop relevant evaluation criteria and weightings based on the geological characteristics of the storage site and the specific evaluation objectives. In the early evaluation stages, initial screening is based on factors such as reservoir characteristics, fluid properties, and surface infrastructure. An appropriate suitability index system is then designed based on geological characteristics and evaluation goals [9]. After the initial screening, further detailed evaluation and ranking of potential storage reservoirs are carried out to establish a basin-level evaluation index system. One of the most representative examples of this system is the 15-indicator framework proposed by Bachu [10], which he used to assess the sequestration potential of the Canadian Basin. Over time, more comprehensive evaluation systems have been developed, incorporating considerations of regional geology, local protection, social health, and sequestration safety, such as the system developed by Oldenburg et al [11,12], which builds on Bachu’ framework and adds aspects of health, safety, and environmental risk.
To date, several challenges remain in the CO2 geological sequestration site evaluation methods and selection criteria. First, the assessment of sequestration capacity and injection rates requires a detailed study of the physical and chemical properties of the storage medium [6,13]. Second, existing site evaluation criteria are not comprehensive, lacking a widely applicable evaluation system with a high degree of quantifiability. Some key factors, such as fault development and sequestration safety, are still evaluated qualitatively or based on subjective judgment, which calls for further improvement in the scientific rigor of the evaluation process. Moreover, sequestration safety remains a concern, particularly regarding potential leakage risks and seismic events triggered by CO2 injection [14]. Additionally, the interaction between CO2 and the storage medium can alter the physical and chemical properties of the medium, potentially affecting the sequestration outcome [15]. Moreover, the widespread implementation of Carbon Capture, Utilization, and Storage (CCUS) is contingent not only upon technological advancements and energy demands but also on societal acceptance [16–18].The reasons hindering the development of CCS technology are not only technical but also related to cost issues [19–22].As, despite relying on existing and developing components, large-scale implementation of CCS faces financial barriers and challenges in deploying extensive projects [23].For example, in a region with multiple carbon emission sources and storage sinks, the properties of these sources and sinks vary, with each source having a different carbon emission level and each sink having a different sequestration capacity. The costs of capturing or storing CO2 also vary. Therefore, how to select and match suitable sources and sinks to minimize the total cost for a given carbon reduction target is a key research issue—the source-sink matching problem. Current CCS deployments have not fully considered the entire carbon capture chain, overlooking spatial matching between CO2 sources and sinks and the post-sequestration migration patterns and their impacts [24].
This study focuses on the Yellow River Delta and proposes a comprehensive CO2 geological sequestration site selection and potential assessment framework. Based on this framework, a comprehensive CO2 geological sequestration site selection and suitability evaluation index system is developed, which integrates the principles and mechanisms of CO2 sequestration in saline aquifers. The system takes into account regional geological background, social environment, and economic suitability conditions, scientifically defining the spatial distribution types and ranges of CO2 geological sequestration sites, as well as determining the priority zones and optimal storage target areas. On this basis, a multi-objective decision-making CO2 geological sequestration source-sink matching model is established to identify the appropriate emission sources for each target area. Finally, a CO2 geological sequestration numerical model is developed for all target areas, considering both gaseous and liquid phases of CO2. The model simulates the migration process and migration patterns of CO2 during sequestration and determines the best sequestration plans. This study addresses the following key questions: How should the optimal CO2 geological sequestration target area be selected? How can the best sequestration plan for the target area be determined? How can the post-sequestration CO2 migration distribution characteristics be simulated? And are there potential risks in the future? The research provides a framework and methodology for regional-scale CO2 geological sequestration suitability evaluation and potential estimation, which can be reasonably adapted to other similar regions.
Methods
This study focuses on the Yellow River Delta and proposes a comprehensive framework for CO2 geological storage site selection and potential evaluation. The Yellow River Delta is located in Shandong Province, where energy, electricity, and chemical industries with high carbon emissions are widely distributed. According to the “Survey and Evaluation of Geological Carbon Sink and Carbon Storage Resources in Key Regions” project by the China Geological Survey, the goal is to identify CO2 geological storage sites in the region with the capacity to store millions of tons of CO2 per year, in order to support the development of industrial-scale CO2 geological storage plans for the high-carbon emission zones along the eastern coastal area. This will contribute to the optimization and adjustment of the regional energy structure.The technical roadmap is shown in Fig 1.
CO2 geological storage site selection and site suitability assessment
The construction of evaluation indicators follows the principles of scientific rigor, comprehensive assessment, ecological sustainability, and adaptability to local conditions. The evaluation is based on five key indicators: storage safety, storage capacity, economic feasibility, social and environmental stability, and safety supervision. Taking into account the mechanisms of saline aquifer CO2 storage, geological characteristics of potential storage sites, environmental risks, and the relevant properties of CO2, a CO2 geological storage site evaluation system was established, referring to the domestic and international CO2 geological storage site evaluation frameworks [25–29]. The Analytical Hierarchy Process (AHP) was applied to calculate the weights of the evaluation indicators, with a consistency ratio (CR) value of less than 0.1, indicating that the consistency test was passed.
In the process of classifying site suitability, a multi-objective comprehensive assessment method was employed, integrating both qualitative and quantitative factors based on GIS spatial analysis tools. Through the spatial overlay of multi-source information, a suitability classification of CO2 saline aquifer storage sites and target area selection was carried out, and a corresponding suitability assessment model was constructed, identifying suitable sites. Further qualitative analysis was conducted in combination with the evaluation indicators system and relevant geological data and literature. Finally, the suitability classification of CO2 geological storage sites in the Yellow River Delta and the geological storage target area were determined.
Source-sink matching comprehensive evaluation model
Spatial analyst and Standard deviation ellipse tools were employed to analyze the distribution characteristics of 198 CO2 emission sources in the Yellow River Delta. The study selected aquifers in semi-closed and closed hydrogeological structures, located at depths of less than 800 meters, with a good cap layer and characterized by slow or very slow hydrological exchange that is not exploitable under current development conditions[30]. To optimize CO2 storage capacity, a nearest-neighbor analysis method was employed, utilizing CO2 emission source. The deep saline aquifer storage sites were considered as the sinks. With a 100 km search radius, the proximity distribution of CO2 emission sources and deep saline aquifers in the Yellow River Delta was matched, revealing the spatial relationships between various data elements.
CO2 geological storage numerical model
The mathematical model for the flow of CO2 fluid, based on the physical and chemical properties of supercritical CO2 fluid, is constructed with the following assumptions:
- (1) The CO2 geological storage target saline aquifer is approximated as a continuous porous media model.
- (2) The gas phase CO2 and the liquid phase saline water, as well as the multiphase flow in the target saline aquifer, all satisfy the generalized Darcy’s law.
- (3) All fluids in the deep saline aquifer obey thermal equilibrium, chemical equilibrium, and mechanical equilibrium.
- (4) Chemical components other than NaCl and H2O in the target saline aquifer are neglected.
- (5) Chemical reaction processes in the formation, except for mineral sequestration, are not considered.
- (6) The influence of the formation stress in the target area is temporarily ignored.
The motion of fluid within the pores is described using the generalized Darcy’s law, as represented by the following equation.:
where:
μαis the fluid viscosity (kg/m/s); is the fluid density (kg/m³);
is the relative permeability of the fluid (mD);g is the gravitational acceleration (m/s²), in the downward direction;z is the vertical direction, opposite to the direction of gravity;K is the absolute permeability of the porous medium, which is independent of the direction.
In the numerical simulation of CO2 geological storage, the mass and energy conservation principles for fluid flow in the reservoir are used as the basis. The simulation region is discretized using the finite difference method (FDM). Each grid cell satisfies the mass and energy conservation control equations for fluid and heat flow in a multiphase, multi-component system:
where:
The integration area is any sub-area within the study area corresponding to the dissected grid, m3; and the sub-area
is the boundary, m2; F is the mass or heat passing through the unit area, kg or J; q is the source-sink term, m3/s; n is the normal vector of the surface cell, pointing inward the
;
is the mass of the component κ, kg, whose superscripts κ are taken as 1,2,3,4 for water, salt, CO2, and heat.
The research focuses on the four CO2 geological storage caprock combinations of the target area in the Yellow River Delta. Numerical simulation of CO2 geological sequestration is carried out using the TOUGH2/ECO2N simulation software. The strata associated with the development of the target zone are shown in Fig 2.The four caprock combinations are distributed across Segments 1, 2, and 3 of the Shahejie Formation. The Shahejie Segment 1 consists of gray mudstone interbedded with bioclastic limestone, dolomite, oil shale, and siltstone; the Shahejie Segment 2 is well developed and consists mainly of mudstone, sandstone, and conglomerate sandstone layers. Segment 3 of the Shahejie Formation is the thickest, dominated by blocky fine sandstone, siltstone, oil shale, mudstone, and shale. A three-dimensional average model is established to analyze the migration and movement characteristics of injected CO2 in the reservoir, phase transitions, and CO2 storage potential under different sequestration types. The parameters employed in the simulation are presented in Table 1.
S3-1: Upper Member 3 of Shahejie Formation;S3-2: Middle Member 3 of Shahejie Formation;S3-3: Lower Member 3 of Shahejie Formation).
Results and analysis
CO2 geological storage site selection and site suitability assessment
This study establishes a multi-level hierarchical evaluation index system for CO₂ geological sequestration sites in the Yellow River Delta, integrating sequestration mechanisms in deep saline aquifers, geological settings, environmental risks, and CO₂ physicochemical properties. The system comprises 5 primary indicators and 44 secondary indicators, employing a five-level scoring criteria. Indicator weights were assigned using the Analytic Hierarchy Process (AHP) method (Table 2), and a comprehensive scoring model for evaluation units was developed (Table 3), providing a methodological framework for quantitative assessment of sequestration sites.
Building upon the CO₂ geological sequestration site evaluation index system, a suitability classification map for sequestration sites was constructed through GIS spatial overlay analysis (Fig 3). This integrated multidimensional constraints including drinking water source areas, ecologically sensitive zones, land use types, spatial proximity to residential areas, fault structures, and reservoir-caprock assemblage characteristics. Subsequently, optimal target sequestration zones were identified and delineated (Fig 4).
http://bzdt.ch.mnr.gov.cn/underaCCBYlicense, with permission from Ministry of Natural Resources, original copyright 2020).
http://bzdt.ch.mnr.gov.cn/underaCCBYlicense, with permission from Ministry of Natural Resources, original copyright 2020).
Source-sink matching comprehensive evaluation model
A spatial analysis of CO2 emission sources in the Yellow River Delta revealed the formation of four high-density clusters, with a clear concentration in the Kenli District and Guangrao County, showing a spatial distribution along a southwest-northeast axis (Fig 5). By analyzing the carbon emissions and distribution of various types of carbon sources across different emission levels, as well as their emission characteristics, the Shahejie Formation was identified as the target saline aquifer for CO2 sequestration, based on the principles of CO2 saline aquifer sequestration. Using proximity analysis within a 100 km search radius, all CO2 emission sources in the Yellow River Delta were successfully matched with suitable sequestration sites, forming source-sink pairs. The total CO2 emissions in the study area amounted to 143.58 Mt, with an average CO2 emission of 0.73 Mt per source, and transport distances ranging from 0 to 61.94 km (Fig 6).
http://bzdt.ch.mnr.gov.cn/underaCCBYlicense, with permission from Ministry of Natural Resources, original copyright 2020).
http://bzdt.ch.mnr.gov.cn/underaCCBYlicense, with permission from Ministry of Natural Resources, original copyright 2020).
CO2 geological storage numerical model
The model includes four CO2 storage layers, each with ten equidistant injection points, and the CO2 injection is performed at 1Mt/a, i.e., 0.7927 kg/s for each injection point, and the total simulation time is 1,000 years with 10 consecutive years of injection.
To ensure the successful execution of CO2 geological storage and the safe confinement of CO2 within the deep target saline aquifer, the injection pressure during CO2 injection is typically required to be lower than the fracture closure pressure of the formation [31], and it is known that the formation fissure closure pressure is generally the hydrostatic pressure of the formation. As shown in the study of J. Rutqvist et al [32], the fracture closure pressure of the formation is typically 1.5 times the static water pressure of the formation [33]. According to the distribution law of pressure gradient in the target area, the hydrostatic pressures at the lower interface of the four cap layers in the study area are 16.4 MPa, 17.9 MPa, 25.9 MPa and 28.2 MPa, respectively, and the maximum fracture pressure is set to 16.4 MPa, 17.9 MPa, 25.9 MPa and 28.2 MPa, respectively, according to the above model. The fracture pressure calculation model to set the maximum formation bearing pressure, the upper limit of pressure at the top interface of S2 reservoir, S3-1 upper reservoir, S3-1 lower reservoir and S3-2 reservoir are 24.6MPa, 35.3MPa, 39.5MPa, 42.5MPa, respectively.As shown in Fig 7 for the distribution of pressure buildup, this study selects the pressure change of different time periods at the top interface of each storage layer condition. The maximum pressure values of the four groups of storage layers reach 17.2MPa, 32.5MPa, 30.2MPa, and 41.2MPa, respectively,and it can be seen that the peak values of pressure changes caused by the injection pressure in the four groups of brackish water aquifers do not exceed the preset maximum formation.
During injection, the CO2 in its gas phase primarily forms a funnel-shaped distribution, with restricted lateral migration at the bottom. As the radial distance from the wellbore increases, the specific gravity (SG) of CO2 gradually decreases. The radial flow distance at the base of the caprock is relatively large, causing the SG of CO2 at the upper part of the injection well to gradually increase. Under the effects of convection and diffusion, the CO2 fluid gradually migrates outward from the vicinity of the wellbore. When the injection is halted, the maximum horizontal migration distances of the CO2 plume in the four reservoirs were 1500 m, 1100 m, 1300 m, and 1200 m, in that order.
The high-pressure zone that formed near the wellbore quickly dissipates once CO2 injection is completed, and the CO2 plume continues to spread laterally as a result of diffusion driven by concentration gradients. During the monitoring phase after CO2 injection, the spatial migration range of the CO2 fluid gradually expands with increasing storage time, although the spatial distribution pattern of gas-phase CO2 does not experience substantial changes. Due to the increased dissolution of CO2, the CO2-specific gravity (SG) in the center of the injection well area decreases rapidly, from the initial values of 0.9 and 0.95 to 0.28, 0.48, 0.4, and 0.55 at 1000 years, respectively. The diffusion range of the CO2 plume increases over time, and by 1000 years, the leading edge of the CO2 plume in all four reservoirs is within 4 km in the horizontal direction, which is within the safety evaluation range. The lateral spread distances of the CO2 plume in the four reservoirs are 4 km, 3 km, 3.6 km, and 3.1 km, respectively (Fig 8).
In the early stages of injection, CO2 in all four reservoirs is primarily in the free phase, followed by the bound phase and dissolved phase. Except for the free phase CO2, the storage capacity of CO2 in the other phases gradually increases over time. As the proportion of free-phase CO2 decreases, the global proportion of residual and dissolved CO2 continues to rise, with the dissolved-phase storage increasing significantly over time. After 500 years, CO2 mineralization begins to show its effects, and the transformation of CO2 in deep saline aquifers through different mechanisms becomes a key factor influencing the storage safety of deep saline formations. The extent of transformation of supercritical CO2 into dissolved and mineralized forms is an important factor for evaluating the storage capacity of deep saline aquifers. By the 1000-year mark, the evolution of all four storage mechanisms becomes more apparent in the four reservoirs. The mass percentage of gas-phase CO2 in each reservoir decreases from 88.7%, 85.1%, 87.7%, and 85.4% at the time injection stops to 58.4%, 66.9%, 53.0%, and 58.6% at 1000 years. The amount of free-phase CO2 significantly decreases, while the storage in the other three mechanisms gradually increases. CO2 dissolves into the saline water in the reservoirs, and over time, the CO2 content dissolved in the target saline aquifers gradually increases. Since the initiation of CO2 injection, the CO2 dissolved in the saline water near the wellbore gradually increases and becomes saturated. Meanwhile, CO2 continues to dissolve through radial and vertical flow, causing large amounts of supercritical CO2 to interact with the formation water. Due to the higher density of saline water containing large amounts of dissolved CO2, this portion of the saline water moves downward. In contrast, saline water with less or undissolved CO2, having a lower density, moves upward. Under the influence of pressure gradients, the dissolution of CO2 in the saline aquifer increases, leading to more dissolved CO2 in the formation water. At the 1000-year mark, the content of dissolved CO2 in each storage layer accounts for 37.6%, 28.6%, 38.7%, and 37.38% of the total, respectively(Table 4).
Discussion
In this paper, an evaluation of CO2 geological storage sites in the Yellow River Delta region is conducted. Through the establishment of an evaluation index system, GIS - based spatial processing of multivariate information, and numerical simulation of CO2 geological storage in the selected target areas, certain results have been obtained. However, there are the following issues that require continuous research and improvement:
- (1) The evaluation of CO2 geological storage sites is a dynamic process throughout the entire life cycle of CO2 geological storage. This paper covers data preparation and analysis, field visits and investigations, stratigraphic surveys and explorations, as well as model inferences. Nevertheless, it lacks research on leakage monitoring after injection. Therefore, in future studies, a comprehensive evaluation of the storage sites should be carried out to enhance injection efficiency, economic viability, and safety.
- (2) When establishing the evaluation index system for CO2 geological storage sites, it is necessary to comprehensively consider influencing factors and select appropriate evaluation indices. The evaluation and screening of target sites involve the mutual coupling of multiple factors. Currently, due to the limited understanding of the study area and the immaturity of related geological background research, the CO2 storage site evaluation index system established in this paper needs further refinement. Additionally, as relevant research in China started relatively late, the relevant laws, regulations, and construction standards are not yet fully developed, which restricts the selection of relevant evaluation indices. With the continuous improvement of relevant laws, regulations, and engineering construction standards, the evaluation index system should be further optimized in future research to increase the accuracy of evaluation results.
- (3) In this paper, when conducting a comprehensive analysis of multivariate information based on GIS, some influencing factors cannot be directly processed spatially with other factors, and human - computer interaction is employed, which affects the evaluation results. In the future, a scientific approach should be adopted to establish and clean the multivariate spatial information dataset. Moreover, although this paper has completed the numerical simulation of CO2 geological storage in the target area, in the simulation of the grid section during numerical simulation, due to the complexity of the geological body, the grid section fails to fully and accurately simulate the actual situation. In future research, further exploration is needed to develop an integrated method that can achieve a double - optimal balance between the grid section and data volume, enabling accurate simulation of all aspects of CO2 geological storage characteristics.
Conclusion
This study establishes an evaluation index system for CO₂ geological sequestration sites in the Yellow River Delta, integrating GIS spatial analysis to delineate suitability zones and target reservoirs by comprehensively assessing factors such as drinking water sources, ecologically sensitive areas, and protected regions. The analysis reveals four high-density aggregation zones of CO₂ emission sources within the study area. By applying saline aquifer sequestration principles and GIS proximity analysis, optimal source-reservoir matching was achieved under a 100 km search radius, enabling full coverage of emission sources and sequestration targets. Numerical simulations demonstrate that pressure variations in the four sequestration layers remained within safe thresholds during and after CO₂ injection. The migration patterns exhibited consistent characteristics: a funnel-shaped distribution during injection, buoyancy-driven upward migration post-injection with capillary breakthrough, followed by lateral diffusion. By the simulation’s conclusion, lateral CO₂ migration in all layers remained confined within predefined safety boundaries. Notably, the deep saline aquifer of the Shahejie Formation in the target area demonstrated superior CO₂ injectivity, storage capacity, and minimal sequestration risks, providing robust scientific support for the implementation of regional CO₂ geological sequestration projects.
Acknowledgments
We gratefully acknowledge the editorial team and reviewers for their insightful comments and professional suggestions, which have been instrumental in refining the arguments and presentation of this work.
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