Evaluation of the Potential for CO₂ Storage and Saline Water Displacement in Huaiyin Sag, Subei Basin, East China

Abstract

CO₂ geological storage combined with deep saline water recovery technology (CO₂-EWR) is one of the most effective ways to reduce carbon emissions. Due to the complex structural features, it is difficult to use CO₂-EWR technology in Huaiyin Sag, Subei basin, East China. In this study, the multi-source information superposition evaluation technology of GIS was utilized for the selection of CO₂ storage sites and water displacement potential target areas in this area, which mainly focused on the sandstone reservoirs of Cretaceous Pukou Formation. Based on the results, a three-dimensional injection–extraction model was established. Various scenarios with different production/injection well ratios (PIR) were simulated. Research has shown that the suitability of the surrounding site of Huaiyin Power Plant can be divided into two levels: relatively suitable and generally suitable; the area in the generally suitable level accounts for more than 80%. At a PIR of 1, CO₂ is distributed asymmetrically, whereas at PIRs of 2 or 4, CO₂ is distributed symmetrically. When the number of production wells is constant, a higher injection rate results in a faster expansion rate of the CO₂ plume. This means that the time taken for the CO₂ plume to reach the production wells is shorter. Reservoir pressure increases rapidly after more than 60 years of CO₂ injection at lower PIR values, while at higher PIRs, reservoir pressure eventually stabilizes. Higher PIR values correspond to higher gas saturation, indicating a greater capacity for CO₂ sequestration with more producing wells. When PIR = 4, the total CO₂ injection increased by 55.73% compared to PIR = 1. However, the extraction of saline decreases with an increase in the number of producing wells, resulting in a decrease in replacement efficiency. This study provides a theoretical basis and technical support for the implementation of large-scale CO₂-EWR engineering and technology demonstration in this region.

1. Introduction

In response to global climate change, governments and institutions of all countries have successively put forward the targets of “carbon peaking” and “carbon neutrality”. CO₂ emission reduction has become a hot issue in recent years [1,2,3,4,5,6,7,8]. CO₂ storage in deep salt-water formation is one of the most effective ways for carbon emissions reduction [9,10,11,12,13,14,15,16,17,18]. A deep salt-water layer is widely distributed in China, which has a potential of up to 1.44 × 10¹¹ t for CO₂ storage in the buried depth range of 1–3 km [9]. However, large-scale CO₂ storage in deep salt-water layers could cause rapid accumulation of reservoir pressure, which may promote reactivation of sealed fractures or create new fracture in the caprock seal. So, the caprock integrity may be damaged in the long term as a result of the CO₂ sequestration in deep saline aquifers [19,20]. In terms of this issue, CO₂ geological storage combined with deep saline water recovery technology (CO₂-EWR) was proposed by Li and Bergmo [21,22,23]. CO₂-EWR is the process in which CO₂ is injected into deep saline or brine layers to displace high value-added liquid mineral resources (such as lithium salts, potassium salts, and bromine) or deep saline water resources, which can be comprehensively developed and utilized, while the injected CO₂ is stored in the long term. This technology could not only meet the requirements of safe CO₂ storage, but also provide a large amount of brine resources [21,23].

Scholars have conducted extensive research on CO₂-EWR technology [13,14,15,16,17,18]. The effects of reservoir porosity, permeability, and total dissolved solids in salt water on CO₂ storage capacity and salt water extraction were studied by using a homogeneous model in the Junggar Basin, China [24]. Li et al. evaluated the comprehensive utilization potential of CO₂ flooding and storage in the deep salt water layer of the Shiqianfeng Formation in the Ordos Basin through experiments and numerical simulations [25]. Much research has shown that reservoir physical parameters, salinity, and boundary conditions all affect pressure changes and CO₂ storage efficiency during CO₂ injection and saline water extraction, and the formation pressure is an important factor limiting CO₂ storage capacity [26,27,28,29,30]. In addition, the injection and output parameters (i.e., maximum injection of CO₂ and the maximum production of salt water) have shown strong differences as the CO₂-EWR injection production mode changes [31,32,33].

As a national thermal power plant, Huaneng Huaiyin Power Plant plays an important role in power supply in northern Jiangsu Province, and is under great pressure to reduce carbon emissions. It is of great practical significance to use CO₂-EWR technology in this region. The good matching of sources and sinks, combined with a larger area of the saline water storage site, provide the feasibility of a large-scale geological storage project for CO₂. However, the typical characteristics of geological background (i.e., small, fragmented, poor, and scattered) increase the difficulty of implementing the project in the Subei Basin [34,35]. Additionally, the development of the Huaiyin-Xiangshui Fault and the Tanlu Fault has increased the risk of geological hazards and limited the storage of large-scale CO₂ saltwater layers in the Huaiyin Sag. The multi-source information superposition evaluation technology of GIS was utilized for the selection of CO₂ storage sites and water displacement potential target areas in this area. Based on the site selection results, a geological model is constructed according to the actual geological conditions of the favorable area. As the study area is currently in the pre-study stage, numerical simulation has been employed to analyze the distribution characteristics of CO₂ and the changes in reservoir pressure under different injection and extraction ratios. This will help to address any potential issues that may arise during the actual project.

2. Geological Setting

The Huaiyin Sag is a secondary structural unit of the Yanfu Depression in the Subei Basin, forming a dustpan-like structure. It is bounded by the Coastal Uplift to the northeast, the Huaiyin-Xiangshui fault to the west, the middle part of the Jianhu Uplift to the south and the Tangwa-dalaba high to the east (Figure 1). The structural pattern of the Subei Basin is controlled by the northeast and almost east–west faults. Generally, the study area is a low-amplitude anticline structure with many fault structures developed in this area, which are mainly polyphase, directional and inheritance normal faults that formed in the late Yanshan and Himalayan periods.

The Cretaceous Pukou Formation, which is the target formation of this study, has deposited an almost kilometer-thick saline series consisting of anhydrite, halite, and glauberite. The Pukou Formation was deposited in the pre-lake and semi-deep lake subfacies. Taking gypsum salt rock layers as the standard layer, and combined with sedimentary cycles characteristic, electrical characteristics, and well drilling data, the Pukou Formation can be divided into four sections (Kp₄, Kp₃, Kp₂, Kp₁) from top to bottom (Figure 2). The member 4 section of Pukou Formation (Kp₄), which is mainly brown mudstone, could be a high-quality regional cap rock. The sandstone in the member 3 section of Pukou Formation (Kp₃) is mainly composed of argillaceous rock debris feldspar quartz powder fine sandstone, with well to medium sorted and a high content of impurities, and the cementation type is mainly the poring contact type. The physical properties of the reservoir are highly variable, with porosity and permeability ranging from 0.4% to 8.3% (with an average of 5.38%) and 0.044–1.5 mD (with an average of 0.665 mD), respectively, indicating that the sandstone belongs to a low-porosity and low-permeability reservoir. The sandstone in the member 2 section of the Pukou Formation (Kp₂) is mainly composed of fine–medium sandstone containing mud, ash, and cloudy feldspar debris with moderate sorting. The pores are mainly intergranular dissolution pores in this section, with porosity and permeability ranging from 0.6% to 15.55% (with an average of 6.82%) and 0.89–6.49 mD (with an average of 0.89 mD), respectively, indicating that the sandstone belongs to a medium- to low-porosity and low-permeability reservoir. The sandstone in section Kp₁ of the Pukou Formation, known for its medium–low porosity and low permeability, is primarily composed of coarse to medium sandstone with gravel and feldspar debris. The reservoir and cap conditions in the study area are generally favorable.

3. Site Selection Evaluation

The assessment of CO₂ saline water reservoir storage site selection is mainly based on the principles of maximum storage capacity, safety, minimum impact on resource development and utilization and economy. The evaluation is mainly conducted from three indicator layers and nine indicators, that is: geological suitability of the sink (reservoir conditions and storage potential, geological characteristics of top cap rock, seismicity, mutual feedback effect of energy development), surface suitability of the sink (geological hazard susceptibility, population density, terrain complexity) and economy (underground economy, CO₂ pipeline transmission and land occupation cost). At present, there are many methods suitable for evaluating the suitability of CO₂ geological storage, including empirical and mathematical methods (such as the analytic hierarchy process, probability analysis, and the feature–event–process (FEP) algorithm), as well as computer technology (such as multi-factor layer by layer stacking method in GIS environment). These evaluation methods are relatively mature and widely used [36,37,38,39,40,41,42]. Normally, the multi-source information superposition evaluation technology of GIS is utilized for the selection of CO₂ saline water storage sites and water displacement potential target areas [43,44]. In this study, this method was also be used for the selection of CO₂ saline water storage sites and water displacement potential target in the Huaiyin Sag.

3.1. Multi-Source Information Overlay Evaluation Technology

With the development of computer technology and remote sensing technology, the multi-source information superposition evaluation technology was proposed for the comprehensive processing of multi-source geoscience information (such as geographic information, geological information, and remote sensing information) [43,44]. It is based on the spatial two-dimensional plane determined by geographical coordinates to achieve the unity of geographic coordinates for the same region and different information, which is also known as spatial registration. The research work is completed by using geographic information software spatial analysis. The superposition of multiple sources of information is not a simple superposition of several types of information, but often leads to new information that cannot be provided by the original individual information.

The multi-source information overlay processing method is used to study the site selection of CO₂ geological storage sites. Firstly, based on a systematic analysis of the influencing factors of CO₂ geological storage, a thematic information map is prepared for each factor by using the basic function of GIS. Secondly, each thematic map generates an information storage layer which has been edited. Third, based on the single-factor analysis, registration and composite processing of major control factors are carried out to form a new information storage layer with composite overlays. Finally, a site selection suitability evaluation model is constructed to conduct site screening suitability evaluation in the research area.

3.2. Storage Site Selection

The Cretaceous Pukou Formation residual thickness is differentially distributed in the study area, two thickness centers were developed in Huaiyin Sag and Yancheng Sag, with a general thickness of 1500 m. In the middle of the study area, the Pukou Formation has experienced uplift and seriously denudation, which result in a thickness of approximately 500 m preserved in here. The Huaiyin-Xiangshui fault and the Tanlu fault were developed in the northwestern margin of the study area, and pose significant geological safety risks. Overall, the storage capacity in the areas of Huaiyin Power Plant and its surrounding is moderate to low, making it unsuitable for large-scale CO₂ saline water storage. Therefore, it is necessary to optimize the storage location in the study area.

The feasibility evaluation of CO₂ saline water storage is shown in

Table 1. The feasibility evaluation of CO₂ saline water storage (revised from Cao et al. [37]).

Basis	Parameter	Standard	Huayin Sag
geotectonics		Sedimentary basins in stable continental interior or near stable continental plate interior	Continental rift basin
Volume conditions	basin area	≥2500 Km2	/
	reservoir thickness	>20 m	Kp2: 60–115 m Kp3: 230–250 m
tectonic feature	strata	The occurrence is gentle, stable and has lateral sealing property	/
	fold	Top of the anticline	Jianhu Uplift
	fault	No fault, less fault or good fault sealing	Tanlu Fault Huaiyin-Xiangshui Fault
reservoir condition	depth	>800 m	1100–2500 m
	physical property	The porosity is generally greater than 10%, and there is no absolute requirement for permeability.	Kp2: 5.38% Kp3: 6.82%
	reservoir pressure	Exceeding the CO2 critical pressure (7.5 MPa)	25 MPa
geothermal condition	geothermal gradient	The lower the more favorable	/
	geothermal temperature	≥35 °C	55 °C
local stability	earthquake volcano or active fault	Earthquakes, volcanoes, and active faults are not developed	No
cap rock condition	caprock thickness	>100 m	Kp2: 125–130 m Kp3: 340 m

. Through the data and information of regional geology, hydraulic and environmental geology, oil and gas geology, geophysical exploration and drilling data, as well as remote sensing interpretation, the reservoir cap rock combination, sedimentary facies changes, physical parameters and their spatial distribution and tectonics model were basically obtained. The characteristics of the evaluation area in terms of population density, topographical complexity and susceptibility to geological hazards were also taken into account, and the principles of “combining underground and surface, and combining technology and economy” were followed.

The hydrogeological characteristics, as an important parameter for storage site selection, are controlled by various factors such as natural geography, geological structure, lithofacies paleogeography and meteorological and hydrological conditions. The aquifer system in Huaiyin Sag mainly includes phreatic water in Quaternary loose sedimentary and pore phreatic water and interlayer water in Cretaceous clastic rock, among which the latter is the CO₂-EWR technology reservoir cap rock area. The sediments of the Pukou Formation in this area exhibit a gradual evolution of salinity, from no salt at the bottom to more salt, less salt, and back to no salt at the top, vertically. Horizontally, the sediments show a pattern of increasing salinity from the subsidence center of the depression to the surrounding area, with a sequence of more salt, gypsum salt, gypsum mudstone, and sand mudstone. These observations suggest that the underground hydrogeological conditions in this area are favorable for the application of CO₂-EWR technology.

The Pukou Formation in the study area lacks oil and gas resources, resulting in an abundance of groundwater in the sandstone reservoir. Additionally, the area has plentiful salt resources, primarily located in the middle section of the Pukou Formation. This section is mainly composed of clastic rock, sulfuric acid rock, and salt rock, forming a sedimentary sequence of normal sedimentary rocks and halites. During the salt formation period, the water solution undergoes repeated cycles of desalination, salinization, and desalination again. Additionally, the rhythm of salt-bearing strata changes frequently. This sedimentary background results in high mineralization of the groundwater in the sandstone aquifer, which enhances the industrial value of displacing saline water. As a result, the study area shows promising potential for saltwater mining.

The cap rock characteristics are important indicators of the geological safety for CO₂ storage. The regional stratigraphic stability, lithology, thickness, burial depth, and other characteristics jointly determine the level of risk of CO₂ leakage in geological storage under structurally stable conditions. When discussing the types of rock which suit to serve as cap rock, it is generally believed that evaporite has the best sealing ability, followed by argillaceous rock with medium sealing ability, and shale and tight limestone with the worst sealing ability. The thickness of cap rock also plays a crucial role in preventing the upward escape of oil and gas. A cap rock with a thickness greater than 100 m is considered good, while a thickness between 50 and 100 m is medium, and a thickness between 10 and 50 m is poor. It is believed that caprock has the best sealing ability when buried between 1000 m and 2700 m. This is due to the higher porosity and permeability of shallow caprock, and the increased brittleness of caprock, which leads to the formation of micro-cracks, at greater burial depths (i.e., more than 2700 m). The cap rock in the study area consists mainly of mudstone and salt rock. It is a single layer with a thickness ranging from 90 m to 130 m and burial depth in range of 1500 m to 2500 m. This suggests that the cap rock of the Pukou Formation in the study area has good sealing ability.

Through geological suitability evaluation, ground suitability evaluation, and economic evaluation of the pool, the suitability of the power plant is divided into 5 levels using the method of multi-source information overlay processing, and finally, suitable sites for CO₂ storage in coal-fired power plants are selected.

The evaluation results indicate that the suitability of the surrounding sites of Huaiyin Power Plant is mainly divided into two levels (i.e., relatively suitable, generally suitable), and the area in the generally suitable level accounts for more than 80% (Figure 3). The suitable sites are mainly distributed in the northeast, central, and southwest of the study area, which are basically consistent with the depression position, and the central part is the most suitable area. According to the evaluation results of CO₂ saline water layer storage site selection, one storage target area with good suitability around Huaiyin Power Plant for simulation research was selected (Figure 3). The actual storage site area is 25.00 km² (the evaluation model area is 7.5 km × 7.5 km = 56.25 km², including 5 km × 5 km distribution range of the site). The reservoir and cap rocks mainly include the member 2 and 3 sections of Pukou Formation (i.e., Kp₃ and Kp₂). There are no fault cuts around the target storage site, and the strata are flat here.

4. Evaluation Method of Water Displacement Potential

4.1. Simulation Program

Since the early 1990s, scholars have established many CO₂ geological storage potential assessment methods for specific problems and assessment scales [27,28,32,33]. In particular, the calculation formulas of the United States Department of Energy and the Carbon Sequestration Leadership Forum (CSLF) are relative scientific. According to the calculation method for CO₂ geological storage in pure saline water layers proposed by USDOE, potential assessment of CO₂ geological storage is mainly achieved by estimating the volume of underground storage space under the premise that the storage space must meet the site selection criteria. However, the geological storage and displacement potential of CO₂ deep salt water layers is closely related to the CO₂ storage capacity. The theoretical evaluation method for CO₂ water displacement potential is similar to the CO₂ oil displacement potential evaluation method. It is generally estimated by multiplying the geological storage capacity of CO₂ by the displacement efficiency of deep saline water (Equations (1) and (2)).

$$G_{CO2}=A·h·{\phi }_e·{\rho }_{CO2}·E_{saline}$$

(1)

$$G_{Water}=G_{CO2}·E_{Recovery}$$

(2)

where $A$ is the area of reservoir distribution, $h$ is the reservoir thickness, ${\phi }_e$ is the average effective porosity of salt water layer,${\rho }_{CO2}$ is the density of CO₂ in temperature and pressure conditions of the saline water layer, $E_{saline}$ is the Storage efficiency (effective coefficient), and $E_{Recovery}$ is the displacement coefficient of deep saline water. For the evaluation of predicted displacement potential, the salt water displacement coefficient is generally taken as 1.0, which means that the displacement efficiency of carbon dioxide and deep salt water is 1:1 (mass).

Based on selected evaluation area, the numerical simulation method is adopted to evaluate the CO₂ flooding potential. Firstly, a geological model of the evaluation site is constructed. And then, the plans of different injection and extraction were set. Finally, the prediction of water flooding potential of CO₂-EWR technology was carried out.

4.2. Conceptual Model

The evaluation method for CO₂ geological storage and water displacement potential is mainly based on basin basic geological research, static geological modeling, and the application of numerical simulation technology to conduct the dynamic evaluation of CO₂ geological storage potential under different scenarios. The reservoir modeling is the fundamental of the entire evaluation process, which may direct determine the quality of the evaluation results. Based on the geological model, the factors such as fluid flow, component material balance, and water-rock reaction are taken in to consider in the evaluation of the potential for geological storage and water displacement potential of CO₂ in deep salt water layer. In addition, the impacts of injection method, injection, and extraction well layout on water repulsion efficiency are also been focused during the evaluation process. An important result of numerical simulation is to provide the maximum water displacement potential during the CO₂ geological storage process of the site, and to provide the best injection and extraction plan, which has important engineering reference significance. However, the study area is currently in the pre-feasibility stage. Due to the lack of core data, A simplified homogeneous geological model was established in the study. Compared with the heterogeneous model, the total amount of CO₂ injection in the homogeneous model is significantly increased due to the influence of reservoir heterogeneity on the formation of CO₂ migration channels. So, the discussion of CO₂-EWR technology with different production/injection well ratios (PIR) is the focus of this research.

4.2.1. Model Building

The model is simulated and analyzed using ECO2N module on the TOUGH2 software, which has high stability and reliability during the numerical simulation process in the condition of homogeneous media. 3D geological modeling was conducted on the selected sites of Kp₃ and Kp₂ sections. Using the top and bottom elevations collected from drilling data, the strata were specifically divided into four sets of reservoir-cap combinations. Based on the assumption that the site strata are generalized as horizontal strata, the geological model range was set to X: 0 m~7500 m, Y: 0 m~7500 m, and Z: −1100 m~−2500 m. The formation thickness is 1400 m, and the sand to soil ratio is 0.47. The cube grid generation method was used, with 50 grids in the X and Y directions and 25 grids in the Z direction, for a total of 62,500 grids in the model (Figure 4). The boundary condition is set as a closed boundary.

4.2.2. Model Parameter Settings

The stratigraphic parameters were assigned values with reference to the actual information acquired at the site. The formation is set at a uniform temperature of 55 ℃. Based on the analysis and division of formation parameters, the formation was divided into 8 layers for simulation. As shown in

Table 2. Setting of formation porosity and permeability parameters.

Formation	Reservoir Cap Rock	Lamination	Top Buried Depth m	Thickness m	Porosity	Permeability mD
Kp3	Caprock	layer1	−1100	400	0.01	0.1
	Reservoir	layer2	−1500	60	0.054	6.65
	Caprock	layer3	−1560	125	0.01	0.1
	Reservoir	layer4	−1685	115	0.054	6.65
	Caprock	layer5	−1800	130	0.01	0.1
Kp2	Reservoir	Layer6	−1930	230	0.061	8.9
	Caprock	Layer7	−2160	90	0.01	0.1
	Reservoir	Layer8	−2250	250	0.061	8.9

Note: Layers 2–8 refer to the injection and extraction intervals.

, the single-layer porosity and permeability were assigned based on the average porosity and permeability data of the corresponding layers (Figure 5). The formation pressure is calculated as follows:

P = 1.013 × 10⁵ − 10⁴ × Z

(3)

where P is formation pressure, Z is the depth.

5. Numerical Simulation Analysis

5.1. Scenario Settings

In the water displacement potential evaluation, different production/injection well ratios (PIR) have been set up (i.e., 1 injection well and 1 production well (PIR is 1), 1 injection well and 2 production wells (PIR is 2), and 1 injection well and 4 production wells (PIR is 4)) (

Table 3. Scenario settings of injection.

Order Number	Production/Injection Well Ratio (PIR)	Injection and Extraction Spacing (km)	Injection Rate (10,000 tons/year)	Pumping Pressure (MPa)	Pumping Time
Case 1	1	2 km	50	20.2	100 yr
Case 1	1	2 km	100	20.2	100 yr
Case 1	1	2 km	200	20.2	100 yr
Case 2	2	2 km	50	20.2	100 yr
Case 2	2	2 km	100	20.2	100 yr
Case 2	2	2 km	200	20.2	100 yr
Case 3	4	2 km	50	20.2	100 yr
Case 3	4	2 km	100	20.2	100 yr
Case 3	4	2 km	200	20.2	100 yr

, Figure 6). The injection wells utilize constant flow and constant speed injection methods. Three different injection rate schemes have been designed: 0.5 million tons/year, 1 million tons/year, and 2 million tons/year. The bottom pressure of the production well was set at a constant value of 19.6 MPa. The production index is 4 × 10⁻¹² m³, and the gradient is set to 3. Different PIR scenarios were continuously running for 100 years to evaluate the water displacement potential of CO₂.

5.2. Evaluation

The combination of CO₂ geological storage and deep salt water extraction could enhance storage safety while obtaining substantial groundwater resources. This evaluation examined multiple options for water displacement potential evaluation. The problems that may be encountered in actual engineering were taken into consideration. Specifically, research works in three aspects (i.e., the CO₂ spatial distribution, reservoir pressure changes, and cap rock sealing) were conducted.

5.2.1. CO₂ Spatial Distribution in Different Scenarios

Different CO₂ injection schemes can form different spatial distribution characteristics of CO₂. Figure 7, Figure 8, Figure 9, Figure 10, Figure 11, Figure 12, Figure 13, Figure 14 and Figure 15 show the spatial distribution of CO₂ after 30, 50, 70, and 100 years of simulation for three PIR scenarios. At the same injection rate (Figure 7, Figure 10 and Figure 13), the CO₂ plume is asymmetrically distributed under the scenarios of PIR = 1, while the CO₂ plume is symmetrically distributed under the schemes of PIR = 2 and PIR = 4. This is due to the influence of the pressure difference, and the CO₂ plume will preferentially expand in the direction of the production well, indicating that the distribution of the production wells will affect the spatial distribution of the CO₂, which in turn affects the amount of CO₂ trapped.

Through comparison, it can be found that make the PIR = 1 with injection rate of 0.5 million tons/year as an exception, the CO₂ plume boundary has all reached the location of the extraction well after 100 years of continuous operation in other design schemes. As shown in Figure 16, with the same PIR, a higher injection rate results in a shorter time for the CO₂ plume to reach the production wells. This suggests that a higher injection rate can improve CO₂ storage efficiency. Additionally, with the same injection rate, the time for the CO₂ plume to reach the production wells is inversely proportional to the number of production wells, indicating that increasing the number of production wells can lead to greater CO₂ storage.

5.2.2. Reservoir Pressure Changes in Different Scenarios

Figure 17 illustrates the change in injection well pressure with time under different injection scenarios. It can be seen that the trend of reservoir pressure change is the same under different scenarios. Initially, the reservoir pressure increases rapidly. As salt water is extracted by the production wells, the pressure of injection well gradually decreases and then tends to stabilize. Subsequently, there is an increasing trend of reservoir pressure. The fixed operating conditions for 50 years demonstrate that the stable injection pressures are 28.44 MPa, 25.87 MPa and 24.58 MPa for the scenarios PIR = 1, PIR = 2 and PIR = 4, respectively. So with the increase in the number of production wells, the reservoir pressure decreases, indicating that the increase in the number of extraction wells has significantly reduced reservoir pressure and the risk of CO₂ leakage. As shown in Figure 17, When the PIR = 1, the reservoir pressure began to rise rapidly after sixty years of CO₂ injection. This could be attributed to the fact that pressure build-up from CO₂ sequestration cannot be effectively reduced by relying on only one production well. While the PIR = 3, Reservoir pressure can eventually maintain a stable value as injection time increases. Therefore, when the PIR is low, prolonged CO₂ injection may cause the reservoir pressure to rise, potentially causing CO₂ to leak if the cap breaks.

5.2.3. Sealing of Cap Rock under Different Scenarios

The storage capacity of the system is primarily limited by the time required for the CO₂ plume to reach the production wells. As shown in Figure 16 and Figure 18, with the injection rate of 1 million tons per year, the free CO₂ gas appears in the production wells after approximately 61, 54, 53 years under different PIR conditions, which implies that CO₂ will begin to leak as the continue exploitation of deep saline water. Thus, under the premise of restricted system storage capacity, it was found that the time for the CO₂ plume to reach the production wells decrease as the increase in production wells number. It is indicated that CO₂ can be injected for shorter periods of time with the PIR increases.

Figure 19 displays the vertical saturation of CO₂ within the Injection well at the point of cap rock breakthrough in different injection scenarios under the premise of unrestricted system storage capacity. The vertical gas saturation of different scenarios basically coincides when the CO₂ plume reaches the production wells, with only differences in breakthrough time. It is also shown that the gas saturation is increased with the increase in the number of the production well, which demonstrates that increasing the number of production wells can lead to greater CO₂ storage. As shown in Figure 20, during cap rock breakthrough, the CO₂ injection volume is 61 million tons, 80 million tons, and 95 million tons, respectively, for the scenarios of PIR = 1, PIR = 2 and PIR = 4. The total water production of the production wells is 102 million tons, 95.9 million tons, and 74.3 million tons, respectively. So, When PIR = 4, the total CO₂ injection increased by 55.73% compared to PIR = 1. The CO₂ displacement saltwater coefficients are 1.67, 1.20, and 0.78, respectively. Thus, under the premise of unrestricted system storage capacity, when a cap rock breakthrough (leakage) occurs, the amount of CO₂ injection increases and the total amount of water extracted decreases as the increase in production wells. Although increasing the PIR reduces the total time of CO₂ injection, it also increases the total amount of CO₂ injected. As the PIR increases, however, total water production decreases. As previously mentioned, a lower number of producing wells leads to increased reservoir pressures during extended CO₂ injection. Consequently, higher PIRs lead to greater returns.

6. Conclusions

Based on the multi-source information superposition evaluation technology, the potential target areas of CO₂ saline water storage and water displacement are evaluated and optimized in Huaiyin Sag. Then, the potential of the application of CO₂-EWR technology is evaluated by numerical simulation, and the spatial distribution of CO₂, reservoir pressure change and cap sealing under different scenarios are discussed. The main conclusions are as follows:

(1) Considering various factors including regional geology, reservoir cap rock combination, and physical parameters in the study area, and following principles of the assessment for site selection of CO₂ saline water reservoir storage, the suitability of the surrounding area of Huaiyin Power Plant is divided into two levels: relatively suitable and generally suitable, in which the general suitable area accounts for over 80%.

(2) Different CO₂ injection schemes can result in different spatial distribution characteristics of CO₂. The CO₂ storage capacity of a site increases with the number of production wells, while maintaining the same injection rate. The higher the injection rate is, the faster the CO₂ plume expands.

(3) When CO₂ is injected into the formation, the reservoir pressure experiences a rapid increase followed by a decrease, and then another increase. The changes in reservoir pressure in different scenarios indicate that the higher the number of production wells, the lower the stable injection pressure.

(4) It was found that increasing the number of production wells leads to a shorter time for the CO₂ plume to reach them. Under the premise of unrestricted system storage capacity, when a cap rock breakthrough (leakage) occurs, the amount of CO₂ injection increases and the total amount of water extracted decreases as the increase in production wells. This also results in a smaller coefficient of CO₂ displacement for saline.