Wei Liu
,
Xiong Zhang
,
Jifang Wan
,
Chunhe Yang
,
Liangliang Jiang
,
Zhangxin Chen
,
Maria Jose Jurado
,
Xilin Shi
,
Deyi Jiang
,
Wendong Ji
,
Qihang Li
Underground salt cavern CO2 storage (SCCS) offers the dual benefits of enabling extensive CO2 storage and facilitating the utilization of CO2 resources while contributing the regulation of the carbon market. Its economic and operational advantages over traditional carbon capture, utilization, and storage (CCUS) projects make SCCS a more cost-effective and flexible option. Despite the widespread use of salt caverns for storing various substances, differences exist between SCCS and traditional salt cavern energy storage in terms of gas-tightness, carbon injection, brine extraction control, long-term carbon storage stability, and site selection criteria. These distinctions stem from the unique phase change characteristics of CO2 and the application scenarios of SCCS. Therefore, targeted and forward-looking scientific research on SCCS is imperative. This paper introduces the implementation principles and application scenarios of SCCS, emphasizing its connections with carbon emissions, carbon utilization, and renewable energy peak shaving. It delves into the operational characteristics and economic advantages of SCCS compared with other CCUS methods, and addresses associated scientific challenges. In this paper, we establish a pressure equation for carbon injection and brine extraction, that considers the phase change characteristics of CO2, and we analyze the pressure during carbon injection. By comparing the viscosities of CO2 and other gases, SCCS’s excellent sealing performance is demonstrated. Building on this, we develop a long-term stability evaluation model and associated indices, which analyze the impact of the injection speed and minimum operating pressure on stability. Field countermeasures to ensure stability are proposed. Site selection criteria for SCCS are established, preliminary salt mine sites suitable for SCCS are identified in China, and an initial estimate of achievable carbon storage scale in China is made at over 51.8-77.7 million tons, utilizing only 20%-30% volume of abandoned salt caverns. This paper addresses key scientific and engineering challenges facing SCCS and determines crucial technical parameters, such as the operating pressure, burial depth, and storage scale, and it offers essential guidance for implementing SCCS projects in China.
The Paris Agreement has established a long-term global climate change control target of limiting the temperature increase to 2 °C [1], [2]. Climate change is considered the greatest threat to human beings and the global ecosystem in the future. Climate change is primarily driven by greenhouse gases, including CO2, CH4, and nitrogen oxides (NxO) [3], [4]. In response to this challenge, the Chinese government has outlined the goal of reaching a carbon emissions peak and achieving carbon neutrality. As the world’s largest carbon-emitting country [5], [6], [7], China has encountered various challenges in the process of transitioning to a net-zero emissions society. In view of China’s total CO2 emissions reaching 10.88 Gt in 2019 [8], there is an imperative and urgent need for substantial carbon emission reduction on a large scale [9], [10].
Carbon capture, utilization, and storage (CCUS) technologies, as a potentially effective means of reducing net CO2 emissions, are gaining global attention [11], [12], [13], [14], [15]. CCUS involves capturing, transporting, utilizing, and storing (or sequestering) CO2. This process entails on-site capture from sources such as power and steel plants, and subsequent transportation to nearby storage or reuse sites [16], [17], [18]. CCUS converts CO2 into valuable raw materials that can be processed into high-value products, such as methane, methanol, and carbonate [19], [20]. Various CO2 capture technologies exist, including pre-combustion capture [21], post-combustion capture [22], oxy-fuel combustion capture [23], and atmospheric CO2 capture [24]. Post-combustion capture is commonly used in the industrial environment because of its high CO2 selectivity and capture efficiency in industrial settings [25]. Direct air capture, another technology, is a method for achieving negative emissions that removes carbon from the environmental cycle, however, it is the most expensive CO2 capture method [26]. CO2 transportation typically utilizes tanks, ships, and pipelines, and pipeline transport has been a well-established technology since 2005 [27].
The key technology and economic feasibility of CCUS are defined by the utilization of CO2, including physical, chemical, biological, and mineral utilization [25]. Physical utilization includes CO2-enhanced oil recovery (EOR), an established oilfield development technology that contributes to the production of approximately 5% of the total crude oil in the United States [28]. Given that over 90% of global oil reservoirs are suitable for CO2-EOR, this method could potentially utilize and store around 70-140 gigatons of CO2 [29]. Notably, CO2-EOR is the predominant mode of CCUS in China [30], and it is exemplified by the Qilu Petrochemical-Shengli Oilfield CCUS project, the country’s largest CCUS industry chain demonstration base, which is a CO2-EOR project. In addition, the methanation of CO2, integrated with renewable energy sources such as wind, solar, and hydro-power [31], [32], represents an emerging carbon cycle paradigm [33]. This approach addresses the limitations of power-to-gas [34]. The Chinese government has outlined an ambitious carbon storage plan, which aims to achieve the carbon storage goal. Despite the existence of 40 operating CCUS projects in China, the current total carbon injection is only 3 million tons per year. This shortfall highlights the urgent need for new and large-scale carbon storage technologies. Storing CO2 in salt caverns is a promising solution. It provides a renewable and sustainable method for utilizing CO2 as a valuable industrial resource. It is a novel carbon storage technology capable of realizing large-scale carbon storage in a short period of time [35], [36].
Zhang et al. [33] introduced an innovative carbon cycle centered on salt cavern CO2 storage (SCCS), which is designed to absorb surplus off-peak renewable energy and provide a substantial power output during peak demand. This approach validated the short-term feasibility and stability of SCCS. In addition, various methods for utilizing CO2 in CCUS can be employed, highlighting the potential pivotal role of SCCS in CCUS. The continuous concentration of CO2 at on-site sources, such as fossil fuel power plants, contrasts with the intermittent nature of downstream markets. Hence, the feasibility of CCUS projects relies on large-scale underground storage formations, such as depleted gas reservoirs, saline aquifers, and mined goafs. Among all potential storage formations, underground salt caverns, which have excellent sealing performance and favorable storage capacity, emerge as a very promising option.
Salt caverns, formed through water solution mining in underground rock salt formations [37], [38], are widely recognized as secure and cost-effective underground structures for large-scale energy storage and waste disposal [39], [40], [41], [42]. Salt caverns have been extensively utilized for storing petroleum [43], [44], natural gas [45], and compressed air (for compressed air energy storage (CAES) plants), and notably, they have been the sole successful underground space for hydrogen storage [41], [46], [47], [48] (Fig. 1 [49], [50], [51]). Despite being well-established for various applications, limited research has been conducted on SCCS, and existing studies have often drawn on experiences in underground gas storage (UGS) [52], [53], [54]. Zhang et al. [33] highlighted the differences between UGS and SCCS, and noted that these distinctions could be mitigated through injection-withdrawal cycles. Wei et al. [55] delved into the potential economic and engineering challenges of SCCS, and modeled the impacts of the injection rate and minimum operating pressure on feasibility and usability. Liu et al. [36] developed a numerical model for supercritical (SC)-CO2 storage in salt caverns, and found that the suitable working condition of this model is 11.0-18.4 MPa and the injection and production frequency is four cycles within 100 years of operation. Mwakipunda et al. [56] demonstrated that salt caverns are an available option for CO2 sequestration when other CO2 geological storage options are not available. Pajonpai et al. [52] evaluated five cavern shapes (spherical, bulb, teardrop, pear, and cylindrical) of SCCS in northeast Thailand. da Costa et al. [57] studied the feasibility of storing high CO2 content gas in ultra-deep underwater salt caverns.
The comprehensive review of the above references revealed that present research on SCCS is still insufficient and far from providing reliable guidance for engineering applications. The crucial issues that require attention include: ① the operational scenarios that align SCCS with carbon storage/utilization, ② the control theory governing CO2 injection and brine extraction, ③ the stability and operation of SCCS processes, ④ determining the economic feasibility at different SCCS storage scales, and ⑤ establishing national and international regulations for carbon market governance.
To comprehensively address these issues and provide informed insights for SCCS projects, in this study, we conducted an initial investigation to support China’s carbon peak and carbon neutrality objectives. The remainder of this paper is organized as follows (Fig. 2): Section 2 introduces the basic concept of SCCS, explores its various scenarios in conjunction with carbon storage and utilization, and discusses the scientific challenges of SCCS. Section 3 compares the gas properties of CO2 with those of other gases and assesses the gas-tightness of SCCS. Section 4 presents a method for calculating the CO2-brine interface pressure, which is supported by a geometric model derived from numerical simulations. Section 5 scrutinizes the results of CO2 injection and brine extraction. Section 6 presents the numerical findings and analyzes the impacts of the injection rate and minimum operating pressure. Finally, in Section 7, we delve into the storage capacity of a single cavern for carbon storage, project the carbon storage scale, and assess the potential nationwide implications of SCCS across China. The paper addresses key scientific and engineering challenges facing SCCS and determines crucial technical parameters, such as the operating pressure, burial depth, and storage scale, and provides essential guidance for implementing SCCS projects in China and abroad.
2. Concept and scientific issues of SCCS
2.1. Basic concept and usefulness of SCCS
At present, the main geological carbon sequestration spaces include deep saline aquifers, oil/gas reservoirs, and non-mining coal seams [58], [59], [60], [61], [62]. However, most existing geological CO2 sequestrations, except for EOR-CCUS, treat CO2 as waste, which has little economic benefit, thus greatly reducing the enthusiasm of the parties involved due to a lack of profit. At the same time, not every place has the geological conditions to meet the requirements of CO2 storage or EOR-CCUS projects and transporting CO2 for disposal over a long-distance will greatly increase the transport cost.
If CO2 can be captured from industry and/or combustion processes and used in different fields, converting CO2 from waste into useful products, this can effectively reduce CO2 emissions and hence increase enthusiasm for CCUS projects. In fact, CO2 is already an important industrial resource, and it is widely used in industrial production, renewable energy, unconventional natural gas development, and among other fields [63], [64]. The most common uses are described below:
(1) Conventional industrial fields. CO2 can be used to prepare fire extinguishers, chemical coils, cleaning agents, and raw materials for alkali production.
(2) Renewable energy. Excess renewable energy is used to electrolyze water to generate a large amount of hydrogen. Once hydrogen is converted into other forms of energy, such as synthetic natural gas, methanol, diesel oil, aircraft fuel, and so forth, its use can be expanded, and the dependence on fossil energy to produce these energy forms can be reduced. Common chemical pathways include CO2 + H2 → CH4 + H2O and CO2 + H2 → CH3OH + H2O.
(3) Unconventional natural gas development. Many studies [65], [66] have pointed out that SC-CO2 can be used as an auxiliary fracturing fluid for unconventional gas reservoir development. More effective reservoir fracturing than methane can be achieved due to the stronger adsorption performance (competitive adsorption) of CO2 to the reservoir’s matrix (e.g., coal seam and shale). In addition, CO2 can be sealed in-situ.
We consider carbon capture as an upstream process and carbon utilization as a downstream one. In this way, there is a huge spatial-temporal difference between the two, which make it impossible to fully utilize the captured carbon or to seal it in time. For example, during the peak period of electricity consumption in winter, the carbon emission of the coal-fired power industry (upstream) is relatively large, while gas reservoir fracturing (downstream), CO2 is intermittently injected, and there is usually less operation in winter. There are also market fluctuations in carbon price, which have a certain impact on carbon utilization. To solve the differences and expectations between carbon capture and carbon utilization in time, space, and market, it is still necessary to find a non-aquifer underground space for storage. This type of underground space is termed an open-source mode, which does not only store CO2 economically and on a large scale, but also provides flexible access when necessary. To a certain extent, SCCS satisfies these requirements. An implementation roadmap that adopts SCCS as a node (middle-stream) to achieve future carbon reduction and carbon utilization is shown in Fig. 3.
Compared with other carbon storage models, SCCS can benefit all participants. For the salt cavern owners, they can rent the salt caverns for storage or store carbon on their behalf. When injecting carbon, the brine is removed from the cavern and can be sold, and the release of stored carbon can also be profitable. For carbon emitters, SCCS increases the choice of carbon disposal. By adopting SCCS, they may pay less carbon tax or avoid it altogether, while reducing the cost of long-distance pipeline construction and CO2 transportation. For carbon-using enterprises, they can buy carbon at a lower price from carbon emitters/cavern owners at a close distance, or they can replace their own carbon emissions with carbon demand, thus reducing unnecessary transportation storage, or purchase fees.
Assuming that a single salt cavern has a volume of 500 000 m3 with a burial depth of 800-2 000 m, based on our previous study, the maximum CO2 storage is over 350 000 tons, and the single amount of recoverable carbon is as high as 300 000 tons [33]. Moreover, SCCS is different from traditional CCUS projects because CO2 can be injected into and withdrawn from salt caverns. In addition, multiple injection-production cycles can be carried out per year. The total amount of carbon used (which can be regarded as a carbon neutral amount) will be significant. Therefore, it is entirely possible for a group of salt caverns to store (and later, supply) millions of tons of carbon. As a result, in a relatively closed area (such as a large industrial park or a city), if there are upstream carbon emissions, midstream salt caverns, and downstream carbon demands (which may also be carbon emitters), a carbon-chain with SCCS as a regulator can be constructed.
2.2. Scenarios and advantages of SCCS
Salt caverns have excellent stability and tightness compared with other underground space, and the relevant gas and oil storage theories, technologies, and equipment are relatively mature, thus providing a strong foundation for implementing carbon storage. Therefore, SCCS is expected to become an increasingly important option for the large-scale temporary or long-term storage of CO2. As shown in Fig. 4, after the completion of CO2 injection and brine extraction, the anticipated application scenarios of SCCS are as follows.
Scenario 1: Salt caverns are used for long-term storage of CO2 (a non-permanent situation) [33]. The rock salt creeps, thus leading to salt cavern shrinkage and causing the carbon dioxide pressure to rise beyond the limit). That is, CO2 is injected into a salt cavern and stored in the SC state. The storage density of CO2 exceeds 700 kg·m−3, and a single cavern with a volume of 500 000 m3 can store more than 350 000 tons of CO2. We have confirmed that for depths of 800-2 000 m, SCCS can be safely achieved for hundreds to thousands of years [33].
Scenario 2: A large amount of CO2 storage with a small amount of CO2 utilization. At present, CO2 utilization technology is immature, and the cost of carbon utilization is still high, so the CO2 utilization scale remains small. A large amount of CO2 is stored in caverns, accompanied by small amounts of carbon withdrawal for use and CO2 re-injection. CO2 is still stored in a SC state, and the carbon pressure in the caverns experiences low frequency injection and extraction. This working condition is expected to become the most feasible mode of SCCS in the near future.
Scenario 3: High-frequency injection and withdrawal of CO2 in salt caverns. In the future, CO2 utilization technology will mature, the cost will be greatly reduced, and the scale will be greatly increased. Similar to the peak-shaving function of gas storage, SCCS will play the role of a regulator to solve the temporal and spatial differences between CCUS. With only a certain amount of CO2 storage, SCCS can become an indispensable link in serving the carbon cycle market through frequent carbon injection and extraction.
The difference between the above three scenarios is: Scenario 1 refers to carbon sequestration, in this way, CO2 can be sealed safely underground for hundreds to thousands of years. Scenarios 2 and 3 both are methods for CCUS, CO2 stored will be extracted for utilization. Scenario 2 is temporal due to immature CO2 utilization technology, while scenario 3 is carbon storage with frequent CO2 injection and withdrawal.
Meanwhile, the above three scenarios can be transformed into each other. Accordingly, with market and technology requirements, the carbon storage injection-extraction modes can also be flexibly switched. SCCS has multiple values of short-term temporary storage to help reduce emissions, medium-term large-scale storage, and long-term regulation of the carbon market, which should significantly promote the important transformation of carbon as a waste to industrial resources, while becoming an important auxiliary means of carbon emission reduction and neutralization.
2.3. Scientific challenges of SCCS
As mentioned earlier, although salt caverns have been successfully used to store oil, natural gas, compressed air, and even hydrogen, the nature of CO2 itself is somewhat different from other stored gases, so the working scenarios of carbon storage in salt caverns are also different [35], [56].
(1) Gas-tightness of SCCS. The gas-tightness of bedded salt rocks for SC-CO2 absolutely determines the feasibility of SCCS. As is well known, SC-CO2 is characterized by strong diffusion and permeability [67]. What are the differences in permeability between it and other gases in the surrounding rock of salt caverns, and does it pose a risk of leakage? This is the first question to be answered for carbon storage in salt caverns.
(2) The pressure control theory of carbon injection and brine extraction. CO2 has typical phase transition characteristics, and its density exhibits nonlinear changes with pressure, resulting in a non-linear pressure distribution from the ground surface to an underground salt cavern [36]. In addition, traditional gas storage is based on a constant amount of brine discharge, which in turn designs the gas injection rate and wellhead pressure, while salt cavern carbon injection and brine extraction are based on a constant amount of carbon injection and a variable amount of brine discharge. These all make the control of carbon injection and brine extraction much more complex than conventional gas injection and brine extraction, making it more difficult to establish corresponding pressure and displacement control equations.
(3) Long-term stability of SCCS. SCCS not only has a regulatory effect on the carbon market (promoting carbon utilization and improving carbon cycle efficiency), but also plays a significant role in carbon sequestration. Therefore, the evaluation of the stability of salt cavern carbon storage should consider a much longer service life than that of conventional gas storage, as well as a certain amount of carbon injection and extraction [33], [36]. To ensure the long-term stability of salt cavern carbon storage, how to scientifically set the carbon storage pressure, injection and production frequency, and pressure rise and fall is also a scientific question that should be focused on and clearly addressed [36].
(4) Site selection criteria and storage capacity of SCCS. Before it reaches the SC state, the density of CO2 rapidly increases with pressure, and then, it slowly increases with pressure. This indicates that underground carbon storage has clear pressure and temperature requirements, and accordingly, in order to ensure the density and economy of carbon storage, it is necessary to select salt caverns with an appropriate depth range for carbon storage. Meanwhile, SCCS is closely related to upstream carbon emissions and downstream carbon utilization, and has requirements for site selection, cavern volume, and so forth. Finally, what are the salt mines currently suitable for building SCCS plants in China, and how much carbon storage potential they have? These are scientific questions that need to be answered.
(5) Other noteworthy issues. CO2 has strong water solubility and corrosiveness [68], and the impacts of these properties on gas injection, brine extraction, specialized equipment, and pipe columns also need to be considered when conducting SCCS.
In summary, there are still many unresolved scientific issues related to SCCS, especially the first four aspects, which are the key focus regarding the safety and economic feasibility of SCCS technology. This paper mainly focuses on these four aspects. A proposed SCCS plant in Pingdingshan City, China, serves as a case study to provide theoretical and technical support for the design and operation of SCCS plants in China. The main key scientific issues of SCCS in China are illustrated in Fig. 5.
3. Gas-tightness of SCCS
In foreign countries, most salt cavern energy storage (SCES) facilities have been constructed in salt domes or thick salt formations, and the tightness of surrounding rocks of the caverns is usually excellent. The salt beds in China are mainly bedded salt rocks, which contain non-salt interlayers. The gas-tightness of the surrounding rock of cavern is usually lower than that in salt domes and thick salt formations. However, to this day, there are more than ten operations, under construction, and planned salt cavern gas storage or CAES facilities. These projects fully demonstrate that the bedded salt rocks in China also have satisfied gas-tightness for high-pressure gas storage. Through nearly 20 years of SCES research and construction in China, rich theories, technologies, data collection, and experiences related to bedded salt rocks have been accumulated, which provide necessary preparations for the implementation of SCCS in China.
It can be foreseen that since most of the bedded salt rocks in China meet the gas-tightness for natural gas, air, and hydrogen storage, there is a high possibility of meeting the sealing requirements for storing CO2. Therefore, this chapter first compares CO2 with other salt cavern storage media and preliminarily determines the gas-tightness performance of bedded salt rock for CO2 storage based on gas properties. Then, considering that viscosity is a key factor affecting the permeability of gas in porous media, the viscosity of CO2 was mainly analyzed. And based on this, a clear answer was given to the sealing capacity of the surrounding rock for SCCS.
3.1. Comparison of properties of gases
Common indicators for characterizing gas properties include the molecular diameter, gas viscosity, and compressibility. CH4, air, H2, He, and CO2 were selected for comparison, and their properties are listed in Table 1. In addition, the corresponding operating conditions for storing different media in salt caverns were also compared. As can be seen from Table 1 [69]. ① The molecular diameters of these gases are not significantly different. That of CH4 is the largest, followed by CO2, H2, and He. ② Under the conditions of a temperature of 313.15 K and pressure of 15 MPa, the viscosities of the gases vary greatly. CO2 has the highest value, followed by air, He, CH4, and H2 has the lowest viscosity. Usually, the viscosity of a gas is an important factor affecting its permeability in porous media. Therefore, it can be speculated that CO2 has the highest viscosity. Thus, theoretically speaking, CO2 has the weakest permeability in porous media. ③ The compression coefficient of CO2 is the smallest, indicating that CO2 is more easily compressed and a higher storage density can be achieved through further compression, while H2 has the highest compression coefficient. ④ The storage period for natural gas, compressed air, H2, and He is generally 30 years, but the corresponding injection and production frequencies vary greatly. It is recommended to consider a service life of over 50-100 years even longer for SCCS, with high-pressure storage being the main consideration. It is difficult to indicate the gas-tightness of the surrounding rock for carbon storage through this table, but it is of high possibility that carbon storage has better gas-tightness in salt cavern.
3.2. Gas-tightness evaluation of SCCS
In unconventional oil and gas development, SC-CO2 is regarded as an excellent fracturing fluid, with strong diffusibility, high permeability, and low viscosity. However, these properties are relative to water-based fracturing fluids, such as active water, the viscosity of which is close to that of pure water [70]. In fact, compared with other gases, the viscosity of CO2 is much higher after it reaches the its SC state.
The permeability coefficient is generally considered as an inherent property of porous media, and it is not affected by the type of porous media. But permeability is a parameter closely related to the viscosity and density of fluid. Generally, viscosity is an important factor affecting the fluid’s permeability in porous media. Generally, the higher the viscosity of gas, the lower its permeability in the same rock medium. The viscosity of water and oil is much higher than that of gas, so the permeability of gas measurement is much higher than that of liquids measurement. Darcy’s Law can clearly reflect the influences of the viscosity of fluids [71], [72], [73]:
where v is the seepage velocity of fluids in the porous media (m·s−1); μ is the viscosity of fluids (mPa·s), K is the permeability (m2), which is only related to the properties of solid skeleton, and $ \frac{\mathrm{d} p}{\mathrm{~d} l}$ is the pressure gradient (Pa·m−1).
Because many salt mines in China have been served as demonstration sites for the storage of natural gas (CH4) and compressed air, the permeability of CO2 in bedded rock salt can be visualized by comparing the viscosity of CO2 with those of CH4, H2, He, and air under the same conditions.
The dynamic viscosities of CO2, CH4, H2, He, and air at the same temperature and different pressures were calculated using the Refprop software [74] and were plotted (Fig. 6(a) [69]). It can be seen that as the pressure increases (a higher pressure strengthens the molecular interaction), the viscosities of all of the gases increase, but after the critical state is reached, the viscosity of CO2 increases rapidly. The comparison can be divided into two stages. ① At a pressure below the SC pressure of CO2, the dynamic viscosity of CO2 is between those of CH4 and air, so it can be predicted that the permeabilities of these three gases in the same rock medium are also close. ② When the critical pressure of CO2 is reached, the dynamic viscosity of CO2 increases rapidly. After the critical pressure of CO2 is exceeded, the viscosity of CO2 becomes much higher than those of CH4, H2, He, and air, and the gap further widens with increasing pressure. Therefore, it can be inferred that after exceeding the critical pressure of CO2, the permeability of CO2 in rocks is much lower than those of CH4, H2, He, and air because of its higher viscosity. This condition is extremely beneficial to sealing in SCCS and helps to further reduce the site selection requirements of SCCS. Similarly, the dynamic viscosity of CO2 at different temperatures was calculated using the Refprop software (Fig. 6(b)). When the pressure exceeds the SC pressure, the dynamic viscosity of CO2 decreases with increasing temperature, which imposes higher requirements for the tightness of deep SCCS. Thus, the appropriate burial depth is an important index for meeting the tightness requirements of SCCS. Moreover, the properties of CH4, air, H2, He, and CO2 were compared (Table 1). The dynamic viscosity of H2 is the lowest, only half those of CH4, air, and He, and the dynamic viscosity of CO2 is highest, almost three times of CH4, air, and He. Therefore, once the salt mine is suitable for natural gas or CAES, it is believed that it can also satisfy the gas-tightness of CO2 storage when the pressure exceeds the SC value for CO2.
4. Theories and models of SCCS
4.1. Operation process
As shown in Fig. 7, SCCS involves four stages. In the injection period: stage I, in a brine-filled salt cavern, CO2 is injected through a well space and discharge brine from another pipe space. This process usually lasts several months or longer until the brine is completely discharged. Stage II: this stage begins with the continuous injection of CO2 to increase the operating pressure. It lasts until the operating pressure reaches the set maximum operating pressure (Pmax), which is generally set as 0.80-0.85 times the in-situ vertical stress at the roof of the cavern. Stage III: There is no CO2 injection; the cavern continuously shrinks due to the creep behavior of the wall rock [46], [75], [76]. This fact that has been clarified by Zhang et al. [33]. Stage IV: CO2 is discharged at a specific speed and the operating pressure drops accordingly until the operating pressure reaches the set minimum operating pressure (Pmin). In the next cycle, there is no brine discharge and the process only consists of stages II, III, and IV.
4.2. Calculation model
Assumptions: ① The heat exchange is ignored in all stages due to the relatively slow process of the injection and withdrawal cycles. ② The dissolution of CO2 in brine is also ignored because of its relatively low solubility and the long time it takes to reach completely dissolved equilibrium [34].
Calculation process.
(1) Stage I: CO2 injection and brine extraction. In this stage, the gas pressure at the gas-liquid interface must balance with the brine pressure to ensure that the brine is displaced (Fig. 8). For natural gas storage, the change in the pressure at the gas-liquid interface in the process of gas injection and brine extraction is generally calculated according to the brine displacement. Subsequently, the wellhead pressure at the ground surface is determined by the height of the gas column, friction loss along the pathway, and brine pressure at the wellhead of the brine withdrawal pipe (the wellhead CO2 injection displacement is obtained at the same time). When natural gas is injected to remove brine, the density of the natural gas can be assumed to increase linearly from the wellhead to the gas-liquid interface in the salt cavern, so it is relatively simple to calculate the wellhead pressure. However, there are some differences when storing CO2 in salt caverns. First, the amount of brine discharged is determined by the amount of CO2 injected. Second, CO2 undergoes a phase change, which results in a nonlinear relationship between its density and pressure. The density of CO2 increases non-linearly from the surface wellhead to the gas-liquid (CO2-brine) interface, making the change in the pressure at the CO2 injection surface wellhead more complicated. Therefore, it is necessary to establish the relationship between the wellhead pressure and CO2-brine interface that is suitable for CO2, so as to provide a basis for the parameter design of CO2 injection and brine extraction.
The end condition is reached when the brine discharge reaches the set value. That is Vbrine(out) = Vcavern. Vbrine(out) is the volume of the brine discharged, and Vcavern is the volume of the salt cavern.
The key is to calculate the pressure at the CO2-brine interface. The pressure equilibrium is expressed as follows:
where Pinterface is the pressure at the CO2-brine interface; Pbw is the brine pressure at the wellhead of the brine withdrawal pipe (0.3 MPa); Pbrine is the brine pressure at the location of the CO2-brine interface (MPa), which is calculated by Eq. (3); Pf,brine is the frictional brine head loss at the brine withdrawal pipe (MPa), which is calculated by Eq. (4); PCO2 is the CO2 pressure at the location of the CO2-brine interface (MPa), which is calculated by Eq. (5); Pf,CO2 is the frictional CO2 head loss in the CO2 injection pipe (MPa), which is calculated by Eq. (6); and Pwellhead is the pressure of the ground wellhead (MPa), which is calculated by Eq. (7) [77].
$ P_{\text {brine }}=\rho_{\text {brine }} g H_{\text {interface }}$
where Hinterface is the depth of CO2-brine interface (m); g is gravitational acceleration (m·s−2); ρbrine is the brine density (kg·m−3); ρCO2 is the density of CO2 (kg·m−3); hf,brine is the frictional head loss of brine (m); and hf,CO2 is the frictional head loss of brine (m).
where, hf is the frictional head loss; de is the effective diameter of the pipe (for a circle, it is the diameter; for a ring it is the differential value of the outer and inner diameters). The diameter of the brine discharge pipe is 0.1143 m, and the diameter of the CO2 injection pipe is 0.1778 m. λ is the friction factor, which can be calculated by the Blasius formula [79]:
$ \lambda=\frac{0.316}{R e^{0.25}}$
where Re is the dimensionless Reynolds number, which can be calculated using the following formula:
$ \operatorname{Re}=\frac{\rho v d}{\mu}$
where d is the diameter of the discharge pipeline (m); ρ is the density of the brine or CO2 (kg·m−3).
Among them, the most important is the determination of the interface height Hinterface and brine velocity vbrine. For a given injection rate of CO2, the mass flow rate Qm is constant:
At the CO2-brine interface, if the interface pressure Pinterface is known, the Peng-Robinson equation of state (P-R EOS) can be used to establish the relationship between the CO2 pressure, temperature, and density [33], [80]:P=RTVmol-b-a(T)VmolVmol+b+b(Vmol-b)
where Vmol is the molar volume of the gas (L·mol−1), R is the universal gas constant (J·(mol·K)−1), Tr = T/TC is the reduced temperature, which is defined as the ratio of the temperature T to critical temperature TC. TC, PC, and w are critical temperature, pressure, and acentric factor, respectively, for CO2, with values of TC = 304.19 K, PC = 7.3815 × 106 Pa, and w = 0.2276 [81].
The above equations can be solved using an iterative method. At a given temperature T and pressure PCO2, the density ρCO2 can be obtained. Similarly, the volume flow rate can be obtained using Eq. (13).
$ \frac{\mathrm{d} m / \rho_{\mathrm{CO}_{2}}}{\mathrm{~d} t}=\frac{\mathrm{d} V_{\mathrm{CO}_{2}(\mathrm{in})}}{\mathrm{d} t}=Q_{\mathrm{V}}$
Connecting Eqs. (11), (12), (13), the relationship between Qm and QV can be established and the mass of CO2 can be converted to the volume of CO2.
The volume of CO2 injected VCO2(in) is equal to the volume of brine discharged Vbrine(out), so VCO2(in) can be obtained using Eq. (14):
The velocity of the brine in the discharge pipeline vbrine can be calculated as follows:
$ v_{\text {brine }}=\frac{4 Q_{V}}{\pi d^{2}}$
Based on the solution of the CO2-brine interface height Hinterface, it is easy to determine through analysis that the volume of CO2 injected VCO2(in) is equivalent to the volume of the cavity above the CO2-brine interface Vcavern,Hinterface namely, Vcavern,Hinterface=VCO2(in). Vcavern,Hinterface can be calculated using the following formula:
where AH is the cross-sectional area of the cavity at height H (m2).
Therefore, the height of the CO2-brine interface Hinterface can be obtained by combining Eqs. (14), (15), (16).
(2) Stage II: CO2 injection and pressurization. In the initial state of this stage, the CO2 pressure is P1, the density of the CO2 is ρ1, and the volume of salt cavern is V1. By continually injecting CO2, the set pressure value P2 is reached. At this time, the density is ρ2, the volume of the salt cavern is V2, and the CO2 injection rate is constant. At time t,
(3) Stage III: high pressure operation. In this stage, the initial CO2 pressure state is P2, and the density of the CO2 is ρ2. Because of the change in the volume of the cavern, the pressure varies. ① The creep of the rock salt causes the cavern to shrink, resulting in an increase in pressure. ② The operating pressure increases, the contracted part of the cavern rebounds, and the volume of the cavern increases, resulting in a pressure reduction.
In the initial state: P2, ρ2, and V2. In the intermediate states, P(t), ρ(t), and V(t). Regardless of gas filtration and the interaction between the CO2 and the surrounding rock, according to the principle of mass conservation,
where V(t) can be obtained via numerical simulation using the FLAC3D software [82], which will be introduced in the next section. Thus, ρ(t) is obtained, and subsequently, P(t) can be calculated according to P-R EOS. Next, P(t) is substituted into the creep calculation.
(4) Stage IV: CO2 discharge. In this stage, CO2 is continuously produced, and the pressure P3 is reduced to the set value P1 in a certain amount of time t2. Thus,
The idle salt caverns in the Pingdingshan salt mine, Henan Province, central China, were selected as a case study. This salt mine is characterized by many salt layers, small spacing between, and many thin mudstone interlayers. The salt caverns are irregular with complex boundaries, basically with a large lower part and a small upper part. One typical cavern was selected for evaluation. This cavern has a roof depth of 1250 m, a maximum radius of 30 m, a height of about 200 m, a top width of 40 m, and a bottom width of 60 m. Therefore, a simplified geometric model of a half cavern, which has a height of 900 m and a width of 600 m was constructed using the by Ansys software (version 19.2) [83]. The geometric model contains salt strata with a thickness of 300 m and eight mudstone interlayers with a mean thickness of 5 m. The thickness of the sediment at the bottom of cavern is 36 m. The generated model has 191 932 nodes and 1 094 994 elements. The effective volume (without sediment at the bottom of cavern) of the cavern is 296 814 m3. The model mesh was constructed using Ansys (shown in Fig. 9) and then was imported into FLAC3D (version 6.0) [82] for mechanical calculation. The geological model has fixed boundaries and stress, according to previous studies [84], [85], [86]. The basic mechanical parameters are shown in Table 2.
The Power-Moor steady-creep model is used for steady-creep calculation, which has been widely used for safety evaluation of salt cavern gas storage [87], [88], [89]. It is expressed as:
where $ \dot{\varepsilon_{\mathrm{t}}}$ is the steady state creep strain rate, s−1; A is a creep parameter, MPa−n·s−1, and n is another creep parameter; Q is the creep activation energy, J; RB is the Boltzmann gas constant, J·mol; and J2 is the second invariant of the deviatoric stress tensor, MPa2.
Considering that under different scenarios of carbon storage and utilization, the salt cavern may undertake different conditions of CO2 injection and withdrawal, we investigate the effects of CO2 injection rate and different internal pressure range variation in the salt cavern. The injection-withdrawal frequency of CO2 in the salt cavern is set as one cycle per year. During one cycle of injection-withdrawal, the injection time depends on the CO2 injection rate, the withdrawal time is set at 30 days, and the rest time is under a high-pressure state. There are two parameters that may be varied, the minimum operating pressure (Pmin) and the CO2 injection rate, both of which may affect the cavern stability. Stage I is too short, so we mainly focus on cavern stability in stages II, III, and IV under cyclic operating periods.
To analyze the effects of the CO2 injection rate and the minimum operating pressure of the SCCS, two simulation conditions were set. ① The simulated CO2 injection rate was set to 1000, 1500, 2000, 2500, and 3000 tons per day, which reflects the different CO2 storage and utilization conditions of scenarios 1 and 2. ② The minimum operating pressure (Pmin, which is usually greater than 0.3 times the in-situ vertical stress at the roof of the cavern [38], [90], [91]) was set to 0.30, 0.35, 0.40, 0.45, and 0.50 times the in-situ vertical stress at the roof of the cavern (σv0), while the maximum operating pressure (Pmax) was 0.8 times the in-situ vertical stress at the roof of the cavern (σv0).
5. Analysis on CO2 injection and brine extraction
5.1. Variation in pressure with injection volume
In the CO2 injection and brine extraction period, monitoring and solving for Pf,brine, Pf,CO2, and Pwellhead are necessary. Based on the calculation model described in Section 4, the variation in Pf,brine, Pf,CO2, and Pwellhead with the CO2 injection volume (injection rate is 1000 tons·d−1) were calculated. The results are shown in Fig. 10. Pf,brine, Pf,CO2, and Pwellhead all increase with the continuous injection of CO2. However, the changes are very small when CO2 is injected at a certain rate. For an injection rate of 1000 tons·d−1, with increasing CO2, injection Pf,CO2increases from 0.07 to 0.10 MPa, Pf,brine remains at about 0.26 MPa, and Pwellhead increases from 7.18 to 7.53 MPa. This indicates that for a certain injection rate, the change in Pwellhead is small. Further analysis shows that the interface between brine and CO2 increases from 1250.0 to 1413.7 m (buried depth of sediment), the density of CO2 increases from 688 to 729 kg·m−3, and the velocity of CO2 fluid decreases from 1.17 to 1.09 m·s−1 (due to the increase of CO2 density), accordingly, the velocity of brine fluid also decreases. Overall, the wellhead injection pressure changes little during the whole process of carbon injection and halogen discharge. It is to note that detailed interaction between CO2 and brine at the interface can be referred to Wang et al. [92], which provides insights into the mechanisms of CO2-liquid phase interactions at the pore scale, highlighting the correlation between CO2 pore occupancy and trapping efficiency, and offering comprehensive data for evaluating CO2 geological storage.
5.2. Variation in pressure with injection rate
The variation in pressure with injection rate is shown in Fig. 11. Pf,brine, Pf,CO2, and Pwellhead all increase as the CO2 injection rate increases. When the injection rate increases from 1000 to 3000 tons·d−1, Pf,CO2 increases from 0.10 to 0.67 MPa, which is relatively small. Pf,brine increases from 0.26 to 1.70 MPa, of which the increase rate is quite large, and Pwellhead increases from 7.53 to 10.36 MPa. It can be seen that the injection pressure (Pwellhead) is relatively large and increases rapidly with the increasing injection rate. A high injection rate leads to a huge increase of Pf,brine, which greatly improves the injection pressure at the wellhead. Higher CO2 injection rates will greatly increase the frictional head loss pressure, because the increase of the injection rate affects the fluid velocity (both brine and CO2). According to the calculation model in Section 4, the increase of fluid velocity greatly increases the frictional head loss pressure, thus changing the wellhead injection pressure. Higher injection rates bring higher wellhead injection pressures, which is unfavorable.
In addition, according to Eqs. (8), (9), (10), the burial depth of the brine-CO2 interface, the fluid velocity, and the pipeline diameter are the main factors affecting the frictional head loss along the way, and the frictional head loss along the pathway is positively correlated with the fluid velocity and the burial depth of the brine-CO2 interface. It is inversely correlated to the pipeline diameter, but the fluid velocity has a greater influence, followed by the buried depth of the brine-CO2 interface, while the pipeline diameter has the least influence. At present, the diameter of injection-production pipelines in China is relatively fixed (as mentioned in Section 4, the diameter of the brine discharge pipe is 0.1143 m, while the diameter of the CO2 injection pipe is 0.1778 m), so this factor can be temporarily ignored. However, the buried depth of the CO2-brine interface is controlled by the buried depth of the salt formation, so it is very important to choose a suitable buried depth of the salt formation to safely store CO2. If the salt cavern is too deep it may lead to excessive and unnecessary head loss along the way. Finally, the fluid velocity is the most important factor affecting such head loss, but it is an uncommon factor that can be controlled manually.
5.3. Variations in CO2 injection time with injection rate
It is very important to calculate the time required for the two stages in a salt cavern: ① CO2 injection and brine extraction and ② CO2 injection and pressurization. According to the definition presented in Section 4, the time required for these two stages can be calculated (Fig. 12). As the carbon injection rate increases from 1000 to 3000 tons·d−1 (1000, 1500, 2000, 2500, and 3000 tons·d−1), the time required for completion of stage I (CO2 injection and brine extraction) is 212, 142, 108, 87, and 73 d, respectively, and the time required to complete stage II (CO2 injection and pressurization) is 26, 17, 11, 8, and 6 d, respectively. Obviously, increasing the carbon injection rate greatly shortens the time required to complete stages I and II, but when the rate is increased to 2000 tons·d−1, the shortened time becomes lower. Moreover, the time required for stage I decreases, while the product of injection time and rate is not the same for different injection rates. For example, the injection time is 212 d at an injection rate of 1000 tons·d−1, with a product of 212 000 tons, while the injection time is 73 d at an injection rate of 3000 tons·d−1, with a product of 219 000 tons. Higher injection rates mean higher CO2 mass injection. This is because the higher mass flow will lead to higher pressure at the CO2-brine interface and lead to a higher CO2 density.
6. Evaluation of long-term stability
6.1. Indexes selected for analysis
Three indexes, including the salt cavern’s volume loss ratio (VLR), displacement of the wall rock, and safety factor volumetric ratio (SFVR) of the wall rock, are selected for further SCCS stability analysis.
6.1.1. Cavern VLR
As a widely used index for stability analysis of salt cavern gas storage [41], [43], [56], the VLR is a parameter that is closely related to the usability and stability of SCCS. Generally, the requirement for salt cavern gas storage is that the VLR should be less than 30% during the operating period. The VLR is defined as follows [93]:
where Vloss is the reduction in the volume of the salt cavern due to creep of the wall rock and V0 is the original volume of the salt cavern.
6.1.2. Wall rock displacement
The displacement of the wall rock is an intuitive index that is also widely used in underground engineering and is easy to monitor [94], [95]. Generally, the maximum displacement should be less than 10% of the radius of the salt cavern.
6.1.3. Wall rock safety factor (SF)
The SF is another widely used index for stability analysis in SCES [96]. It is calculated using the van Sambeek criterion [97]:
where bm is a material parameter with a value of 0.27 [95] and I1 is the first invariant of the stress tensor.
According to the previous studies [94], [96], 1.0 < SF < 1.5 indicates local damage, 0.6 < SF < 1.0 indicates failure, and SF < 0.6 indicates collapse.
Based on SF, the SFVR is proposed to provide a more intuitive knowledge about SF. The SFVR is defined as:
where VSF is the volume of the surrounding rock within the SF range.
In previous studies, SF contours were drawn for the surrounding rock salt caverns and provided an intuitive knowledge of their stability. However, salt caverns in China have been mainly constructed in bedded rock salts containing numerous interlayers [98], [99], [100], which are much harder than rock salt, and the SF is likely to be lower in the interlayers [43], [89], [101]. As the van Sambeek criterion was proposed based on rock salt, the interlayer group and sediment group in the FLAC3D model were not selected for the SFVR calculation. That is, only the salt layers were selected.
6.2. Effect of injection rate
In this section, the influence of the gas injection rate on the CO2 injection-withdrawal cycle is characterized based on the analysis of the VLR, displacement, and SF.
6.2.1. VLR of SCCS
Fig. 13 shows the curves of the VLR versus the operating time for different CO2 gas injection rates. In the CO2 injection-withdrawal cycle, the VLR exhibits a fluctuating increasing trend. This is because in the injection-withdrawal cycle, the internal pressure of the cavern changes with the injection-withdrawal of CO2, and the creep of the surrounding rock of the cavern accelerates at lower pressures [89]. At a higher pressure, part of the surrounding rock is re-compacted, which causes the volume of the cavern to expand again. However, in general, the volume of the cavern will decrease continuously during each injection-withdrawal cycle, and the VLR will also increase as the number of injection-production cycles increases.
After 50 injection-withdrawal cycles within 50 years, the final VLRs of the cavern under different gas injection rates of 1000, 1500, 2000, 2500, and 3000 tons·d−1 were calculated to be 12.85%, 10.69%, 9.42%, 8.54%, and 7.88%, respectively. By increasing the CO2 injection rate, the VLR of the cavern can be effectively reduced, from 12.85% to 7.88% over 50 years, with a reduction of 38.68%. After 50 injection-withdrawal cycles, the maximum VLR is far less than 30%, which meets the VLR requirement for salt caverns [96]. Due to the continuous injection of CO2, the salt cavern is subjected to lower fluctuations of internal pressure in the cavern, which makes its pressure higher during most of its operating time, thus greatly reducing its VLR. Compared to gas storage in salt caverns [99], SCCS has no stage for low-pressure operation, so the VLR of SCCS shows a much slower increasing trend and a much longer service life.
6.2.2. Displacement of wall rock
The second index is the displacement of the wall rock. Fig. 14 presents the displacement curves at different points along the cavern wall for the simulated CO2 injection rates.
In Fig. 14(a), the working conditions are as follows: the gas injection rate of 1000 tons·d−1, the minimum internal pressure of 0.3σv0, and five points (points 1-5 in Fig. 9) in the surrounding rock of the cavern were selected as the research objects. Point 1 is located at the top of the cavern, and its Z-axis displacement is monitored, while point 2 is located at the bottom of the cavern. Points 3-5 are all points of the surrounding rock of the cavern, and their X-axis displacements are also monitored. It can be clearly seen that with increasing time, the displacements of all of the selected target points also increase and the maximum displacement occurs at point 5 in the middle of the surrounding rock of the cavern, followed by the displacement of point 4 in the middle and lower part of the cavern, and the displacement of point 3 in the middle and upper part of the cavern is the smallest. Comparing the displacements at points 1 and 2, we find that the displacement of point 2 located at the bottom of the cavern is obviously larger than that of point 1 located at the top. Overall, the displacement in the middle and lower part of the cavern is larger, while the displacement in the middle and upper part is smaller. However, in previous studies [89], [91], the displacement in the middle and upper part of the cavern is larger, while the displacement in the middle and lower part is smaller. According to our analysis, the reasons for the small displacement in the middle and lower parts of the cavern are due to insoluble located in bedded rock salt accumulating at the bottom of the cavern, which provides a partial supporting force for the middle and lower parts of the cavern, while hindering the contraction of the middle and lower parts of the cavern towards the sediment [89]. However, to explain the large displacement of the middle and lower parts in this study, we posit that it is because the shape of the cavern is slender (the height of the cavern is 200 m), and the difference between the original rock stress at the top and bottom of the cavern may reach about 4.6 MPa. The difference between the original rock stress at the bottom of the cavern and the operating pressure of the cavern is larger, which makes the displacement at the bottom of the cavern correspondingly larger. In this study, the maximum displacement of the cavern occurs in the middle and lower salt layers of the cavern, which is caused by the joint influence of the above two factors.
Fig. 14 (b) shows the displacement curves at point 5 (maximum displacement point) with an operating time under different CO2 injection rates. The minimum internal pressure is 0.3σv0. Similar to the VLR, the displacement increases with increasing operating time, and it finally reaches the final peak after 50 years. The final displacement value of the cavern is calculated to be 1.516, 1.246, 1.087, 0.980, and 0.901 m for injection rates of 1000, 1500, 2000, 2500, and 3000 tons·d−1. By increasing the injection rate from 1000 to 3000 tons·d−1, the displacement can be effectively reduced by 40.57%. Considering that 10% of the cavern’s radius is 2.5 m, the displacement values of each point in the cavern meet the displacement requirements [96].
6.2.3. SFVR distribution
Fig. 15 illustrates the SFVR distribution under different injection rates. Considering that the minimum SF values for all of the working conditions are all greater than 1.5 [94], the SCCS can meet the SF index requirement after 50 years of operation. It should be noted that the SFVR calculated in this paper is the numerical value in each zone in the FLAC3D model, while the SF values obtained in previous research [94], [95], [96] are the numerical values obtained after volumetric averaging processing. Without volumetric averaging, the SF value is much smaller. In this paper, the difference under the different injection rates is determined via analysis of the SFVR. Fig. 15(a) shows the relationship between the SFVR and SF considering the interlayers. SF < 0.6 is negligible under different injection rates, and the SFVR increases with increasing SF. Based on the comparison of Figs. 15(a) and (b), the interlayers and sediments occupy most of the SFVR in the low SF zone. The lower the SF, the higher the percentage of interlayers and sediment. Therefore, eliminating the interlayers and sediment group in the numerical simulation model for the SF and SFVR calculations is an essential step. The difference of SF < 0.6 and 0.6-1.0 between various injection rates is negligible, and when SF = 1.0-1.5, SFVR for low injection rates is much higher than for high injection rates (Fig. 15(b)). For example, SFVR is 0.2 when the injection rate = 1000 tons·d−1 and is 0.1 when the injection rate = 3000 tons·d−1. Generally, the influence of injection rate on SFVR is little and is limited.
Overall, by VLR, displacement, SF, and SFVR analysis, we see that high injection rates will improve the stability of SCCS. However, the effect of injection rate on the injection-withdrawal cycles of SCCS is little and limited. Generally speaking, through the analysis of VLR, displacement, and SFVR, higher injection rates can improve the stability of SCCS, but injection rate has only a small effect on SFVR, while it has a great influence on VLR and wall rock displacement. Although increasing the injection rate can effectively reduce VLR, displacement, and so forth, and improve the safety of the cavern, the overall injection rate of the salt cavern group is constant. If the injection rate of a single salt cavern is increased, the injection rate of other salt cavern will be correspondingly reduced. Therefore, it is very important to choose an appropriate injection rate in the salt cavern, a topic which deserves further analysis and discussion.
6.3. Effect of minimum operating pressure
As in the previous section, in this section, we characterize the influence of the minimum operating pressure on the SCCS injection-withdrawal cycles through analysis of the VLR, displacement, and SF. Then, we compare the influences of the minimum operating pressure and injection rate on the SCCS injection-withdrawal cycle.
6.3.1. VLR of SCCS
Fig. 16(a) shows the curves of the VLR versus the operating time for different minimum operating pressure ratios. The minimum operating pressure ratio is the ratio of the minimum operating pressure to the original rock stress at the casing shoe. For SCES, the proper operating pressure is 0.30-0.85 times the original rock stress at the casing shoe; therefore, in this paper, the minimum operating pressure ratio is set to 0.3-0.5. The gas injection rate is set to 1000 tons·d−1. After 50 injection-withdrawal cycles in 50 years, the final VLR values of the cavern under minimum operating pressures of 0.30, 0.35, 0.40, 0.45, and 0.50 are 12.85%, 11.14%, 9.24%, 7.58%, and 6.12%, respectively. By increasing the injection rate, the VLR of the cavern can be effectively reduced: from 12.85% to 6.12% after 50 years, a reduction of 52.37%. Fig. 16(b) shows the curve of the VLR versus the minimum operating pressure ratio for SCCS under different injection rates. It can be seen that as the minimum operating pressure increases, the VLR decreases continuously, and it also decreases with the increasing injection rate. Comparing the basic working conditions of 1000 tons·d−1 and 0.3σv0, we see that increasing the minimum operating pressure to 0.5σv0 decreases by 52.37% whereas increasing the injection rate to 3000 tons·d−1 decreases it by 38.68%.
6.3.2. Displacement of the wall rock
Fig. 17 shows the curves of the displacement at point 5 (the maximum displacement point) versus the operating time, and versus the minimum operating pressure ratio. Fig. 17(a) shows the curve of the displacement versus the operating time for different minimum operating pressure ratios and a CO2 injection rate of 1000 tons·d−1. The final displacement values of the cavern are 1.516, 1.341, 1.132, 0.940, and 0.770 m, for minimum operating pressure ratios of 0.30, 0.35, 0.40, 0.45, and 0.50, respectively. By increasing the injection rate from 0.3P0 to 0.5P0, the maximum displacement of the cavern can be effectively reduced by 49.21%, which is close to the value of 52.37% for the VLR. Similarly, the displacement value of each cavern satisfies the requirements that the displacement not exceed 10% of the cavern’s radius [96]. Fig. 17(b) shows the influence of the minimum operating pressure and injection rate on the displacement at point 5 after 50 years of operation. Similarly, with increasing injection rate, the displacement decreases continuously. By comparison with the basic working conditions of 1000 tons·d−1 and 0.3P0, we find that the decrease of 49.21%, by increasing the minimum operating pressure to 0.5P0, is higher than the one of 40.57% by increasing the injection rate to 3000 tons·d−1.
6.3.3. SFVR distribution
Fig. 18 shows the distribution of the SFVR for different minimum operating pressure ratios. For these cases, when SF < 5, the SFVR increases with increasing SF, indicating that the high SF value has a wider range. However, under different minimum operating pressure ratios, the SFVR changes greatly. As the minimum operating pressure ratio increases, the SFVR with an SF value < 5 decreases, which indicates that the minimum operating pressure ratio can effectively reduce the range of the surrounding rock with low SF values, thus increasing the stability of the cavern, which is beneficial to the long-term safe operations in salt caverns. Compared with Fig. 15, we find that different minimum operating pressures have a great influence on the distribution of SFVR, greatly reducing its rock salt volume when SF < 5, and greatly improving its safety—while the injection rate has little influence on SFVR.
The influence of operating pressure is much higher than for injection rate. Although increasing the minimum operating pressure can effectively reduce VLR, displacement, and so forth, while increasing the safety of the cavern, increasing the minimum operating pressure will reduce the single-cycle CO2 injection-withdrawal volume, thus reducing its usability. Therefore, the selection of the appropriate minimum operating pressure deserves further analysis and discussion by combining the usability.
7. Discussion and future prospects
7.1. Accumulated working mass (AWM) of a single cavern
This section discusses the influence of injection rate and operating pressure on SCCS in combination with availability analysis. Lifespan is used as the intuitive index, showing how long the salt cavern can be used for CO2 storage [33]. It is defined by the operating time until the salt cavern fails to meet any of the three indexes mentioned above in Section 6. The AWM of CO2 is used to analyze the usability of SCCS during its lifespan. Generally speaking, the higher the operating pressure of the salt cavern, the smaller the VLR. But correspondingly, the lower working gas volume stored in the salt cavern affects the working gas volume over a single injection-withdrawal cycle. We observe that the AWM is related to the initial volume of the cavern, the VLR of the cavern after running for t years, the density difference between high pressure and low pressure, the service life, among other factors. Therefore, AWM can be calculated as follows:
The lifespan of SCCS is strongly correlated to the injection rate (shown in Fig. 19). By increasing the injection rate to 3000 tons·d−1 (from 1000 tons·d−1), its lifespan can be increased from 178 to 341 years (1.92 times), which indicates that a high injection rate is also advanced in this aspect. As for the value of AWM of the salt cavern, changing the injection rate will only affect its service life and VLR, but will not change the density difference. Therefore, increasing the injection rate can effectively increase its AWM, but it has little effect on the annual working gas mass.
To analyze the effect of minimum operating pressure, density difference (the difference between density at maximum and minimum operating pressures—indicating the working mass of single injecting-withdrawal cycle), and lifespan is calculated under different minimum operating pressure (shown in Fig. 20). By increasing the minimum operating pressure to 0.5σv0 (from 0.3σv0), the lifespan of SCCS can be increased from 178 to 557 years (3.13 times), which is significant compared to the 1.92 times. However, the density difference decreased from 544.50 kg·m−3 (0.3σv0) to 183.25 kg·m−3 (0.5σv0), which decreased by 66.34%, indicating that increasing the minimum operating pressure greatly reduced the working gas volume of a single injection-withdrawal cycle, thus influencing the AWM value for a certain period.
To analyze the effect of AWM on the whole lifespan of SCCS under various minimum operating pressures, we select 30% VLR as the terminating criterion, with the corresponding result shown in Fig. 21(a). Under various minimum operating pressure ratios, the AWM values are: 2.35 × 107, 2.38 × 107, 2.33 × 107, 2.32 × 107, and 2.46 × 107 tons, respectively. We clearly see that the AWM value is quite large, and the difference between each case is very small. This is because the final cavern shrinkage is certain, the working mass and the volume shrinkage is almost positively correlated. In a specific cycle, when the minimum operating pressure decreases, the working mass increases while cavern shrinkage also increases. This leads to the little difference of AWM under various minimum operating pressure ratios. Moreover, this also shows that the injection-production mode of SCCS is quite flexible.
It is worth mentioning that these are only the AWM values for a single salt cavern with a volume of 296 814 m3. Therefore, if many salt caverns work together, they have great potential for CO2 storage due to the continuous injection-withdrawal of CO2.
Under the minimum operating pressure of 0.3σv0, the increasing rate (Fig. 21(b)) is much higher than others, and after 50/100 cycles, the AWM values have reached 0.75/1.53 × 107 tons, respectively, which is quite considerable. Moreover, the average annual CO2 storage mass is up to 153 000 tons for a single salt cavern with a volume of 296 814 m3, which is much higher than the scale of CCUS demonstration projects in China [33]—demonstrating what a single salt cavern can do using SCCS. For dozens of salt caverns in one salt mine [45], [98], [102], the total annual CO2 storage mass can reach millions to tens of millions of tons. In addition, from the above stability analysis, we find that SCCS can operate safely for very long time. Therefore, SCCS can meet the carbon storage and carbon supply functions for different time demands.
7.2. Site selection of SCCS in China
7.2.1. Requirements for SCCS site selection
Based on the above research, the following suggested site selection requirements of SCCS in China can be obtained.
(1) Suitably storable depth range. The range of storage depth, from the point of view of SC-CO2 density, is between 800-2000 m, and the density of CO2 is between 750-870 kg·m−3, and then increasing the depth does not significantly increase the density, and the cost of drilling and cavern building increases greatly. From the perspective of injection-production density difference, the greater the depth, the smaller the density difference of CO2 under the same pressure difference, and the density difference of injection-production disappears when it exceeds 2000 m. Considering the tightness, energy storage scale, peak-shaving ability, and economy, 800-2000 m is preferred as the depth range of reservoir site selection.
(2) Determination of optional area and old cavern. The permeability of CO2 in rock mass under high pressure is not as good as CH4, H2, He, and air. As long as CO2 is injected into the salt cavern in a SC state with high viscosity, its requirements for the tightness of surrounding rock are lower than those of other gases, which can further expand the scope of site and cavern selections.
(3) Requirements of storable scale. Considering that the current economy of carbon storage in salt caverns has not been fully reflected, it is suggested that the old cavern of salt caverns should still be closed, and it is suggested that the net space should not be less than 200 000 m3 (more than 150 000 tons of carbon storage), so as to measure its economy.
(4) Safety operation requirements. The operating pressure of SCCS is high, and the pressure fluctuation is smaller, which is suitable for long-term storage. In the traditional places where gas storage or compressed air storage is built, it can theoretically meet the requirements of SCCS.
(5) Relationship with carbon upstream and downstream. It is suggested that the location should not be too far away from upstream carbon emission and downstream carbon utilization/storage, and it is suggested that it is about 100 km, so as to ensure the economy of SCCS and control the cost. It is suggested to further develop the combination of SCCS and SCES combined with CCUS pipeline, such as compressed CO2 energy storage in SCCS.
7.2.2. Preliminarily selected SCCS sites
Moreover, basic information of some salt mines and provincial carbon emission of China is given in Table 3 [8], [45], [84], [103]. Table 3 lists CO2 emissions and salt mines in some representative provinces in China. The total carbon emission of these six provinces is 3550.96 Mt CO2, accounting for 32.64% of the national carbon emissions in 2019. These high-carbon emission provinces are mainly located in the eastern and coastal areas of China, and these areas are also rich in salt mines. Based on the suggested site selection requirements above of SCCS in China and Table 3, several potential salt mines are preliminarily obtained, as follows.
(1) In Jiangsu Province, Huai’an, Chuzhou, Jintan, Zhaoji, and Fengxian salt mines are potential SCCS sites, and Jiangsu Province is a big carbon emission province in China. Therefore, SCCS can play a major part in the goal of achieving peak carbon emission and carbon neutrality.
(2) Furthermore, Henan Province, Shandong Province, and Hubei Province all have suitable salt mines for SCCS and worthy of further investigation.
(3) Dingyuan salt mine in Anhui Province, Longgui salt mine in Guangdong Province, and Yunying salt mine in Hubei Province cannot be potential SCCS sites due to their shallow burial depth.
7.3. Evaluation of storage scale by SCCS
Herein we have researched the working principle, potential application, CO2 injection, and cavern stability of SCCS. However, it is still necessary to analyze the potential scale of SCCS from the perspective of CCUS and the demand of the carbon market at a national level. In this way, it can provide guidance for the future large-scale construction of salt caverns to store carbon.
The “China annual report on carbon capture, utilization and storage China (2023)” [104], predicts that CCUS demand in China will be about 24 million tons per year in 2025, nearly 100 million tons per year in 2030, about one billion tons per year in 2040, over two billion tons per year in 2050, and about 2.35 billion tons per year in 2060. At present, there are about 40 CCUS projects under construction and operation in China, mainly small-scale demonstration projects of the power, oil, and coal industries, with an annual total CO2 capture capacity of three million tons per year [105], which is far from the future demand for emission reductions. The carbon sequestration goal is very ambitious; however, the current progress is relatively slow. Apart from the need for technological progress, the CCUS projects are difficult to make profits. And this makes CCUS mostly stay in the demonstration stage [105]. Enterprises are the real executors of carbon emissions reductions, but it is difficult for enterprises whose survival is based on profit to shift their priorities such that the driving force is high carbon sequestration investment. Therefore, with the implementation a carbon tax policy in China in the future, although enterprises will have to sequester carbon, the traditional CCUS model will still make enterprises face enormous economic pressure.
7.3.1. Unique advantages
SCCS has some unique advantages, which can further incentivize carbon storage in enterprises.
(1) Regional advantages. As shown in Table 3, the eastern and coastal areas of China are the high-carbon emission provinces and rich in salt mines. These areas have many salt mines and idle salt caverns. These areas are economically prosperous with a well-developed industry, and there is also a great demand for the utilization of carbon. Therefore, it provides the necessary conditions for site selection and caverns for carbon storage. In particular, for provinces such as Hebei, Henan, Sha’anxi, Shandong, Jiangsu, Guangdong, Sichuan, Yunnan, and other provinces, in addition to salt mines, there are abundant wind, solar, or hydro-power resources. Combined with large-scale SCCS, and integrated industry can be established that includes renewable energy, hydrogen energy, and CO2 utilization, having the industrial conditions and consumption market for renewable energy peak shaving and hydrogen energy conversion to other forms of energy.
(2) Making the carbon neutrality chain more flexible. Carbon emissions cannot be sealed or used immediately. SCCS is characterized by large-scale, safety, economy, and flexibility. Based on the temporary storage and spatial use characteristics of SCCS, the market compatibility and flexibility of the carbon-neutral industrial chain can be greatly enhanced.
(3) Decreasing cost for carbon injection. At present, the cost of gas injection-brine extraction in salt caverns is about 20 CNY·m−3, and the cost of carbon injection in most other CCUS is about 50-60 CNY·ton−1 (corresponding to about 1.5 m3 of brine, the discharged brine can offset some costs). This is because the salt cavern is a huge cavity, and the depth of most salt cavern gas storage in China is between 500-2000 m. The gas in the salt cavern is directly injected into the solution cavity from the ground through the gas injection well, and the brine is discharged through the brine drainage well. The friction in this process is actually not large, and the process of brine drainage is relatively easy, and the corresponding energy consumption is relatively low. Moreover, the discharged brine can also be sold, which has a certain compensation effect on the cost. While the other CCUSs are porous media formations (such as oil layers and aquifers) where high-pressure CO2 is slow injected into the pores of the reservoir. So the pipeline friction and seepage friction are much greater than that of CO2 injection in salt caverns. The greater the friction, the longer the gas injection, the higher the energy consumption and the corresponding cost. And the process of CO2 injection will be very slow. There is basically no additional cavern-construction cost when using idle salt caverns. Therefore, considering that SCCS is comparable to other CCUS in terms of ground operation and pipeline construction costs, the injection cost of SCCS will still be much lower.
(4) Significantly increasing the amount of available carbon. A single recoverable carbon amount is as high as 300 000 tons [33], and multiple injection-production cycles can be carried out in one year. The total amount of carbon used (which can be regarded as a carbon neutral amount) will be significant. Therefore, it is entirely possible for a group of salt caverns to store (and later, supply) millions of tons of carbon.
7.3.2. Storage scale of SCCS
Combined with the three scenarios of SCCS mentioned above, we will now discuss the carbon storage capacity and potential benefits of SCCS at the national level. By the end of 2016 [90], the total volume of idle salt caverns in China had reached 250 million cubic meters. In recent years, China has an annual output of 40 million tons of salt. Hence, by the end of 2023, it is estimated that China will have more than 370 million cubic meters of idle salt caverns in total. Most of the salt caverns are more than 800 m deep, basically meeting the storage conditions of SC-CO2. In the same way, the storage scale of SCCS can be calculated as:
where mtotal is the total carbon storage capacity, ton; η is the usage ratio of salt cavern’s volume for carbon storage, %; Vcavern is the volume of idle salt caverns in total, m3; and ρSC-CO2 is the density of SC-CO2, kg·m−3.
As a preliminary estimate, it is completely feasible to use 20%-30% of the cavern’s volume for carbon storage, with the total carbon storage expected to exceed 51.8-77.7 million tons (density of SC-CO2 is set as 700 kg·m−3), which is about 17.30-25.95 times the national annual carbon storage (2022 data) [104].
(1) Combined with scenario 1. The current national carbon storage is small, and there has been no major technological breakthrough. However, the adoption of SCCS can increase the carbon storage of more than 51.8 million tons. This is of practical significance for increasing the scale of carbon storage in the country in just a short period of time. The location and operation of carbon storage in salt caverns are similar to those of gas storage, and the complete technical system of salt cavern gas storage can effectively ensure the implementation of SCCS. This model mainly serves to achieve short-term carbon emission reduction targets (for example, in 2030), and there is no other economy except the one of carbon emissions reductions. In this scenario, a total of 51.8 million tons of carbon storage can provide an important supplementary way for CCUS in 2030.
(2) Combined with scenario 2. This mode is mainly adopted because the technology is immature and cost of carbon utilization presently is high. In salt caverns, carbon is stored on a large scale and used on a small scale. But even if 80% of carbon is not used passively, more than 40 million tons of carbon will be stored for an extended time. This model can meet the needs of carbon emission reductions in just the next 10-20 years, in addition we can consider that carbon utilization can produce certain economy of its own. Moreover, carbon dioxide energy storage (CES) technology, including thermo-electrical (TE)-CES, transcritical (TC)-CES, SC-CES systems, and liquid CES (LCES), is a new type of clean physical energy storage technology with long-term, stable, and efficient energy storage, and has the characteristic of high energy storage density and high cycle efficiency [106], [107], [108]. Due to the high pressure on the high-pressure side of the CES system (generally 10-25 MPa), strict requirements are put forward for the high-pressure side storage vessels. Ordinary steel pressure vessels often cannot meet the safety requirements, and in order to meet the stable energy release conditions of the system, a considerable amount of surplus volume is needed when designing the pressure vessels, which leads to a large material cost and affects the overall economic benefits of the CES system. Therefore, some scholars put forward that combined with CO2 storage technology, underground storage (hard rock caves, salt caverns, abandoned coal mines, saline aquifers, underwater, etc.) should be used to store high- and low-pressure CO2. Compared with other ways, salt caverns are highly coincident with the high CO2 emission region in China. Therefore, CES system based on salt caverns will be a hot topic in the upcoming years.
(3) Combined with scenario 3. Carbon stored in salt caverns is injected and extracted frequently. We may expect that, after 2040, the technology, cost, scale, and other related issues of carbon utilization will be well-solved. At that time, large-scale utilization of carbon will be the main mode of the carbon market. SCCS plays an important role in that carbon market—although the scale might be small, SCCS can play an important role in regulating the carbon market due to the frequent injection and extraction of carbon. At present, it is exceedingly complex to predict the future carbon regulation capacity of SCCS. However, similar to gas storage capacity of 10% in the natural gas market, it could act to meet the demand of peak shaving in the natural gas market. Therefore, we can expect that the 51.8 million tons of SCCS should play the role of regulator on a much larger carbon utilization scale in the market. This is also the main mode of SCCS in the future, which mainly will play the role of regulator or lever in the future carbon market. In this scenario, the biggest advantage of SCCS can be reflected. For CES, a single cavern with volume of 500 000 m3 can store over 10 GW·h energy (for SC-CES, energy storage density over 20 kW·h·m−3) [109]. For CCUS, injection-production cycle will greatly increase carbon storage. The working gas mass of single salt cavern can exceed 300 000 tons [33] for each injection-production cycle, that is, 10 million tons of carbon storage can be realized by 33 salt caverns. Moreover, when the number of injection-production cycles is ten times per year, the annual carbon storage scale can reach 100 million tons. The annual cumulative turnover of the carbon market reached 194 million tons in China (from July 16, 2021 to July 15, 2022) [110]. The transaction price has increased slightly in the past year. The opening price a year ago was 48 CNY·ton−1, and the current price is around 60 CNY·ton−1. In this case, SCCS can provide more than half of the carbon market storage, and a bigger carbon market can be promoted and implemented.
8. Conclusions and prospects
(1) According to the needs and development of the carbon market, SCCS can achieve carbon reduction and utilization through long-term large-scale storage by utilizing a small amount of carbon extraction and high-frequency carbon injection-withdrawal. Similar to other CCUS projects at present, SCCS can also provide large-scale carbon storage. In particular, SCCS plays the role of temporary and semi-permanent carbon storage, which strengthens the conversion of CO2 from waste to an industrial resource, thus yielding economic benefits for each participant.
(2) Scenario 1 is the carbon sequestration method, and scenarios 2 and 3 are CCUS methods. Scenario 2 is temporal due to immature CO2 utilization technology, while scenario 3 is carbon storage with frequent CO2 injection and withdrawal.
(3) The dynamic viscosity of H2 is the smallest, only half those of CH4, air, and He, and the dynamic viscosity of CO2 is highest, almost three times those of CH4, air, and He. Therefore, the tightness requirements of salt cavern hydrogen storage are highest, and the tightness requirements of SCCS is lowest.
(4) In the CO2 injection and brine extraction stage, CO2 is injected in the gaseous state and is stored in the SC state; and the change in the CO2 pressure at the wellhead, friction along the injection and withdrawal channels, and relationship between the CO2 pressures at the wellhead and CO2-brine interface are determined. The CO2 injection rate is the most important factor affecting the head loss along the pathway.
(5) Through analysis of the VLR, wall rock displacement, and SFVR, we determined that during long-term operational periods, higher injection rates can improve the stability of SCCS, but the injection rate has a small effect on the SFVR, while it has large influences on the VLR and displacement. Increasing the minimum operating pressure can effectively reduce the VLR and displacement, and increase the safety of the salt cavern. SCCS has a better stability than salt cavern gas storage, suggesting that it also has a longer service life.
(6) The suitable range of storable depth is between 800-2000 m, and the density of CO2 is between 750-870 kg·m−3. For economic demand, it is suggested that the net space of salt cavern should not be less than 200 000 m3, and the distance from upstream carbon emission and downstream carbon utilization/storage is within 100 km.
(7) In China, Jiangsu Province, Henan Province, Shandong Province, and Hubei Province all have suitable salt mine for SCCS and worthy of further investigation. and Jiangsu Province is a big carbon emission province in China. Therefore, SCCS can play a major part in the goal of achieving peak carbon emission and achieving carbon neutrality.
(8) In China, salt mines coincided well with many major carbon-emitting and renewable provinces. A single cavern can serve over 100 years and store more than millions of tons of carbon during its lifespan. In the national region, if 20%-30% of the idle cavern space is utilized, the SCCS can provide over 51.8-77.7 million tons of carbon storage, which is favorable for both temporary and long-term carbon storage. By continuous carbon injection and extraction, SCCS can play as an important regulator to serve the carbon market in the future.
Acknowledgments
This work was supported by the National Natural Science Foundation of China (52074046, 52122403, 51834003, and 52274073), the Graduate Research and Innovation Foundation of Chongqing (CYB22023), the Chongqing Talents Plan for Young Talents (cstc2022ycjh-bgzxm0035), Hunan Institute of Engineering (21RC025 and XJ2005), and Hunan Province Education Department (21B0664).
Compliance with ethics guidelines
Wei Liu, Xiong Zhang, Jifang Wan, Chunhe Yang, Liangliang Jiang, Zhangxin Chen, Maria Jose Jurado, Xilin Shi, Deyi Jiang, Wendong Ji, and Qihang Li declare that they have no conflicts of interest or financial conflicts to disclose.
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