Assessment of the CO₂ Geological Storage Potential of Yanchang Shale Gas Formation (Chang7 Member) Considering the Capillary Sealing Capability of Caprock

Abstract

Reducing net carbon emissions is of great significance for sustainability. Carbon capture, utilization, and storage (CCUS) technology is regarded as one of the most effective approaches to reducing net carbon emissions. A prerequisite for the implementation of the CO₂ geological storage project is the assessment of the storage potential of the storage site. In this study, a calculation method of storage potential was proposed to estimate the CO₂ storage potential of the Yanchang shale gas reservoir in the Ordos Basin, China. In this method, the CO₂ sealing capability of the caprock is taken into account, which determines the maximum CO₂ storage pressure of the reservoir. The overall CO₂ storage potential consists of four types of storage states (free-state, adsorption, dissolution, and mineralization). The maximum CO₂ storage pressure of the Yanchang shale gas reservoir is 13.4 MPa via breakthrough pressure experiments, and the corresponding theoretical storage potential is 7.59 × 10¹¹ t. The potential for free-state, adsorption, dissolution, and mineralization sequestration are 8.42 × 10¹⁰ t, 6.88 × 10¹⁰ t, 2.45 × 10⁹ t, and 6.05 × 10¹¹ t, respectively. Due to the difficulty in completing mineralization within the engineering time scale, the mineralization potential should not be taken into account when estimating the available CO₂ storage potential. The available CO₂ potential (including free-state, adsorption, and dissolution) of the Yanchang shale gas reservoir is 1.54 × 10¹¹ t, which is a considerable amount. The Yanchang shale gas formation will be able to accommodate 41.49% of global annual CO₂ emissions (according to the data in 2021) if the available CO₂ storage potential of the Yanchang shale gas reservoir is fully exploited.

1. Introduction

The global warming effect caused by exceeded carbon emissions has attracted worldwide attention. Reducing net carbon emissions is of great significance for sustainability. Carbon capture, utilization, and storage (CCUS) technology is considered to be one of the most effective approaches to reduce net carbon emissions [1,2,3,4]. The International Energy Agency (IEA) estimated that CCUS technology will undertake 19% of the global carbon emission reduction task and become the single technology with the largest share of carbon emission reduction by 2050 [5].

The available formations for CO₂ geological storage include deep saline aquifers, developed oil and gas reservoirs, and non-minable coal seams [5,6,7,8,9,10,11]. However, some recent studies show that shale gas reservoirs are also candidates for CO₂ geological storage due to the following reasons: (1) Widely distributed shale gas reservoirs can provide huge storage space. (2) Millions of years of shale gas preservation history can confirm the validity of the trap. (3) The geological data and wellbore retained during the shale gas development process can be reused to lower the costs. (4) The injection of CO₂ can improve the recovery of CH₄, which brings additional economic benefit [12,13,14,15,16,17,18,19,20]. In an earlier field experiment, CO₂ was injected into the Yanchang shale gas formation with the aim of increasing production. The gas composition monitoring results showed that the concentration of CO₂ in the reverse exhaust gas was equivalent to the original CO₂ concentration of the gas reservoir, which indicated that CO₂ could be effectively sequestrated in the Yanchang shale gas reservoir [21,22]. Shale formations, especially depleted shale units previously used for gas extraction, have good economics and reliability when used for CO₂ geological storage.

A prerequisite for the implementation of geological storage of CO₂ is the assessment of the storage potential of the storage site. Several methods have been proposed to estimate the CO₂ storage potential in different types of formations. The Carbon Sequestration Leaders Forum (CSLF) and the United States Department of Energy (DOE) proposed estimating methods of CO₂ storage potential for deep saline aquifers and non-minable coal seams, respectively [8,23]. Shen et al. proposed an estimation method for oil reservoirs [8,24]. Recently, the CO₂ storage potential of shale formations has also been a concern [25,26]. Godec et al. estimated that the CO₂ storage potential of Marcellus shale formation could reach 55 Gt [27]. Nuttall et al. estimated that 28 Gt CO₂ could be sequestered in the Devonian shales underlying Kentucky [28]. CO₂ will be sequestrated in shale gas reservoirs in four states, i.e., free-state, adsorption, dissolution, and mineralization. The aforementioned methods for estimating CO₂ sequestration potential do not fully consider the contribution of each sequestration state. Furthermore, these methods do not consider the sealing capacity of the caprock, which may result in an overestimation of the potential beyond safe sequestration limits.

The contribution of each storage state to the overall CO₂ storage potential (OCSP) is affected by temperature, pressure, petrology, mineralogy, and hydrogeological conditions. A large amount of CO₂ injection will lead to increased pressure in shale reservoirs, and leakage will occur when the reservoir pressure exceeds the sealing capability of the overlying caprock. Thus, the assessment of CO₂ sequestration potential must take into account the sealing capability of caprock. A caprock is usually with low permeability, low porosity, and high brine saturation [29]. Caprock’s key sealing mechanism has been identified as capillary sealing, which takes place at the CO₂–brine interface and prevents CO₂ from migrating upward [30,31]. Capillary sealing efficiency is controlled by the gas-liquid interfacial tension (IFT), the water wettability of the caprock mineral, and the pore size distribution within the caprock. Breakthrough pressure (BP) is the parameter that best reflects the capillary sealing efficiency of caprocks, which is defined as the minimum gas pressure required to overcome the capillary pressure in the largest pore channels [32,33,34,35]. From an experimental perspective, BP refers to the pressure difference between the inlet and outlet when the gas flow is formed in a brine-saturated sample [36,37,38]. The BP of caprock determines the upper limit of CO₂ storage pressure, which in turn controls the storage potential. It is necessary to determine the maximum storage pressure before evaluating the CO₂ storage potential of the shale gas reservoir. Due to the differences between CO₂–brine IFT and CH₄-brine IFT, there may be significant differences in the sealing efficiency of the same caprock for CO₂ and CH₄ [39,40]. Therefore, the idea that the maximum CO₂ storage pressure in depleted shale gas reservoirs can reach the original pressure of gas reservoirs may lead to wrong estimates. The maximum storage pressure should be determined by the experimental method.

The upper Triassic Yanchang formation (Chang7 member) is a typical continental shale gas reservoir located in the Ordos Basin, China. The reasons for choosing the Yanchang Shale Formation in this study include the following: (1) The Yanchang Shale Formation is widely distributed, which can provide a huge storage capacity for CO₂; (2) There are many concentrated sources of CO₂ emissions (chemical factory, power plants) within the Ordos Basin, providing a good match for CO₂ source and sink when choosing Yanchang Shale Formation as a storage site; (3) Preliminary field-scale CO₂ injection experiments have already been conducted in the Yanchang Shale Formation, proving the feasibility of CO₂ sequestration in this stratum. These favorable conditions make the Yanchang Shale Formation a possibility of becoming the target formation for large-scale CO₂ geological storage.

In this study, a calculation method for CO₂ storage potential considering the sealing capability of caprock was proposed. A series of experiments, including breakthrough pressure tests, nuclear magnetic resonance (NMR), CO₂ isothermal adsorption, and X-ray diffraction, were conducted to determine the sealing capability, pore structure, adsorption capability, and mineralogy of Yanchang shale. The CO₂ storage potential of Yanchang shale formation was estimated according to the results. The innovation of this study lies in proposing a model for estimating CO₂ storage potential that takes into account the capillary sealing capacity of the caprock and the different storage states of CO₂ in shale and, for the first time, estimating the available sequestration potential of the Yanchang Shale Formation. The results of this study provide a theoretical basis for the feasibility assessment of large-scale CO₂ geological sequestration in the Yanchang Shale Formation, which has positive implications for global sustainability.

2. Geological Settings

The Ordos Basin is located at the tectonic joint of the eastern and western domains in China, which can be divided into six secondary tectonic units (termed as Western Margin Thrust Belt, Tianhuan Depression, Yishaan Slope, Jinxi Flexural Fold, Yimeng Uplift, and Weibei Uplift) according to the present structural morphology and evolution history of the basin (Figure 1a) [41]. The Yanchang Formation was formed during the Late Triassic and can be divided into 10 sections from top to bottom [42,43]. The Chang7 member is the main shale gas-bearing formation, whose thickness distribution is shown in Figure 1b [44]. The burial depth of the Chang 7 reservoir is between 1200 m and 1800 m, with an average reservoir temperature of 50 °C. The Chang7 member can be further divided into three sub-members: Chang7¹, Chang7², and Chang7³. The Chang7¹ and Chang7², located in the middle and lower sections, are gas-bearing formations. The electric logging results show that the resistivity of the Chang7¹ section is much lower than that of the Chang7² section and Chang7³ section, indicating that it is highly water-saturated and can be regarded as the direct caprock of Chang7 shale gas formation (Figure 1c) [45].

3. Methodology

3.1. Storage Potential Evaluation

The conceptual model shown in Figure 2 illustrates the sealing and storage mechanism of CO₂ in Yanchang shale gas formation. The highly water-saturated layer located at the upper section of the Chang 7 member forms a capillary sealing mechanism that prevents the upward migration of CO₂. The original gas-bearing layer provides storage space for CO₂. CO₂ will be stored in the states of free-state, adsorption, dissolution, and mineralization. The upper limit of capillary sealing capability can be expressed as follows [36,46]:

$$P_{\mathrm{C}{\mathrm{O}}_2}=P_c+P_{brine}$$

(1)

where $P_{\mathrm{c}{\mathrm{o}}_2}$ is the maximum storage pressure, MPa; $P_c$ is the breakthrough pressure of caprock; and $P_{brine}$ is the overlying hydrostatic pressure, MPa.

The middle and lower sections of the Chang7 member provide CO₂ storage space, where CO₂ is stored in free, adsorbed, dissolved, and mineralized states. The total storage potential is equal to the sum of the four states of CO₂. The storage potential of free CO₂ can be calculated as

$$C_f=\frac{P_{\mathrm{C}{\mathrm{O}}_2}\phi M_{\mathrm{C}{\mathrm{O}}_2}\left(1-S_w-V_a\right)}{ZRT}$$

(2)

where $C_f$ is the storage potential of free CO₂ in unit volume shale, kg/m³; $\phi$ is the porosity of shale, %; $M_{\mathrm{C}{\mathrm{O}}_2}$ is the molar mass of CO₂, 0.044 kg/mol; $S_w$ is the water saturation of shale reservoir, %; $V_a$ is the volume of adsorption phase in unit volume shale, dimensionless; $T$ is the average reservoir temperature, K; $Z$ is the compressibility factor of CO₂; and R is the universal gas constant, 8.314 J/(mol·K).

There are many classical models to describe the adsorption behavior of CO₂ in shale, including the Langmuir model, Dubinin–Radushkevich (D-R) model, Dubinin-Astakhov (D-A) model, etc. The Langmuir model, despite its simplicity and computational convenience, maintains an excellent fit and is thus widely employed. Consequently, we opted to use the Langmuir model for the calculation of the adsorption storage potential, which can be expressed as

$$n_a=V_L\frac{P_{\mathrm{C}{\mathrm{O}}_2}}{P_L+P_{\mathrm{C}{\mathrm{O}}_2}}$$

(3)

where $n_a$ is the amount of CO₂ absorbed in unit mass shale, m³/kg; $V_L$ and $P_L$ are the Langmuir volume and the Langmuir pressure, respectively, which can be obtained via isothermal adsorption experiment. Considering the pore space occupied by the adsorbed phase, excess adsorption was used to calculate the sequestration potential as follows:

$$C_a=V_L\frac{P_{\mathrm{C}{\mathrm{O}}_2}{\rho }_{shale}{\rho }_{\mathrm{C}{\mathrm{O}}_2}}{P_L+P_{\mathrm{C}{\mathrm{O}}_2}}$$

(4)

$$V_a=\frac{C_a}{{\rho }_a}$$

(5)

where $C_a$ is the storage potential of absorbed CO₂ in unit volume shale, kg/m³. ${\rho }_{shale}$ is the density of shale, 2700 kg/m³; and ${\rho }_{\mathrm{C}{\mathrm{O}}_2}$ is the density of CO₂ at standard condition, 1.96 kg/m³. ${\rho }_a$ is the density of adsorbed phase, 1180 kg/m³.

The storage potential of dissolved CO₂ can be calculated as

$$C_d=\phi S_w{k}_{\mathrm{C}{\mathrm{O}}_2}$$

(6)

where $C_d$ is the storage potential of dissolved CO₂ in unit volume shale, kg/m³; and $k_{\mathrm{C}{\mathrm{O}}_2}$ is the solubility of CO₂, kg/m³, which can be calculated according to the Duan model [47].

When CO₂ dissolves in water, a carbonate ion is generated and can react with divalent cations and lead to carbonate precipitation. CaCO₃, MgCO₃, and FeCO₃ are regarded as the main mineral trapping types. Those non-carbonate minerals that release Ca²⁺, Mg²⁺, and Fe²⁺ via dissolution reactions are considered minerals with carbon trapping potential. The carbon trapping potential of minerals can be estimated by calculating the amount of CO₂ consumed when all the Ca²⁺, Mg²⁺, and Fe²⁺ in non-carbonate minerals in a unit volume of rock are transferred to carbonate precipitations. The storage potential of mineralized CO₂ can be calculated as [48,49]

$$C_m={\displaystyle \sum _{}^{}(n_m\times r)}$$

(7)

where $C_m$ is the storage potential of dissolved CO₂ in unit volume shale, kg/m³; $n_m$ is the mineral content (illite and montmorillonite) favorable for mineralization, kg/m³; and $r$ is the trapping potential of the minerals (r_i = 0.41, r_m = 0.03).

The overall CO₂ storage potential of the Yanchang shale gas formation can be calculated as

$$C_t={\displaystyle \sum A_i}{H}_i(C_f+C_a+C_d+C_m)$$

(8)

where $C_t$ is the total CO₂ storage potential of the Yanchang shale gas formation, kg/m³; $A_i$ is the area of ith block, m²; and $H_i$ is the thickness of ith block, m.

3.2. Breakthrough Pressure Experiment

The Step-by-Step (SBS) method was employed to measure the CO₂ breakthrough pressure (BP) of the shale samples [50,51]. The testing system of BP is shown in Figure 3a. The shale core plugs fully saturated with brine were put into the core holder, and then the net confining pressure and temperature were set according to the formation situation (12 MPa, 50 °C for Chang7 member). Next, the injection pressure of CO₂ at the inlet was increased gradually until continuous and uniform bubbles appeared at the outlet. At this moment, the pressure difference between upstream and downstream was considered to be the breakout pressure. The pressure was maintained for a specific duration after each boost. The magnitude of each boost and the duration of pressure retention were set strictly in accordance with the Chinese Oil and Gas Industry Standard (No. SY/T 5748–2020) [52]. The brine is configured according to the Yanchang formation water (Cacl 2%wt, NaCl 1.5%wt, KCl 1.5%wt). The BP experiments were conducted on 11 samples from the Chang7 member.

3.3. NMR Experiment

NMR tests were carried out on the shale samples to characterize their pore structure. Prior to conducting the NMR test, each core sample was saturated under negative pressure. Once a core sample was saturated with water, it was placed within a high-intensity magnetic field, prompting the hydrogen nuclei in the pore water to align with the magnetic field. These aligned hydrogen nuclei were then excited into a non-equilibrium state via the application of radio frequency pulses. When the radio frequency pulse was turned off, these nuclei returned to their equilibrium state, emitting detectable electromagnetic signals during this process. The strength of these signals correlates directly with the number of hydrogen atoms present, which allows for the determination of pore water volume and, subsequently, the porosity of the core. The time taken for the hydrogen nuclei to return from a non-equilibrium state to an equilibrium state is referred to as the transverse relaxation time (T₂). The relationship between T₂ and pore size r can be expressed as [53]

$$\frac{1}{T_2}=\rho \times \frac{S}{V}=F_s\times \frac{\rho }{r}$$

(9)

where $T_2$ is the transverse relaxation time in ms; $\rho$ is the intensity of transverse surface relaxation in μm/ms; S is the pore surface area in cm²; V is the pore volume in cm³; $F_s$ is the shape factor of the pores; and r is the pore size.

The MacroMR12-150H-I system was employed to characterize the pore structure of the samples (Figure 3b). The main magnetic field of this system is 0.3 T, the R_F pulse is 1–42 MHz, the control precision is 0.01 Hz, and the peak output is greater than 300 W.

3.4. Isothermal Adsorption Experiment

The isothermal adsorption curves of CO₂ on the Yanchang shale were obtained using the volumetric method. The experiment system is shown in Figure 3c, which consists of a sample chamber, a reference chamber, a pressure sensor, a temperature sensor, a water bath, and a set of valves. The details of the experimental procedure can be found in our previous research.

3.5. XRD Experiment

The rest of the sample was crushed into 60–80 mesh powder for XRD analysis to quantitatively analyze the mineral composition of shale samples. XRD analysis was performed on Bruker D8 ADVANCE (Bruker Corporation, Karlsruhe, Germany) following the Chinese Oil and Gas Industry Standard SY/T 5163-2018 [54].

4. Result

4.1. Pore Structure of Yanchang Shale

The NMR experiments were conducted on shale samples taken from the Chang7 member. The aperture distribution and cumulative porosity of shale samples are shown in Figure 4. The aperture distribution of all samples exhibits a bimodal pattern. The dividing point of the two peaks is 0.15 μm. Pores with apertures less than 0.15 μm dominate, and all pores have apertures less than 10 μm. The NMR porosity of shale samples is between 6.77% and 8.02%, with an average value of 7.19%.

4.2. CO₂ Breakthrough Pressure of Yanchang Shale

The breakthrough pressure experiments were carried out on 11 samples. The BP values are displayed from 1.4 MPa to 3.5 MPa, with an average of 1.97 MPa (Figure 5). BP is the most intuitive and important parameter to characterize the capillary sealing capability of caprock. The upper limit of CO₂ pressure in the reservoir is determined by the BP of the overlying caprock, which is numerically equal to the sum of BP and the hydrostatic pressure of the overlying brine (Equation (1)). To maximize storage safety, the minimum breakthrough pressure is adopted to characterize the capillary sealing capacity of the Chang7 shale. The maximum CO₂ storage pressure for Chang7 shale gas formation is estimated to be 13.4 MPa (the average hydrostatic pressure of overlying brine is assumed to be 12 MPa according to the geological condition).

4.3. CO₂ Isothermal Adsorption

The CO₂ isothermal adsorption experiment was conducted at 50 °C. The adsorption capacity obtained directly from the volumetric method is called the excess adsorption capacity ($n_{ex}$), which ignores the pore space occupied by the adsorption phase. The excess adsorption capacity should be corrected to absolute adsorption capacity ($n_{ab}$) via Equation (9). The excess adsorption and absolute adsorption are shown in Figure 6. It can be found that the absolute adsorption capacity increases with pressure. The Langmuir model was used to fit the absolute adsorption capacity. The fitting correlation coefficient (R²) is 0.97192, which indicates that the Langmuir model can well describe the adsorption behavior of CO₂ on Yanchang shale. The values of the Langmuir volume (V_L) and the Langmuir pressure (P_L) are 0.00648 m³/kg and 8.41662 MPa, respectively.

$$n_{ex}=n_{ab}\left(1-\frac{{\rho }_f}{{\rho }_a}\right)$$

(10)

4.4. Mineralogy of Yanchang Shale

The mineral content of Yanchang shale is shown in

Table 1. The mineral content of Yanchang shale.

Quartz	Albite	Pyrite	Kaolinite	Chlorite	Montmorillonite	Illite
36.6%	20.7%	0.9%	10.3%	13.2%	1.7%	16.6%

. The main brittle minerals of Yanchang shale are Quartz and Albite. The total clay mineral content is 41.8%. Montmorillonite and illite are regarded as the main minerals favorable for mineralization, whose content are 1.7% and 16.6%, respectively. The contents of montmorillonite and illite in unit volume shale are 45.9 kg/m³ and 448.2 kg/m³. The XRD diffraction spectra are shown in Figure 7.

4.5. CO₂ Geological Storage Potential of Yanchang Shale

The CO₂ geological storage potential can be estimated via the experimental results and Equations (2)–(8). The reservoir porosity is assumed to be 7.19%, according to the NMR result. The water saturation of the reservoir is assumed to be 0.2. The CO₂ geological storage potential in unit volume shale is shown in Figure 8. For a specific reservoir, mineralization potential is certain as it is only related to mineral content favorable for mineralization. The mineralization potential of the Yanchang shale gas reservoir is estimated to be 139.135 kg/m³. The storage potential of free-state, adsorption, and dissolution increases with the CO₂ storage pressure. It is obvious that the total storage potential is a function of the CO₂ storage pressure, which is determined by the sealing capacity of the caprock. The maximum CO₂ storage pressure of the Yanchang shale gas reservoir is estimated to be 13.4 MPa, at which point the CO₂ storage potential in the unit volume of the shale is 232.16 kg/m³ (free-state 25.21 kg/m³, adsorption 21.06 kg/m³, dissolution 0.75 kg/m³, mineralization 185.14 kg/m³).

Based on the thickness distribution of the Chang7 shale gas formation, the study area was divided into 10 blocks (Figure 1b). The area and thickness of each block are listed in

Table 2. The area and average thickness of blocks.

Block	Area (m2)	Average Thickness (m)	Storage Volume (m3)
1	1.59 × 1010	5	7.97 × 1010
2	1.31 × 1010	15	1.96 × 1011
3	1.56 × 1010	25	3.91 × 1011
4	2.38 × 1010	35	8.33 × 1011
5	7.66 × 1010	45	3.45 × 1011
6	1.12 × 1010	45	5.03 × 1011
7	2.03 × 109	55	1.12 × 1011
8	8.97 × 109	55	4.93 × 1011
9	4.42 × 109	60	2.65 × 1011
10	8.44 × 108	60	5.06 × 1010

. The overall CO₂ storage potential (OCSP) of the Chang7 shale gas reservoir is shown in Figure 9. OCSP increases with the increase in CO₂ storage pressure. When the CO₂ storage pressure reaches the upper limit of the capillary sealing capacity of the caprock (13.4 MPa), the OCSP reaches 7.59 × 10¹¹ t. This shows that the CO₂ geological storage potential of the Chang 7 shale gas reservoir is huge.

5. Discussion

5.1. The Effect of Sealing Capability of Caprock on the Storage Potential

In previous research on the potential of CO₂ geological storage, the sealing capability of the caprock was rarely considered. Obviously, the CO₂ storage potential is a function of storage pressure. The maximum storage pressure of CO₂ is determined by the capillary sealing capability of the caprock, which is equal to the sum of the breakthrough pressure and the pore pressure of the overlying brine. The idea that the maximum storage pressure of CO₂ can reach the pressure of the original gas reservoir may lead to erroneous estimates. The capillary sealing capability of the caprock is determined by its pore structure, wettability, and gas-liquid interfacial tension (IFT). When hydrocarbons are replaced by carbon dioxide, changes in IFT and wettability can lead to significant changes in the sealing capability of a specific cap layer. It is incorrect for a given cap rock to be able to maintain carbon dioxide below or slightly below the original pressure due to its successful sealing of hydrocarbons during geological periods. The sealing capacity of the cap rock should be determined before the start of CO₂ geological storage engineering to enhance confidence in the safety of CO₂ geological storage.

5.2. Theoretical Potential and Available Potential

In the Yanchang shale gas reservoir, the amount and proportion of free-state storage potential, adsorption storage potential, dissolution storage potential, and mineralization storage potential are shown in Figure 10. The ranking from large to small is mineralization storage potential, free-state storage potential, adsorption storage potential, and dissolution storage potential, wherein the mineralization storage potential is 6.05 × 10¹¹ t, accounting for 79.75% of the OCSP. The potential for dissolution and storage is 2.45 × 10⁹ t, accounting for only 0.32% of the OCSP. The free-state storage potential and adsorption storage potential are 8.24 × 10¹⁰ t and 6.88 × 10¹⁰ t, respectively, accounting for 10.86% and 9.07%, respectively.

In a CCUS project, CO₂ will be injected into the underground formation in a free state. Afterward, adsorption and dissolution will rapidly occur. Adsorption and dissolution will reach equilibrium within months to years, depending on field engineering parameters and the physicochemical properties of the storage formation. After CO₂ is dissolved in formation water, it will combine with cations to form inorganic salt precipitation, i.e., mineralization. According to prior studies, the time scale of mineralization processes ranges from hundreds to thousands of years. For a CO₂ geological storage project, the time required for mineralization far exceeds the engineering time scale. Therefore, the mineralization potential should be subtracted from the theoretical potential to obtain the available potential. The available CO₂ storage potential of the shale gas reservoir in the Yanchang Formation is 1.54 × 10¹¹ t, which is still a large amount (Figure 11). If the CO₂ storage potential of the Yanchang shale gas reservoir is fully exploited, it will be able to accommodate 41.49% of global annual CO₂ emissions (according to data in 2021) [55]

6. Conclusions

In this study, a CO₂ storage potential estimation model considering the sealing capacity of caprock was proposed to evaluate the CO₂ storage potential of the Yanchang shale gas reservoir in the Ordos Basin, China. Four types of CO₂ storage states, including free-state, adsorption, dissolution, and mineralization, were considered. The maximum CO₂ storage pressure for the Yanchang shale gas reservoir was estimated to be 13.4 MPa based on the results of breakthrough pressure experiments, which corresponds to a theoretical CO₂ storage potential of 7.59 × 10¹¹ t. Due to the difficulty in completing mineralization within the engineering time scale, the mineralization potential should not be taken into account when estimating the available CO₂ storage potential. The available CO₂ potential of the Yanchang shale gas reservoir is 1.54 × 10¹¹ t. If the available CO₂ storage potential of the Yanchang shale gas reservoir is fully exploited, it will be able to accommodate 41.49% of global annual CO₂ emissions.