Numerical Simulation on Carbon Dioxide Geological Storage and Coalbed Methane Drainage Displacement—A Case Study in Middle Hunan Depression of China

Abstract

Based on a detailed investigation of the geological setting of coalbed methane by previous work in the Xiangzhong Depression, Hunan Province, numerical simulation methods were used to simulate the geological storage of carbon dioxide and displacement gas production in this area. In this simulation, a 400 m × 400 m square well group was constructed for coalbed methane production, and a carbon dioxide injection well was arranged in the center of the well group. Injection storage and displacement gas production simulations were carried out under the conditions of original permeability and 1 mD permeability. At the initial permeability (0.01 mD), carbon dioxide is difficult to inject, and the production of displaced and non-displaced coalbed methane is low. During the 25-year injection process, the reservoir pressure only increased by 7 MPa, and it is difficult to reach the formation fracture pressure. When the permeability reaches 1 mD, the carbon dioxide injection displacement rate can reach 4000 m³/d; the cumulative production of displaced and non-displaced coalbed methane is 7.83 × 10⁶ m³ and 9.56 × 10⁵ m³, respectively, and the average daily production is 1430 m³/d and 175 m³/d. The displacement effect is significantly improved compared to the original permeability. In the later storage stage, the carbon dioxide injection rate can reach 8000 m³/d, reaching the formation rupture pressure after 3 years, and the cumulative carbon dioxide injection volume is 1.17 × 10⁷ m³. This research indicates that permeability has a great impact on carbon dioxide geological storage. During the carbon dioxide injection process, selecting areas with high permeability and choosing appropriate reservoir transformation measures to enhance permeability are key factors in increasing the amount of carbon dioxide injected into the area.

1. Introduction

In recent years, the total energy consumption of the Hunan Province economy has increased [1]. From 2008 to 2015, the total energy consumption of Hunan increased from 123 million tons of standard coal to 155 million tons of standard coal. In 2021, it exceeded 167 million tons of standard coal. From the perspective of consumption structure, Hunan Province is dominated by coal-polluting energy. Coal consumption accounted for 60% of the total in 2015 and 70% in 2021, and it is still the main energy source today [2]. The energy consumption structure is unbalanced, and the proportion of clean energy is lower [3,4]. In recent years, rapid economic development and an imbalance of energy consumption structure have led to an increase in carbon emissions in Hunan Province, and the realization of carbon neutrality is facing serious challenges. The Hunan Energy Development Report 2021 points out that the total carbon emissions from the energy sector in Hunan Province in 2019 are about 310 million tons, and it is predicted that the carbon emissions from the energy sector will peak in 2029–2030 at about 353 million tons. Although the total carbon emission, carbon intensity, and per capita carbon emission data are lower than the national average, the strategic deployment of “carbon peak and carbon neutrality” in Hunan Province is still imminent.

Although Hunan Province has clearly defined the short-term strategic direction of energy transformation under the “dual carbon” goal, the specific implementation path and action plan have not been decided, which is not conducive to the development of corresponding countermeasures and transformation plans in various industries. Hunan Province has large carbon dioxide emissions, and the problem of carbon source storage space can be solved by geological carbon sealing. There are coal seams, shales, sandstones, abandoned mines, goaf, and brackish water beds that can be used for carbon sequestration in the Lianshao Basin, which has good geological conditions and potential for carbon sequestration [5], but their specific characteristics and distribution areas are not clear and have not been studied. In addition, the coalbed methane production in Hunan Province is low, and the coalbed methane production rate can be improved by CO₂ injection [6,7,8].

Geological sequestrations of CO₂ into coal seams can be effective and successful [9,10,11,12,13]. Some numerical simulations of CO₂ geological storage and coalbed methane drainage displacement have been conducted. Vishal et al. used the COMET3 software to simulate CO₂-ECBM [14]. Chen et al. simulated the storage effect of injecting pure CO₂ and a mixture of CO₂ and saline water in the Junggar Basin of China [15]. Jia et al. simulated injection schemes and obtained a favorable threshold time for CO₂ injection [16]. Fatah et al. simulated the effect of mineral content in reservoirs on storage potential [17,18]. Fan et al. simulated the sealing effect generated by different injection well heights, temperatures, and pressures [19]. Zou et al. performed CO₂-ECBM in coal beds of the Longtan Formation in the Xiangzhong Depression of China [2].

Therefore, the authors of this paper collected geological features of coal and coalbed methane in the middle Hunan Depression of China from previous work, and performed numerical simulations of CO₂ geological storage and coalbed methane drainage displacement in the research area. The authors’ conclusions within the paper will facilitate the development of an action plan for Hunan Province to reduce carbon dioxide emissions in the future.

2. Geological Setting

The study area is located in the middle of Hunan Province, and the central Xiangzhong Depression is distributed in the Zhadu, Lengshuijiang, DouShan, Hongshandian, Duanpoqiao, and Gujiaodi mining areas. The specific structure and distribution of the mining areas are shown in Figure 1. It should be noted that Figure 1 is modified from Ref. [5]. The northern part of the Depression is the Lianyuan sag, also known as the Lianyuan coal-bearing area. The Lianyuan fold belt is the northern wing of the Qiyang arc structure, with the Caledonian fold unconformity as the base. There are a series of wide and gentle short-axial synclines distributed from west to east [5,20]. The northern part of the Lianyuan Depression is the Weishan uplift and Xiangtan Depression. The central area is the Shaoyang Depression, with a series of tight to widespread synclines distributed from west to east. The southern area is the Lingling Depression, which has a complex structure consisting of a series of tightly closed folds that are inverted to the northwest and reverse faults that are thrust to the northeast. It often forms an imbricate structure and is also accompanied by transverse faults.

The Longtan Formation (P₃l) of the Upper Permian is an important coal-bearing formation in this area. Bounded by 27°40′ north latitude, the Longtan Formation can be divided into two subtypes, north and south, according to the differences in the development of coal-bearing strata and contact with the upper and lower strata. The sedimentation in north Longtan is thin, with fewer coal layers, and is a tidal flat-related coal-bearing sedimentation set consisting of clastic rocks. It is an important coal-bearing formation in the area, composed of sandstone, siltstone, sandy claystone, carbonaceous shale, coal beds, etc. The thickness of the economically exploitable coal seam ranges from 0.7 to 3.2 m. The Longtan Formation has a large thickness, and the variation of lithology and lithofacies is divided into upper and lower sections. The lower part of the Longtan Formation (P₃l¹) does not contain coal. The upper part of the Longtan Formation (P₃l²) is composed of feldspar, quartz, sandstone, siltstone, carbonaceous mudstone, sandy mudstone, and coal seam, which contains 5–10 layers of coal and can be mined from two layers with a total thickness of 0–12.50 m.

3. Geological Variation of Coalbed Methane

Laboratory experiments to obtain the geological variations of coalbed methane have been conducted in authors’ previous works described in Ref. [5], and the conclusions are as follows. The coal rocks of the Longtan Formation are mostly light black to black or steel gray, with a glass, strong glass, or semi-metallic to metallic luster, and a block, granular, banded, or scaly structure. The fissures are well developed, and the fracture is jagged or stepped, with visible shell-like shapes. The rock type in north Longtan is macroscopically classified as semi-bright to semi-dark coal, with less bright coal. The rock type in south Longtan is semi-bright to bright coal, with less semi-dark and dull coal. The results of the determination of the contents of the organic/inorganic microscopic components show that the vitrinite in this area ranges from 54.37 to 87.80%, the inertinite ranges from 11.14 to 25.89%, the exinite ranges from 0.35 to 14.08% (generally less than 1%), and the inorganic component ranges from 0.71 to 5.66% (clay minerals).

Under the microscope, the residual cellular pores and stomata in the coal body and the endogenous cracks were observed. The primary structure of the coal body is complete, as shown in Figure 2. The porosity test results show that the porosity in the region ranges from 6.59 to 15.94%, and the distribution, which ranges from 7 to 9%, is concentrated. The vertical permeability of the coal core is affected by a large buried depth, coal crushing, and high ground stress, resulting in a low permeability of 0.001–0.025 mD. The horizontal permeability was higher than the vertical permeability and ranged from 0.013 to 0.082 mD, which is lower than 0.05 mD.

The reservoir pressure in this area ranges from 3.74 to 11.58 MPa, and the reservoir pressure is high overall, indicating that the energy of the coal seam is high, which is conducive to the adsorption and desorption of coalbed gas. In addition, excessive reservoir pressure is caused by high ground stress, high gas pressure, and high water pressure, resulting in concomitant structural coal and low permeability. From the perspective of permeability and reservoir reformability, it is not conducive to the drainage of coalbed methane. The Langmuir volume varies from 12.43 to 33.27 m³/t, and the main value is greater than 25 m³/t. The Langmuir pressure ranges from 1.05 to 3.63 MPa, and the main value is greater than 2 MPa. Therefore, the high overall Langmuir volume indicates that the Longtan Formation coal seam has a strong adsorption capacity and development potential of coalbed methane.

The main component of coalbed methane in this area is methane, the content of which ranges from 53.7 to 97.68%. More than 80% of the mine area’s methane content is more than 90%. The CO₂ content ranges from 0.04 to 8.42%, with most being higher than 2%. The N₂ content ranges from 1.5 to 38.4%, with an average of 12.5%. The heavy hydrocarbon content ranges from 0.067 to 8.11%, with an average of 2.6%. Based on desorption in situ, gas content data ranges from 2.0 to 30.3 m³/t, with most of it ranging from 4 to 18 m³/t, as shown in Figure 3.

4. Numerical Simulation of Carbon Dioxide Storage and Displacement

During simulation, the following assumptions are made: 1. The initial gas consists of only methane. 2. The coal reservoir is assumed to be homogeneous. 3. The simulated gas production during the CO₂-ECBM stage only includes methane, and there is no CO₂ leakage after the CO₂ geological sequestration stage.

Based on the above results, combined with Eclipse reservoir numerical simulation software (version 2006.1), a numerical simulation of carbon dioxide storage and displacement gas production in Longtan Formation coal seam was carried out. Based on the experience of single well radius values, the simulation design of a 400 × 400 m square well group coalbed methane mining was generated. A carbon dioxide injection well is placed in the center of the well group to simulate the carbon dioxide injection and storage performance of a single well in the well group, as illustrated in Figure 4. Two stages were designed for this simulation. The first stage is the carbon dioxide injection displacement gas production stage. The design duration is 15 years based on the discharge period of general coalbed methane wells. The long-term low-injection method was chosen for displacement because the original permeability of the coal seam is low and therefore not suitable for a short-term large-scale carbon dioxide injection. First of all, the first 5 years are the gas production stage of carbon dioxide injection displacement. Secondly, the injection well is closed, and only production is generated 10 years later. Finally, the drainage and production were stopped, and the gas-producing wells were closed. The second stage is the carbon dioxide storage stage. The process stops gas production from the square well group and injects CO₂ into the target coal seam through injection wells until the formation rupture pressure is reached. Finally, the carbon dioxide storage capacity of a single well is calculated.

Due to the size limitation of the test samples, there is an error between the core permeability measured in the laboratory and the actual formation permeability. In addition, reservoir fracturing is generally required before coalbed methane wells are produced to enhance permeability. Therefore, the effects of carbon dioxide injection storage and displacement gas production under an initial permeability of 1 mD were respectively simulated. The reservoir parameter values set by the simulation generally adopt the average data of the whole region, and the parameters are derived from the data, as shown in

Table 1. Numerical simulation parameter values.

Reservoir Parameters	Value	Source	Reservoir Parameters	Value	Source
Gas content, m3/t	11	Data average	CH4 Langmuir volume, m3/t	23	Data average
Coal thickness, m	2	Data average	CH4 Langmuir pressure, MPa	2.3	Data average
Porosity, %	8	Data average	Reservoir pressure, MPa	7.6	Data average
Permeability, mD	0.01; 1	Average value + setting	Formation fracture pressure, MPa	60.35	Material
CO2 Langmuir volume, m3/t	31	Material	Rock compressibility, 1/KPa	10−9	Material
CO2 Langmuir pressure, MPa	0.4	Material	Formation water compressibility	4.35 × 10−7	Material

.

In the authors’ previous work, sensitivity analyses for permeability and porosity were performed in detail, as illustrated in Ref. [2], and it was found that permeability is an important parameter in reservoir numerical simulations. In this paper, detailed investigations of permeability on geological sequestration and CO₂-ECBM are performed and illustrated as follows.

Figure 5 and Figure 6 show the effects of carbon dioxide storage and displacement gas production at 0.01 mD and 1 mD permeability, respectively.

Figure 5 indicates that at an initial permeability of 0.01 mD, it is difficult to inject carbon dioxide for displacement. The injection rate is only 100 m³/d, and both the displaced and non-displaced coalbed methane production rates are low, with cumulative production volumes of 14.95 × 10⁴ m³ and 1.81 × 10⁴ m³, respectively. During the injection and sequestration phase, the maximum injection rate of carbon dioxide is only 200 m³/d. During the 25-year injection process, the reservoir pressure increases by only 7 MPa, making it difficult to achieve the formation fracture pressure. Therefore, further simulation is not continued.

Figure 6 shows that when the permeability reaches 1 mD, the CO₂ injection displacement rate exceeds 4000 m³/d, and the injection rate is higher than that under the original permeability condition. During the 15-year production process, the cumulative coalbed methane production for displacement and non-displacement is 7.83 × 10⁶ m³ and 9.56 × 10⁵ m³, respectively, and the average daily production rates are 1430 m³/d and 175 m³/d, respectively. The displacement results in a significant increase in coalbed methane production. In the later storage stage, the initial carbon dioxide injection rate is set to 8000 m³/d. The formation fracture pressure achieved after 3 years was 58.7 MPa, and the cumulative carbon dioxide injection volume was 1.17 × 10⁷ m³.

Figure 7 shows the molar fraction of carbon dioxide after 5 years of carbon dioxide displacement injection at permeabilities of 0.01 mD and 1 mD. At the original permeability of 0.01 mD, due to the difficulty of injecting carbon dioxide, its diffusion is not significant, with only a small amount of carbon dioxide distribution near the injection well. When the permeability increases to 1 mD, its molar distribution shows significant diffusion during the displacement process with the injection of 4000 m³/d of carbon dioxide and spreads throughout the entire well group area due to the favorable permeability.

As can be seen from the above simulations, various permeabilities result in significantly different CO₂ sequestrations, and a higher permeability leads to superior CO₂ injection rates and increases the amount of CO₂ sequestration. Therefore, during the later stages of carbon dioxide injection, selecting areas with developed permeabilities and implementing reservoir enhancement measures to increase permeability is a crucial factor in increasing the amount of carbon dioxide injection.

5. Conclusions

On the basis of ascertaining the geological background of the study area and the geological characteristics of coalbed methane in detail, the numerical simulation of carbon dioxide geological storage and gas production by displacement was carried out. In this simulation, a square well group measuring 400 m × 400 m was constructed for coalbed methane production, with a carbon dioxide injection well placed at the center of the well group. A simulation of injection storage and displacement gas production under the conditions of original permeability and 1 mD permeability was carried out, and the following conclusions were obtained.

(1)

At the initial permeability of 0.01 mD, it was difficult to inject and displace carbon dioxide with an injection rate of only 100 m³/d. In addition, the production of both displaced and non-displaced coalbed methane was low, with cumulative gas production of 14.95 × 10⁴ m³ and 1.81 × 10⁴ m³, respectively. In the injection and storage stage, the maximum carbon dioxide injection rate was only 200 m³/d. During the 25 years of injection, the reservoir pressure only increased by 7 MPa, making it difficult to achieve the formation fracture pressure.

(2)

The penetration rate reached 1 mD, and the carbon dioxide injection displacement rate exceeded 4000 m³/d, which is a significant increase compared to the original permeability conditions. During the 15 years of drainage and production, the cumulative coalbed methane production of displaced and non-displaced coalbed methane was 7.83 × 10⁶ m³ and 9.56 × 10⁵ m³ respectively, with an average daily production of 1430 m³/d and 175 m³/d. In the later storage stage, the initial carbon dioxide injection rate was set at 8000 m³/d. The formation fracture pressure, which was 58.7 MPa, was reached after 3 years,. The cumulative carbon dioxide injection volume was 1.17 × 10⁷ m³.

(3)

At the original permeability of 0.01 mD, due to the difficulty of injecting carbon dioxide, its diffusion was not significant, with only a small amount of carbon dioxide distributed near the injection well. When the permeability increased to 1 mD, its molar distribution showed significant diffusion during the displacement process with an injection of 4000 m³/d of carbon dioxide and spread throughout the entire well group area due to the favorable permeability.

(4)

The amount of carbon dioxide that was trapped was controlled by the reservoir permeability. During the carbon dioxide injection process, selecting areas with high permeability and choosing appropriate reservoir transformation measures to enhance permeability are key factors in increasing the amount of carbon dioxide injected into the area.

The conclusions in this paper will facilitate the development of an action plan for Hunan Province to reduce carbon dioxide emissions in the future.