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. 2024 Jun 10;9(25):26900–26910. doi: 10.1021/acsomega.3c08901

CO2-Controlled Water Injection in Carbonate Gas Reservoirs: An Effective Approach to Improve Production

Jie Wei †, Kai Cheng †,‡,*, Shushuai Wang †,‡, Mingyang Yuan †,‡, Xuanji E §, Chi Cen ∥
PMCID: PMC11209697  PMID: 38947811

Abstract

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In the development of edgewater-type carbonate gas reservoirs, the challenge posed by water flooding in production wells is a significant concern. This study investigates the potential of CO2 injection as a solution for water control. Experiments were conducted to understand the gas–water flow dynamics during CO2-controlled water injection in a series-connected core. Emphasis was placed on the effects of varying the CO2 injection pressure on water flow and gas cumulative production rate. The mechanisms influencing water control and production efficiency across different injection pressures in multiwell production were elucidated. The results showed that the gas production rate of the core increased by 27.2% over the depletion production rate after the CO2 injection pressure was increased from 8 to 13 MPa. The gas production rate increases during the second development cycle from 20% to 55% after switching to CO2 injection, which pushes the edge water further back, slowing down side water flow in the core in the form of segmental plugs, and prolonging the time before water breakthrough. The production time and water breakthrough time for the second development cycle increased with increasing CO2 injection, while the degree of water flow on the core side decreased. These insights are crucial for optimizing the recovery efficiency of edgewater-type gas reservoirs and provide guidance on the application of CO2 injection for water control and CO2 sequestration in carbonate gas reservoirs.

1. Introduction

The utilization of fossil energy on a global scale has led to a concurrent rise in global CO2 emissions. The release of CO2 directly into the atmosphere can contribute to the greenhouse effect, as CO2 is a significant greenhouse gas.1−4 Data indicates that in 2022, CO2 emissions surged by 6% from the previous year, amounting to 36.1Gt, potentially causing a 1.5 °C increase in global temperatures.5,6 To address this, researchers from various fields are currently investigating strategies to reduce greenhouse gas emissions, placing a specific focus on the implementation of Carbon Capture, Utilization, and Storage (CCUS) technology.7 The utilization of CO2 in the development of oil and gas reservoirs has emerged as a prominent area of investigation within the domain of petroleum engineering.8 Currently, the utilization of CO2 in oil and gas reservoirs mostly include unconventional oil and gas drilling techniques, reservoir modification methodologies, and oilfield development.9 Within the domain of drilling, ongoing scholarly investigations predominantly center around the potential corrosion effects induced by the use of CO2 on the wellbore after displacement. The primary objective of these studies is to discern, measure, and alleviate the corrosion resulting from CO2 exposure in both displacement and production wells.10 Thickened CO2 has been identified as a highly effective fracturing fluid within the domain of reservoir modification, but at the same time, CO2 thickening is still facing challenges in particular in finding a cost-effective and efficient polymers.11 In the context of oil and gas field development, CO2 is commonly employed as a displacement or injectant medium due to its ability to form a combination with crude oil and its reduced viscosity.12−15 In addition, scientists are also studying the utilization of CO2 in enhancing oil and gas recovery.12 Previous studies have demonstrated that CO2 has the potential to create a barrier that addresses water-related challenges encountered in oil and gas reservoirs characterized by edges and bottom water. This is attributed to the relatively low diffusion coefficient and solubility of CO2 in water and natural gas.16 While CO2 solubility in water may not be high, as CO2 encounters water in the subsurface system, CO2 solubility can play a role in entrapping CO2 in the brine, which helps CCUS while increasing the yield.17 At the same time, some potential advantages of using carbonated water alongside CO2 to delay breakthrough and optimize gas recovery is very significant.18 Hence, CO2 can serve as a medium for mitigating the water invasion.

The highest recovery stage of an edge water type carbonate rock gas reservoir is the water-free extraction using formation energy. However, ensuring long-term water-free production of the gas reservoir is challenging due to factors such as gas–water distribution patterns, reservoir heterogeneity, and production technology.19 During the development of edge water type carbonate rock gas reservoirs, with the advancement of production, a pressure drops funnel forms centered on the bottom of the production well,20 causing the formation pressure to gradually decrease. The pressure drop in the gas-containing area is faster than that in the edge water area, causing edge water from the high-pressure area to seep into the lower pressure gas-containing area. Initially, edge water moves toward the gas-containing area along larger channels such as fractures and high permeability areas, resulting in the production of edge water in gas wells, a phenomenon known as water invasion in the gas reservoir.21 During water invasion, a gas–water two-phase flow forms in the formation. After the edge water moves along the large pores, natural gas in the low permeability areas of small channels is blocked in the pores by edge water through mechanisms such as snap-off, bypass, and water sealing. This makes it difficult to extract natural gas from low-permeability pores, significantly reducing the natural gas output and production rate of production wells.22 As production continues to advance, formation pressure continues to decrease, the water/gas ratio of the production well continues to rise, the wellbore liquid level significantly increases, and pressure loss problems become prominent. The abandonment pressure of the production well continues to increase with the intensification of water invasion, eventually leading to complete flooding of the production well and a drop-in production to zero. Therefore, how to develop water-containing gas reservoirs in a reasonable and effective manner is an important challenge faced in the development process of edge water type carbonate rock gas reservoirs.

The water control methods mainly include well network optimization, water layer plugging, active drainage, tubing replacement, and mechanical drainage.23−27 The method of optimizing the well network involves changing the well network layout to reduce the unevenness of the production pressure difference and suppress uneven bottom water coning. Based on this, Joshi proposed a horizontal well productivity equation, and the results showed that horizontal wells are suitable for thin layers and gas–water coning reservoirs with high vertical permeability.28 Jin et al.29 proposed the use of DWS technology for drainage to control bottom water coning, but interference between different wells needs to be reduced during implementation. Moreover, overall well network adjustment for oil and gas reservoirs would significantly increase the extraction cost. Water layer plugging mainly includes plugging the water-producing layer and water-producing well section; the advantage of this method is that it can reduce the impact of water invasion, but the disadvantage is that there are fewer application examples, and only some oilfields have practical applications. Clay Cole conducted experiments in West Texas, applying four chemical processes individually or in combination to block high water-producing layers in the reservoir to achieve the effect of preventing water invasion.21 However, each chemical process must be customized according to reservoir conditions, and only a few wells were used. Active drainage includes blowdown, gas carrying water, gas lift drainage, chemical drainage, etc. These methods also have obvious disadvantages: blowdown will waste produced gas, and as gas carries water, the increase in produced water with the decrease in pressure will exacerbate water invasion. The costs of replacing tubing, electric pump drainage, and mechanical drainage are all too high. Wojtanowicz et al.30 studied the installation of water circulation or gas–water separation equipment in wells for development, which was used to control water invasion and achieved significant water control effects, but retrofitting all old wells is not realistic. Research shows that all the above technologies cannot solve the problems of producing pressure decline and severe water production in gas reservoirs while ensuring that production does not decrease. Therefore, there is an urgent need to explore a new technology that can both control water invasion in carbonate rock gas reservoirs and improve the production rate.31

Currently, the research on CO2 injection in carbonate rocks mainly uses means such as microscopic gas–water two-phase flow, core experiments in laboratories, and numerical Mimics in carbonate rock areas to study the extraction effects, sequestration effects, and water–rock reactions after CO2 injection. Hellevang et al. analyzed the interaction of CO2–water–rock under kinetic constraints by solving ordinary differential equations (ODE) and simplifying the solution method.30 Smith et al. conducted core experiments on carbonate rocks with injected CO2, aiming to study water–rock reactions under simulated reservoir conditions and the degree of enhanced recovery.31 Izdec et al. used experiments and numerical Mimics to study the trend of changes in rock porosity and permeability after CO2 injection.32 Overall, there is less research on water control by injecting CO2, but CO2 injection can effectively avoid some of the problems mentioned above.33−37 In this study, we investigated the movement and gas production patterns of edge water after CO2 injection based on a series-connected core flooding experiment. By varying different injection pressure conditions, we explored the dynamic characteristics of marginal water seepage and gas production as well as the effects of different CO2 injections on suppressing water breakthrough and increasing the extent of natural gas extraction from the core.

2. Materials and Equipment for Gas Injection Water Control Experiment

2.1. Materials

The specific parameters of the real core taken from the reservoir are listed in Table 1. The selected gas sources are CO2, CH4, and N2, with a purity of 99% each. The laboratory mixes simulated formation water, and the parameters for mineralization of the formation water are shown in Table 2.

Table 1. Parameters of Nature Cores.

sample No. core length (cm) core diameter (cm) permeability (mD) porosity (%)
1 8 3.8 80 14.9
2 8 3.8 85 15.8
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Table 2. Salt Composition of Formation Water.

mineral composition CO32– SO42– Cl– Ca2+ Mg2+ Na+ salinity
mg/L 6002 485 30085 406 662 18069 55709
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2.2. Experimental Equipment

The experimental equipment includes displacement pumps, differential pressure transmitters, pressure data acquisition modules, thermostatic chambers, piston-type intermediate containers, core holders, back-pressure regulator, gas–liquid separators, six-way valves, gas and liquid collection devices, and several pipelines.

3. Methods and Procedures for Gas Injection Water Control Experiment

3.1. Controllable Method for Simulating Marginal Water Invasion

To accurately simulate the dynamics of actual gas reservoir exploitation, three similarity principles are established for the physical Mimic experiment of controllable marginal water invasion, as explained below:

Rock samples that were representative of a target gas reservoir were drilled and used in the experiments of the relevant gas field to ensure that the parameters such as porosity and permeability of the core in the laboratory experiment match the geological characteristics of the target gas reservoir.38 The gas reservoir adopts a multiwell depletion production method and has an edge water area with sufficient pressure, so it employs a depletion development method in the early stages of development. Therefore, the initial pressure and temperature of the gas reservoir are used as the initial temperature and pressure of the experiment to establish a series-connected physical model of constant-volume depletion development. Use two series-connected core clamps to represent the spacing of production well groups, simulating the depletion production of the near-water end and far-water end well groups of the target gas reservoir and the production after CO2 injection. Additionally, to effectively simulate the state where the production pressure difference decreases significantly during edge water invasion, consider using N2 with pressure to provide pressure for edge water. Control the edge water flow rate through the initial pressure of N2 with pressure (initial pressure being the true pressure of the formation), ensuring that the flooding time at the tail end of the core in the indoor experiment matches the real production dynamics of the target gas reservoir and can simulate the gradual decrease in pressure difference during depletion production. Calculating the volume of nitrogen required during the experiment is crucial for determining the nitrogen volume under room temperature conditions as edge water is transported to the core holder by the expansion pressure of gas in the intermediate container.

N2 expansion volume:

3.1. 1

where P1 represents the formation pressure at water breakthrough, Z1 denotes the gas compressibility factor of the inert gas at pressure P1, P2 is the initial formation pressure prior to development, Z2 indicates the gas compressibility factor of the inert gas at pressure P2, and ΔVg signifies the volume expansion due to high-pressure nitrogen between pressures P2 and P1.

Water invasion volume, Vw:

3.1. 2

where Vw is the volume of marginal water invasion in the core, Vs is the pore volume of the core, and r is the invasion coefficient at the time of water flooding in the reservoir.

Amount of gas substance, n:

3.1. 3

The volume of gas expansion is equal to the volume of water invasion, and the amount of substance in the gas expansion process remains unchanged. Therefore, by solving eqns 1, 2, and 3 simultaneously, we obtain the initial pressure Pg0 of the gas in the intermediate container and its expression (eq 4):

3.1. 4

where Pg0 is the initial gas pressure, Vg0 is the volume of the piston-type intermediate container, and Zg0 is the gas compressibility factor of the inert gas under pressure Pg0.

3.2. Experimental Setup and Procedures

The connected core flooding experimental setup was used for the CO2-controlled water injection experiments, as depicted in Figure 1. This Article provides a summary of the experimental methodologies employed.

  • ①

    Core saturation with gas: After vacuuming the dry core for 8 h, a displacement pump is used in constant pressure mode to inject CH4 from the intermediate container into the series core holder. When the pore pressure of the core reaches the set pressure, it is considered to have reached equilibrium with the core saturated gas, and the amount of saturated gas is measured.

  • ②

    Mimic of core water invasion process: Nitrogen gas is injected into the piston-type intermediate container from above until the pressure reaches Pg0 as defined in eq 4. Formation water is injected into the piston-type intermediate container from below until the pressure in the water tank reaches the pore pressure of the core. The lower end of the intermediate container is connected to the front end of the fully saturated core holder. The tail end of Core 1 (front end core) is connected to the back-pressure valve, gas–liquid separator, and gas flow meter. The pressure of the back-pressure valve is set to the pore pressure of the core and decreases it by 0.5 MPa per cycle until the core is completely water-flooded. The gas production, water production, and system pressure changes are recorded.

  • ③

    Mimic of CO2 water control process: Once the front-end core is fully water-flooded, production is stopped. CO2 is injected between the two cores until the pore pressure of the core reaches the target value. The volume of CO2 injected is calculated based on the input volume. Once the pressure stabilizes, production is continued starting from the tail end of Core 2 (rear-end core). The pressure of the back-pressure valve is decreased by 0.5 MPa per cycle until the core is completely water-flooded. The gas component is analyzed using gas chromatography and the gas production, water production, and system pressure changes are recorded.

  • ④

    CO2 injection optimization method: The process steps ① to ③ are recorded and vary the CO2 injection pressure in the displacement pump’s constant pressure mode. A relationship curve is established between the improvement in gas production rate from the core after gas injection and the amount of gas injected. The gas injection volume is optimized based on this curve.

Figure 1.

Figure 1

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Experimental setup of CO2 injection for water control.

4. Results and Discussion

4.1. Depletion-Style Gas and Water Flow Characteristics in Development

The characteristics of gas production and edge water infiltration in the series core during the depletion-style development phase were examined. The gas production stage at the end of Core 1 is termed the first-stage depletion development, whereas that at the end of Core 2 is the second-stage depletion development. Figure 2 presents the pressure profile of the first-stage depletion in the series core.

Figure 2.

Figure 2

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Pressure curve of first-stage depletion development in series of cores.

According to the findings presented in Figure 2c, it can be observed that there is minimal disparity in pressure between Core 1 and the terminal section of Core 2. However, it is important to note that the pressure levels in both cores are lower compared to the pressure of the edge water in the initial stage of depletion development. Additionally, at the beginning of production, the pressure difference between the tail end of the core and the edge water is relatively small, around 0.2 MPa in Figure 2a,b. As production progresses, the pressure difference between the tail end of the core and the edge water gradually increases, reaching a maximum of around 1 MPa in Figure 2a,b. This indicates that during the first-stage development, as production progresses, the pressure of the gas in the series core decreases, leading to a gradual reduction in the producing pressure required to maintain production.

Figure 3 depicts the edge water pressure and pressure difference at the end of Core 1, while Figure 4 illustrates the volume of gas production under varying back pressures. The integration of the pressure differential profile depicted in Figure 3 with the gas production volume observed under varying back pressures in Figure 4 enables an analysis of the dynamic variations in edge water infiltration and the gas production attributes of Core 1 during this stage. In the first stage, the pressure difference between the edge water and the tail end of Core 1 is relatively small (around 0.4 MPa) and shows a minimal fluctuation. This indicates that during the initial phase of production, there is still a significant amount of gas energy in the core, resulting in a relatively low level of edge water infiltration and limited producing pressure recharge in the core. As the pressure decreases during depletion production, gas production gradually declines. In the second stage, the pressure difference increases gradually, indicating intensified edge water infiltration, leading to a severe water breakthrough in Core 1. The water influx effectively replenishes the producing pressure in the core, resulting in increased gas production and maintaining it at a relatively high level. In the third stage, water breakthrough is observed at the tail end of Core 1, and the fluctuation in pressure difference further intensifies with a maximum range of 0.4 MPa. At this point, the edge water occupies some of the highly permeable pores in the core, resulting in a decrease in the level of gas production. In the fourth stage, Core 1 is completely water-flooded and the pressure difference between the edge water and the tail end decreases rapidly, eventually stabilizing around 0.3 MPa. In this stage, the edge water occupies all of the effective pores of the core, resulting in zero gas production.

Figure 3.

Figure 3

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Pressure difference profile at both ends of Core 1 during first-stage depletion development.

Figure 4.

Figure 4

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Gas production volume at different back pressures during first-stage depletion development.

Figure 5 displays the pressure profile of the second-stage depletion development in the series of cores. Currently, Core 1 is fully inundated with water, leading to the absence of gas production. Consequently, a marginal pressure disparity of roughly 1 MPa exists between the front and posterior sections of Core 1. In contrast, in the second stage of production, there is a steady increase in the degree of water breakthrough in Core 2 as the back-pressure lowers. This results in a stepwise increase in the pressure difference between the front and rear ends of Core 2, reaching around 1.5 MPa. The pressure difference observed in Core 2 throughout the first-stage development is significantly higher than that of Core 1, mostly due to the superior qualities of Core 2, as indicated in Table 2 (Figure 3). In contrast to the initial phase of development, the subsequent phase has a shorter duration. Following a mere five cycles of development, Core 2 attains full saturation with water. This observation suggests that cores exhibiting superior physical qualities experience a more pronounced water breakthrough.

Figure 5.

Figure 5

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Pressure profile of second-stage depletion development.

Figure 6 illustrates the gas production volume observed during the second-stage depletion development in the series of cores. During the initial phase, the edge water does not fully penetrate Core 2. As the back pressure diminishes over time, the occurrence of water breakthrough in Core 2 intensifies. Additionally, this phenomenon yields enhanced producing pressure restoration in Core 2, resulting in a swift escalation of gas generation, culminating at roughly 340 mL prior to the occurrence of water breakthrough. The second stage commences with the occurrence of water breakthrough in Core 2 during the third reduction in back pressure. Following the occurrence of water breakthrough, the gradual reduction in back pressure results in the dominance of edge water within the preferential flow channels located in the core. The consequence of this phenomenon is a swift reduction in gas production within Core 2, reaching approximately 40 mL. This phase persists until the core is fully saturated with water.

Figure 6.

Figure 6

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CH4 production curve at different back pressures during second-stage depletion development.

4.2. Gas and Water Flow Characteristics in CO2 Water Control Development

An experimental study was done to address the challenges of rapid water invasion and poor gas production during the depletion-style development phase. The focus of the research was the development of CO2 water control techniques for the cores. The present study examined the flow characteristics of both the edge and bottom water and gas during the CO2 injection. Additionally, it assessed the influence of the volume of CO2 injected on the effectiveness of the water control. Moreover, in light of this research, the injection volume of CO2 was manipulated in order to investigate the flow characteristics of the edge and bottom water, as well as the gas generation, across varying CO2 injection volumes.

An additional experiment was undertaken to investigate the effects of CO2 injection on secondary production following water flooding in Core 1. The experiment involved infusing CO2 at a pressure of 8 MPa, and the resulting changes in secondary production were observed and compared with the effects of secondary depletion development. Figure 7 presents the variations in pressure differences observed between the development of the CO2 water control and the depletion development in the series cores. During the process of depletion production, a significant occurrence of water breakthrough was observed, resulting in the occurrence of water breakthrough in Core 2 as early as 5 min into the production stage. The pressure differential between the anterior and posterior regions of Core 2 exhibited a notable increase of roughly 0.25 MPa, indicating a substantial change. Following the injection of CO2, there was a notable delay in the onset of water breakthrough in Core 2, which transpired around 15 min into the production process. Furthermore, the extent of breakthrough seen was comparatively reduced. The pressure differential between the front and posterior regions of Core 2 exhibited a modest increase of roughly 0.2 MPa, accompanied by a comparatively smaller increment. This finding suggests that the infusion of CO2 has the potential to both impede the occurrence of water breakthrough and diminish the magnitude of the water breakthrough. Following the injection of CO2, the core exhibits enhanced stability, resulting in an extended production duration.

Figure 7.

Figure 7

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Comparing pressure differences between CO2 water control development and depletion development.

From Figure 8, it can be observed that, after injection of CO2, Core 2 starts to experience water breakthrough at the tail end in the second gas extraction cycle, while during depletion production, water breakthrough in Core 2 occurs only in the third gas extraction cycle. However, even after water breakthrough at the tail end of Core 2 following CO2 injection, the core can still complete four gas extraction cycles before complete water flooding, whereas during depletion production, it becomes completely water-flooded after the second cycle following water breakthrough. Additionally, after water flooding, the gas production decreases rapidly during depletion production with a reduction of approximately 80%. However, after CO2 injection, the reduction is only about 45%. This indicates that CO2 injection can effectively delay and inhibit the speed of edge water occupying the effective channels, thereby extending the effective production time. According to Figure 9, it can be observed that after CO2 injection, while extending the production period, there is also a significant increase in the total CH4 production. According to Figure 10, After the end of the secondary production, the edge water production under the CO2 transfer mode is 3 cm3 less than that under the depletion mode, which can effectively show that the edge water flow during the secondary production is effectively slowed after the CO2 transfer mode.

Figure 8.

Figure 8

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Production of CH4 under different back pressures in two development approaches.

Figure 9.

Figure 9

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Total CH4 production in two development approaches.

Figure 10.

Figure 10

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Total edge water production in two development approaches.

4.2.1. Flow Characteristics of Gas and Water in CO2 Control Water Injection Development at Different Pressures

Figure 11 demonstrates the variation of production pressure at the front and back ends of Core 2 at different injection pressures. It can be observed that after the injection, the pressure differences under different injection volumes remain at lower levels (around 0.05 MPa), indicating that the injected CO2 effectively replenishes the producing pressure of the core and pushes back the edge water, thereby reducing the degree of water invasion. As production progresses, the core with a smaller amount of reinjected CO2 experiences faster water breakthrough due to gas extraction, resulting in a continuous increase in pressure difference at a magnitude of around 0.2 MPa. On the other hand, the core with more injection volume can push back the edge water to a greater distance, resulting in slower water breakthrough, which occurs only after around 25 min of production. Once water breakthrough occurs, the increase of differential pressure in the core with more reinjection volume is also smaller than that in the core with less reinjection volume, which is about 0.1 MPa increase. This indicates that the more the amount of reinjection, the smaller the degree of edge water breakthrough.

Figure 11.

Figure 11

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Pressure variation under different injection pressures.

In Figure 12, we present the gas production trends during the CO2-controlled water injection in a series-connected core. Broadly, CH4 production across varying injection volumes displays a general decline. The peak CH4 production is observed during the initial extraction cycle, whereas the minimum is noted just before water flooding. This suggests that post-CO2 injection, as it repels the edge water in the core, a gas–water plug emerges between the edge water and CH4, ensuring their effective separation. In the subsequent extraction, most of the isolated CH4 is extracted prior to water contact. However, a minor fraction of CH4 is transported by CO2 and extracted after water contact.

Figure 12.

Figure 12

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Gas production during CO2-controlled water injection development: (a) the production of CH4 and (b) the production of CO2.

Conversely, CO2 production trends start with a gradual rise, attaining a zenith, and then diminishing. This can be attributed to CO2’s role in liberating most of the isolated CH4 from the core before its own release. Before water contact within the core, the CO2–CH4 mixed gas predominantly occupies the preferential pathways, leading to augmented gas production. Yet, post water contact, the edge water increasingly takes over the core’s high-permeability channels, obstructing gas production and subsequently causing a drop in CO2 production.

Analysis of various gas extraction cycles reveals that greater injection volumes correspond to elevated CH4 and CO2 production relative to lesser volumes. This underscores that larger injection volumes can notably boost the core’s recovery efficiency, and the greater the CO2 transfer volume, the less the water production, as delineated in Figures 13 and 14. Overall, in contrast to the work conducted by Liu et al.,6 our research focuses on examining the impact of CO2 injection as a controlling water medium across a series of numerous cores. This study conducts a comprehensive analysis, both qualitatively and statistically, to evaluate the effects of CO2 injection on various cores. The findings of this research contribute to the establishment of a theoretical framework for the regulated growth of water in multiwell gas reservoirs.

Figure 13.

Figure 13

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CH4 recovery levels under different CO2 back pressure.

Figure 14.

Figure 14

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Total edge water production under different injection pressures.

5. Conclusions

In this study, we investigated CO2 gas injection and water control in carbonate reservoirs through core flooding experiments, encompassing gas injection depletion development and development with varying CO2 injection pressures. Our conclusions, now reinforced with additional quantitative data, further underscore the advantages of CO2-controlled edge water flooding:

  • (1)

    Initial depletion primary development reveals a gradual, uniform edge water infiltration into the core. As natural gas extraction progresses, the pressure differential between the edge water and production well intensifies, resulting in water flooding through high-permeability channels. The secondary phase mirrors the primary, albeit with accelerated water flooding.

  • (2)

    CO2 displacement injection yields a gas–water plug, isolating encroaching edge water and CH4. This deceleration of water breakthrough, coupled with reduced pressure differences, extends the core’s development cycle, leading to a significant 12% increase in CH4 production and recovery factors.

  • (3)

    Increasing CO2 injection volumes not only contributes to the delay of water breakthrough in the core, particularly in Core 2, but also extends the secondary development cycle’s production time by 10 min, further enhancing the CH4 production and recovery factors.

  • (4)

    Our study delves into CO2 injection’s role in controlling water in a multicore series, offering both qualitative and quantitative insights. By enriching our conclusions with specific data comparisons, we establish a robust understanding of the advantages of CO2-controlled edge water flooding, building upon and enriching prior research.

Acknowledgments

The authors would like to acknowledge the China Scholarship Council (CSC) for funding this research work through the research grant (CSC Nos. 202206440058 and 202306440038).

Data Availability Statement

The authors declare that the data in this article is available.

Author Contributions

The corresponding authors contributed greatly to this article, and all authors contributed equally.

The authors declare no competing financial interest.

Special Issue

Published as part of ACS Omegavirtual special issue “CO2 Geostorage”.

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