Analysis of Factors Impacting CO₂ Assisted Gravity Drainage in Oil Reservoirs with Bottom Water

Abstract

In recent years, there has been significant focus on the issue of global carbon emissions. One of the most prominent areas of research in this regard is the use of carbon capture, utilization, and storage (CCUS) technology in the petrochemical industry. At present, the utilization of CO₂ Assisted Gravity Drainage (CAGD) in oil reservoirs, particularly those containing bottom water, is considered to be in the early stages of exploration and development. In this study, a mechanistic model was built, and five key factors influencing CAGD were analyzed. These factors included the reservoir structure, CO₂ injection site, initial formation pressure, reservoir thickness, and CO₂ injection rate. Then, the applicable rules governing CAGD in oil reservoirs with bottom water were obtained. Finally, these rules were employed in an actual reservoir to optimize the injection-production parameters. The results of the influence factor analysis indicated that CAGD was more suitable for anticline structural reservoirs. The combined top-waist CO₂ injection could fully utilize gravity differentiation in a short timeframe to expand the lateral sweep range of the CO₂. CAGD was more effective when the reservoir pressure was greater than the minimum miscible pressure and the reservoir thickness was between 25–50 m. The generation of a secondary CO₂ cap was favored when the CO₂ injection rate was 35,000 m³/d. Results from A Oilfield applications indicated that, following the application of CAGD technology, A Oilfield experienced an increase in cumulative oil production of 15.76 × 10⁴ t, a 10% reduction in water cut, and an amount of 82.15 × 10⁶ m³ of CO₂ that was sequestered in the subsurface. These findings can offer practical insights and guidance for the future development of CAGD techniques in similar reservoirs.

1. Introduction

The advancement of human society and the continuous evolution of scientific and technological civilization have brought to light the significant environmental and public health risks posed by CO₂ and other pollutants generated from fossil energy sources [1]. To ensure the sustainable progression of human civilization, every industry must collectively strive towards two pivotal objectives: achieving carbon peak and carbon neutrality [2,3]. Hence, it is imperative for individuals and industries to explore innovative technologies aimed at mitigating carbon emissions. Currently, the primary methods for carbon emission reduction revolve around carbon capture, utilization, and storage (CCUS). This approach is widely recognized as the most cost-effective and practical means to curtail greenhouse gas emissions and mitigate the pace of global warming in the future [4]. At present, the concept of CCUS is widespread in the crude oil industry, and the relevant technology is being constantly updated [5,6]. Several oilfields have currently initiated CCUS-enhanced oil recovery (EOR) projects. Yanchang Oilfield has established four demonstration areas for CO₂ EOR and storage while Qilu Petrochemical Company and Shengli Oilfield have completed a million-ton-scale CCUS-EOR project [7]. However, the research on the utilization technology of CO₂ still needs to be strengthened so as to solve the problem of carbon neutralization while ensuring economic benefits [8,9,10].

The most commonly employed method in oilfields involves injecting CO₂ into oil and gas reservoirs to enhance oil recovery while simultaneously sealing a portion of the CO₂ underground [11,12]. D.H. Stright et al. [13] explored the application of CO₂ miscible flooding technology in heavy oil reservoirs with bottom water and conducted field experiments. The results indicated that when injecting only a small quantity of CO₂, the efficiency of enhanced oil recovery through CO₂ miscible flooding in reservoirs with bottom water was limited. This limitation was attributed to the bottom water coning. Li et al. [14] employed physical simulation techniques for CO₂ flooding and CO₂ huff and puff in a bottom water model. Their research focused on assessing the impact of these methods on oil recovery in oil reservoirs with bottom water. The study revealed that CO₂ flooding following water flooding could enhance oil recovery. However, it was observed that the increase in oil recovery achieved through CO₂ huff and puff was significantly greater than that achieved through CO₂ flooding alone. CO₂ was injected into a reservoir with bottom water followed by a soaking period, wherein a portion of the CO₂ dissolved into both the oil and water phases. This dissolution process served to increase energy levels, reduce viscosity, and assist in facilitating production. As such, these mechanisms collectively contribute to an improvement in oil recovery of the reservoir. Hao et al. [15] demonstrated the mechanism and influencing factors of CO₂ huff and puff synergistic flooding in an edge water fault block reservoir through laboratory experiments. Findings were made that the mechanism of synergistic effect could be divided into formation energy supplementation, gas flooding, gravity differentiation, and CO₂-assisted edge water flooding. Injecting CO₂ supplementary energy into lower wells could effectively control edge water invasion. After gas injection at different positions of the well group, multi-well cooperation could be realized, thereby achieving a better cooperative oil displacement effect. Chen [16] conducted a study on phase mixing and gravity on the efficiency and storage potential of EOR and designed a series of displacement experiments. By comparing the displacement results under various combinations of phase behavior and gravity, the optimal method for enhancing oil recovery through CO₂ injection was confirmed. The experimental results indicated that, for oil recovery in the absence of miscible, top gas injection was the most effective, followed by horizontal gas injection, while bottom gas injection was the least effective. In miscible displacement, reservoir thickness and injection direction were no longer the critical factors influencing CO₂ displacement results. Regarding CO₂ storage capacity, in immiscible conditions, maximizing the use of gravity through top gas injection obtained the highest CO₂ storage capacity, with a storage rate of 65.35%. As pressure increased, the influence of gravity on CO₂ storage capacity diminished. In miscible conditions, irrespective of the injection direction, CO₂ exhibited a remarkably high storage potential. Zhou et al. [17] constructed a polynomial response surface model for a fault block low-permeability reservoir in Jiangsu Oilfield and analyzed the factors affecting the oil exchange rate of CO₂ gravity-stable flooding from the aspects of reservoir dip, reservoir thickness, permeability, crude oil viscosity, and permeability difference. Ultimately, a method suitable for CO₂ gravity-stable flooding reservoir optimization in Jiangsu Oilfield was established. The results revealed that the effect of CO₂ gravity-stable flooding in reservoirs with large permeability differences and high crude oil viscosity was poor, while the effect of CO₂ gravity stable flooding in reservoirs with larger dip angle, higher permeability, and thicker thickness was better. While significant progress has been made globally in enhancing oil recovery through CAGD, the application of this technology to mitigate the rise of bottom water remained primarily in the exploratory phase. The effective containment of bottom-water coning is a crucial factor that directly impacts the overall success of reservoirs with bottom water development. However, for oil reservoirs with bottom water, this technology is still in the exploration stage and has not made significant progress.

A Oilfield is a bottom water sandstone reservoir with structural anticline features, situated at depths ranging from 2500 m to 4700 m. The reservoir exhibits an average porosity of 17.6% and an average permeability of 12.63 mD. The average formation pressure is 33.69 MPa, and through slimtube experiments the minimum miscibility pressure has been determined to be 22 MPa. Following natural energy development, the reservoir has experienced significant bottom water invasion, leading to a rapid rise in the oil-water interface. Based on the analysis of oil saturation (Figure 1), it is evident that certain blocks are experiencing severe bottom water invasion. The remaining oil is concentrated primarily in the upper portion of the reservoir, resulting in a higher oil saturation in this zone. In the initial stages of development, the oilfield exhibited relatively high oil production due to the natural bottom water energy. However, this was accompanied by a rapid increase in water cut. Once the water cut reached 90% (Figure 2), crude oil extraction in the lower portions of the structure essentially concluded, leaving the remaining crude oil primarily in the middle and upper section of the reservoir. The water cut has transitioned from a phase of rapid increase to a phase of slow growth. After a certain period, the water cut in the oilfield exceeded 98%.

In the case of A Oilfield, conventional gas flooding has limitations as it can only partially displace the crude oil in the reservoir [18]. Moreover, it is not effective in addressing the high water cut issue resulting from the positioning of production well perforations below the oil-water interface. CO₂ EOR technology is typically employed as a significant means to enhance recovery in the later development stages of low-permeability, high-pressure sandstone reservoirs. CAGD, as one of the main CO₂ EOR technologies, involves injecting a significant amount of CO₂ into the upper part of the reservoir, creating a CO₂ cap at the upper structural position of the reservoir. The technique primarily relies on gravity as the main driving force, while using the gas cap formed by CO₂ injection for gas displacement. The process utilizes the expansion energy of the gas, gravity, and pressure difference resulting from CO₂ injection to displace the crude oil from higher to lower regions. This process lowers both the gas-oil interface and the oil-water interface (Figure 3 and Figure 4). Additionally, CO₂ can cause the release of bound water from clay minerals, leading to a reduction in the particle size of clay minerals. When CO₂ dissolves in formation water, it forms a carbonic acid solution, capable of dissolving minerals such as carbonates and silicates in the formation, effectively improving the physical properties of the reservoir. The miscibility of CO₂ with crude oil not only reduces the interfacial tension and viscosity of the crude oil, thereby enhancing crude oil displacement efficiency, but also, owing to its strong diffusion and mobility, can displace crude oil from small pores that are hard to reach by water flooding [19]. Finally, when CO₂ or miscible liquid encounters an impermeable cap rock and cannot migrate upward, it becomes trapped within the cap rock, effectively storing the CO₂ [20]. Therefore, CAGD is suitable for A Oilfield.

In this study, a corresponding mechanism model was established according to the characteristics of A Oilfield, and the factors affecting CAGD applied in this type of oilfield were studied from the aspects of reservoir structure, CO₂ injection site, initial formation pressure, reservoir thickness, and CO₂ injection rate. The applicable rules of CAGD technology are derived and subsequently applied to optimize injection-production parameters in A Oilfield. Findings were made that CAGD technology can be highly effective in extracting the remaining oil from the upper sections of oil reservoirs with bottom water, especially in areas with low-permeability flow channels. Additionally, this technology has the capability to restrain bottom-water coning, leading to an improvement in water cut and an overall enhancement in oil recovery. Simultaneously, it plays a crucial role in sequestering a significant amount of CO₂ underground, thereby reducing carbon emissions. This approach offers a dual benefit, promoting both environmental conservation and economic advantages [21].

2. Methods

2.1. Establishment of Mechanism Model

To combine the actual geological characteristics of A Oilfield with pressure-volume-temperature properties and the relative permeability relationship between oil-water and oil-gas, the tNavigator reservoir numerical simulation software was utilized to establish a three-dimensional mechanism model for the reservoir with bottom water. The grid number, grid size, the initial porosity, the initial permeability, the initial oil-water interface, the minimum miscible pressure, and the rock compression coefficient, respectively, are 12 × 10 × 22, 100 m × 100 m × 5 m, 15%, 20 Md, 3250 m, 22 Mpa, and 1.45 × 10⁻⁴ Mpa. The basic parameters of the model are shown in

Table 1. Basic parameters of the model.

Parameter	Numerical Value
grid number	12 × 10 × 22
grid size in X, Y, Z direction, m	100, 100, 5
Initial porosity, %	15
Initial permeability in X direction, mD	20
Initial permeability in Y direction, mD	20
Initial permeability in Z direction, mD	20
Initial oil-water interface, m	3250
Minimum miscible pressure, MPa	22
Rock compression coefficient, MPa−1	1.45 × 10−4

and

Table 2. Information about crude oil components.

Crude Oil Component	Molar Content (%)
N2	0.29
CO2	1.17
C1	53.78
C2	6.93
C3–6	8.14
C7–17	22.50
C18+	7.20

, and the relative permeability curve is displayed in Figure 5 and Figure 6. There are 11 wells in the model, including 8 production wells (P2–P9) and 3 gas injection wells (INJ1–INJ3). The well locations are shown in Figure 7.

2.2. Analysis of the Mechanism and Influencing Factors of CAGD

In this study, the mechanism and influencing factors of CAGD were explored by establishing a mechanism model, and the effects of CAGD under different reservoir structures, CO₂ injection sites, initial formation pressures, reservoir thicknesses, and CO₂ injection rates were simulated, respectively, thereby providing theoretical guidance for exploring the development scheme and adjustment scheme of CAGD in anticline reservoirs with bottom water.

• Reservoir structure;

To investigate the influence of reservoir structure on the effect of CAGD, two kinds of reservoir structures with or without anticline were set up for the numerical simulation model, and the sweep range and gas saturation after CO₂ injection were compared.

• CO₂ injection site;

The CO₂ injection position directly affects the scale and range of CO₂ cap formation. According to the established numerical simulation model, three kinds of CO₂ injection sites were set up under the condition of the same total CO₂ injection volume, including waist CO₂ injection on both sides, CO₂ injection at the top and combined CO₂ injection at the waist and top, so as to analyze their influence on oil displacement effect.

• Initial formation pressure;

For investigating the influence of initial formation pressure on the effect of CAGD, considering that the minimum miscible pressure of crude oil is 22 MPa, three different initial formation pressures (12 MPa, 22 MPa, and 32 MPa) were set.

• Reservoir thickness;

To explore the influence of reservoir thickness on the effect of CAGD, models with 5, 10, and 15 layers were established to simulate the oil saturation before and after CAGD.

• CO₂ injection rate.

To investigate the impact of CO₂ injection rate on the effect of CAGD, three CO₂ injection rates were chosen: 25,000 m³/d, 35,000 m³/d, and 45,000 m³/d, while keeping the other parameters constant.

2.3. Filed Application

2.3.1. Well Pattern Conformation of CAGD

Considering the previous production status of A Oilfield and aiming to minimize workload, no new additional wells were established. Instead, the well layout was arranged based on the positions and production conditions of existing wells.

2.3.2. Optimization of Injection-Production Parameters

Various CO₂ injection modes, CO₂ injection rates, injection-production ratios, and supplementary CO₂ injection were simulated to identify and select the optimal parameters for implementing CAGD.

• Optimization of CO₂ injection mode

Two different CO₂ injection methods (

Table 3. Design of injection mode.

Scheme	Gas Well Injection Mode
1	Continuous gas injection	Monthly
2	Intermittent gas injection	Inject 4 months; stop for 2 months

), continuous CO₂ injection and intermittent CO₂ injection, were designed to compare the CO₂ sweep range.

• Optimization of CO₂ injection rate;

CO₂ injection rate is one of the most sensitive factors affecting the scale and development effect of secondary gas caps. In this study, four kinds of CO₂ injection rates were designed: 50,000 m³/d, 70,000 m³/d, 90,000 m³/d, and 110,000 m³/d. These rates were simulated over a period of ten years.

• Optimization of injection-production ratio;

In order to explore the optimal injection-production ratio, five injection-production ratio schemes were designed wherein the injection-production ratios were 0.7, 0.8, 0.9, 1.0, and 1.1, respectively. Those parameters were predicted over 10 years and the cumulative oil production was compared.

• Supplementary CO₂ injection.

The limited number of CO₂ injection wells led to CO₂ retention near the wellbore. Subsequently, pressure differentials within the reservoir, following oil production, resulted in the susceptibility of CO₂ to viscous fingering along the oil well paths [22]. When multiple wells collaborate for CO₂ injection, gas channels can form between injection wells. This effectively mitigated viscous fingering between wells, maintained a stable oil-gas interface, slowed the rise of the oil-water interface, allowed for a more comprehensive exploitation of gravity differentiation, and increased CO₂ utilization. Therefore, in the later stages, there are plans to add new wells for supplemental CO₂ injection.

3. Results and Discussion

3.1. Influencing Factors of CAGD

3.1.1. Reservoir Structure

Through comparing Figure 8 and Figure 9, an observation could be made that after CO₂ injection, the CO₂ in the non-anticline structure reservoir spread around and failed to form a significant CO₂ cap in the upper region. Conversely, after CO₂ injection in the anticline structure reservoir, the remaining oil collected at the top miscible with CO₂, significantly reducing the viscosity of crude oil. This allowed the remaining oil in the upper part to be preferentially extracted. As a result, the subsequent injected CO₂ could accumulate in the upper region (Figure 10). This accumulation of CO₂ helped push down the oil-water interface, resulting in the desired effect of gravity drainage [23]. Additionally, it effectively sequestered the gathered CO₂.

3.1.2. CO₂ Injection Site

According to the following figures (Figure 11, Figure 12 and Figure 13), when the same amount of CO₂ was injected, injecting CO₂ at the waist of the anticline resulted in the injected CO₂ becoming miscible with the remaining oil in the middle of the structure. This prevented CO₂ from effectively accumulating at the top of the anticline structure, thus affecting the efficiency of gravity differentiation. While CO₂ injection at the top of the anticline structure could quickly establish gravity differentiation, prolonged and excessive CO₂ injection at the top could lead to downward gas breakthrough [24]. This resulted in higher gas saturation in grid No. 6 and No. 7 (Figure 14) and a less effective lateral CO₂ sweep. On the other hand, combined CO₂ injection at both the top and waist of the anticline structure could achieve effective gravity differentiation throughout the anticline quickly and maintain a good lateral CO₂ sweep effect. This approach was beneficial for the formation of a large-scale CO₂ cap.

3.1.3. Initial Formation Pressure

An observation could be made that when the formation pressure was higher, the effect of miscible flooding was better, which was more conducive to CO₂ accumulation (Figure 15, Figure 16 and Figure 17). As the initial reservoir pressure decreased, the gas compressibility factor also decreased, resulting in a larger underground volume for the same surface volume of injected CO₂ [25]. Consequently, gas coning occurred earlier in the production well, and the injected CO₂ dispersed, as depicted in Figure 18. This dispersion was not conducive to the formation of a large-scale CO₂ cap.

3.1.4. Reservoir Thickness

A thicker reservoir, on the other hand, led to increased CO₂ dissolution in crude oil, promoting miscibility and requiring a larger CO₂ injection volume to establish an effective CO₂ cap [26]. In a scenario where only the reservoir thickness was varied while keeping the CO₂ injection volume constant, when the reservoir thickness became excessively large, both the descent of the oil-water interface and the oil-gas interface was not substantial, as indicated in Figure 19, Figure 20 and Figure 21. When the reservoir thickness was smaller, injected CO₂ tended to disperse along the oil-gas interface, which hindered the gravity differentiation of oil and gas and the development of a CO₂ cap (Figure 22). These observations suggested that CAGD technology was particularly suitable for the anticlinal reservoirs with thicknesses ranging from 25 m to 50 m.

3.1.5. CO₂ Injection Rate

From Figure 23, Figure 24, Figure 25 and Figure 26, it was evident that as the CO₂ injection rate increased, the CO₂ cap development occurred more rapidly, resulting in a wider lateral sweep range and a more pronounced effect on the recovery of residual oil at the top. However, when the CO₂ injection rate was excessively high, it could lead to CO₂ breakthrough downward, diminishing the lateral sweep efficiency [27]. Conversely, when the CO₂ injection rate was too low, it prolonged the development of the CO₂ cap, which could impact cost-effectiveness. Therefore, optimizing the CO₂ injection rate was crucial in practical oil field development.

4. Application of CAGD

4.1. Filed Application

Well Pattern Conformation of CAGD

The initial well pattern involved injecting CO₂ at the top of the anticline structure and providing supplementary CO₂ injection and oil production at the waist of the anticline structure. During the formation of gravity differentiation at the top, the production well was shut in, and the boundary between oil and gas, driven by CO₂, moved downward. Subsequently, the production wells at the waist of the anticline structure were restarted, while continuously replenishing CO₂. Therefore, T1, T2, and T3 were chosen as CO₂ injection wells, while the remaining wells were designated as production wells (Figure 27).

4.2. Optimization of Injection-Production Parameters

4.2.1. Optimization of CO₂ Injection Mode

Utilizing three wells, T1, T2, and T3, continuous CO₂ injection and intermittent CO₂ injection (inject 4 months; stop for 2 months) were performed separately. Both injection schemes maintained an equal total injection volume of 6.48 × 10⁸ m³. The simulation was conducted to predict the performance over a period of ten years. By comparing the CO₂ sweep range demonstrated by the two injection methods, findings were made that intermittent CO₂ injection was more conducive to the effective utilization of gravity differentiation and resulted in better lateral sweep range (Figure 28). This was because the soaking period of intermittent CO₂ injection was the optimal period for molecular diffusion, and when a large number of gas molecules enter a high-temperature and high-pressure reservoir environment, intense diffusion occurs, resulting in significant expansion energy [28]. In contrast, continuous CO₂ injection could lead to rapid gas migration towards the reservoir bottom, diminishing its effectiveness in lateral sweep range.

4.2.2. Optimization of CO₂ Injection Rate

From the analysis of influencing factors of CAGD in the previous sections, it was evident that optimizing CO₂ injection rate was crucial when CAGD technology applied in actual reservoirs. If the CO₂ injection rate was too high, the occurrence of displacement CO₂ fingering would be accelerated, and the CO₂ would breakthrough prematurely so as to reduce the effect of CO₂ injection [29]. Conversely, if the CO₂ injection rate was too low, the effective period of CO₂ injection would be prolonged and the economic benefit would be affected.

Table 4. Cumulative oil production and oil exchange rate at different CO₂ injection rates.

Gas Injection Rate (m3/d)	Cumulative Oil Production (104 t)	Oil Exchange Rate (t/m3)
50,000	200.264	0.091
70,000	220.625	0.080
90,000	232.185	0.073
110,000	198.717	0.055

and Figure 29 show that the cumulative oil production increased with the increase in CO₂ injection rate, and the oil exchange rate decreased with the decrease in CO₂ injection rate, but when the CO₂ injection rate was greater than 90,000 m³/d, the cumulative oil production decreased gradually and the oil exchange rate decreased. The CO₂ injection rate affected the stability of the gas-oil interface. Considering the cumulative oil production and oil exchange rate, the CO₂ injection rate adopted in the present study was 90,000 m³/d.

4.2.3. Optimization of Injection-Production Ratio

In

Table 5. Cumulative oil production under different I-P ratios.

I-P Ratio	Cumulative Oil Production (104 t)
0.7	207.064
0.8	214.269
0.9	224.357
1.0	232.185
1.1	235.185

and Figure 30, an observation could be made that as the injection-production ratio (I-P ratio) increased, the cumulative oil production increased. However, the upward trend in cumulative oil production slowed when the I-P ratio exceeded 1.0. Additionally, when the I-P ratio became too high, it led to an increase in CO₂ injection costs, which could have a negative impact on economic returns. Therefore, opting for an I-P ratio of 1.0, the simulation predicts a cumulative oil production of 232.185 × 10⁴ t after ten years.

4.3. Supplementary CO₂ Injection

In the case of A Oilfield, following the CO₂ injection until June 2024, the upward trend in cumulative crude oil production showed a noticeable slowdown. The two production wells, T4 and T5, situated in the anticlinal structure of the mid-section, were converted into CO₂ injection wells with a gradual CO₂ supplementation rate of 50,000 m³/d. Additionally, the production wells continued to operate with a I-P ratio of 1.0. As indicated in Figure 31, after implementing supplementary CO₂ injection in A Oilfield, cumulative oil production increased by 5.5 × 10⁴ t, accompanied by an obvious improvement in oil recovery.

4.4. Optimization Result

4.4.1. Enhancing Oil Recovery

According to the optimization result of injection-production parameters, the development plan for CAGD in A Oilfield was determined as follows:

In the initial stage, three CO₂ injection wells located at the top of the anticlinal structure were used at an injection rate of 90,000 m³/d for intermittent injection, and the production wells were operated under the condition of an I-P ratio of 1.0. Once the oil-gas interface stabilized, two gas injection wells at the midsection of the anticlinal structure were used with an injection rate of 50,000 m³/d, in conjunction with the three top gas injection wells, for intermittent gas supplementation.

As shown in Figure 32 and Figure 33, the implementation of CAGD led to a substantial decrease in water cut and an increase in cumulative oil production. Compared to the scenario where CAGD was not employed, implementing CAGD resulted in effects whereby the water cut decreased by approximately 10%, the cumulative oil production increased by 15.76 × 10⁴ t, the sweep range expanded, and a favorable oil recovery was obtained.

4.4.2. CO₂ Storage

From Figure 34, an observation could be made that using the CAGD method, a significant amount of CO₂ remained within the reservoir. In this scheme, a total of 84 × 10⁶ m³ of CO₂ was injected, and the total gas production from the oil field amounted to 1.85 × 10⁶ m³. Considering that the produced gas from the production wells consisted of not only CO₂ that had undergone miscible with the crude oil but also dissolved gases from the crude oil, it could be reasonably inferred that after ten years of implementation, a substantial amount of CO₂ gas still accumulates at the top of the reservoir (Figure 35), with at least 82.15 × 10⁶ m³ of CO₂ effectively sequestered in the reservoir. This signified a storage rate exceeding 90%, indicating highly effective CO₂ storage.

5. Conclusions

In this study, the challenges of extracting residual oil in high water cut reservoirs with bottom water during development were addressed, and a CAGD technique was proposed. The oil displacement and CO₂ storage mechanisms in CAGD were also explored. By establishing mechanistic models, the influencing factors of CAGD in oil reservoirs with bottom water were analyzed and investigated. The proposed technology was applied to an actual reservoir for simulation and optimization of the development program, resulting in the following conclusions and insights:

• Reservoir structure, CO₂ injection site, initial formation pressure, reservoir thickness, and CO₂ injection rate were all significant factors that affected the effect of CAGD in oil reservoirs with bottom water. When there was an anticline in the reservoir, it was easier for CO₂ to accumulate in the top to form a CO₂ cap. In the context of CO₂ injection, combining CO₂ injection at both the top and waist regions achieved effective gravity differentiation in the shortest time while considering lateral sweep effects. When only top CO₂ injection was employed, the lateral sweep effect was poor, and waist CO₂ injection prolonged the gravity differentiation period. When the initial formation pressure was greater than the minimum miscible pressure, CO₂ was prone to undergo miscible with the crude oil. This not only enhanced oil recovery but also improved the storage efficiency of CO₂. In cases where the reservoir thickness was greater, achieving gravity differentiation became more challenging. Conversely, in reservoirs with insufficient reservoir thickness, CO₂ spread rapidly. Moreover, as the CO₂ injection rate increased, the CO₂ sweep range gradually expanded. However, excessive CO₂ injection rate could lead to CO₂ breakthrough downward, thereby diminishing the effectiveness of lateral sweep.
• The application of the CAGD technique in extracting high position remaining oil in high water cut anticline reservoirs with bottom water was simulated using tNavigator software (V22.1) over a ten-year development period. After a decade of development, there was a significant reduction in water cut and the previously challenging-to-produce high position residual oil was effectively mobilized. The cumulative oil production in the A oilfield reached 23.74 × 10⁴ t, with a reduction in water cut of approximately 10%. Additionally, the CO₂ storage effect was quite favorable, with a storage volume of approximately 82.15 × 10⁶ m³.
• This paper investigated the influencing factors of CAGD and applied it to practical reservoirs, achieving favorable results. It provided theoretical and methodological guidance for implementing CAGD in similar reservoirs and also offered directions for researching CAGD technology in other types of reservoirs.