A Study on the Plugging Effect of Different Plugging Agent Combinations during CO₂ Flooding in Heterogeneous Reservoirs

Abstract

Gas channeling control is key to improving CO₂-flooding efficiency. A traditional plugging system has disadvantages, such as poor adaptability and stability, leading to the poor plugging effect of CO₂ channeling in heterogeneous reservoirs and difficulty in controlling the subsequent CO₂ injection pressure. To achieve a significant plugging effect and effectively control the subsequent CO₂ injection pressure, a heterogeneous physical model of gas channeling in a horizontal well was established, and plugging experiments were conducted using four different combinations of plugging agents during CO₂ flooding. Three evaluation parameters were defined, including the temperature field variation coefficient (TFVC), medium-permeability diversion rate (MPDR), and subsequent injection pressure coefficient (SIPC). The plugging effect of different combinations of plugging agents during CO₂ flooding in heterogeneous reservoirs was analyzed. The results show that the plugging effect after using a combination of plugging agents was significantly better than after using a single plugging agent, and different plugging agent combinations had distinct characteristics. The strong–medium–weak (S-M-W) combination had the best MPDR for subsequent CO₂ flooding, but the SIPC was the highest. The strong–weak–strong–weak (S-W-S-W) and weak–strong–weak–strong (W-S-W-S) combinations could effectively control the SIPC. These results indicate that plugging using the S-W-S-W and W-S-W-S combinations can achieve an effective plugging effect and reasonably control the subsequent CO₂ injection pressure. This work provides a personalized design scheme for effective gas channeling control and maintenance of appropriate injection pressure during CO₂ flooding in heterogeneous reservoirs.

1. Introduction

In recent years, ultra-low-permeability reservoirs have been developed rapidly, and the proportion of oil production in ultra-low-permeability oilfields has increased. However, due to complex diagenesis and geological structures, the heterogeneity of ultra-low-permeability reservoirs is strong, which greatly increases the difficulty of reservoir development [1,2,3,4,5]. Ultra-low-permeability reservoirs with low porosity, low permeability, and strong heterogeneity are developed to address conventional water flooding, which often faces difficulty in water injection and has a low production capacity [6,7,8,9,10]. The existing research results show that compared to traditional water flooding, CO₂ has a better ability to enhance oil recovery in ultra-low-permeability reservoirs because of its unique properties. CO₂ can increase sweep efficiency and effectively starts crude oil that has not been displaced during water flooding [11,12,13,14]. Moreover, a large amount of CO₂ can be effectively stored in reservoirs during CO₂ flooding [15,16,17]. During CO₂ flooding, gas channeling is prone to occur due to gas slippage, viscous fingering, and reservoir heterogeneity, especially when channeling through large pores and the high-permeability layer [18,19,20,21]. The early breakthrough of CO₂ injection could lead to most of the reservoir not being swept, which makes it difficult to achieve the expected development effect. Therefore, effective plugging treatment must be carried out after gas channeling during CO₂ flooding [22,23,24,25].

Viscous fingering in the matrix and crossflow in the fractures are the main factors causing gas channeling. Conventional methods for gas channeling control include alternating water and gas injection [26] and foam plugging control [27], among others. However, these methods all have certain limitations. For example, alternating water and gas injection exhibits a certain selectivity for reservoir permeability, and it is almost ineffective in tight reservoirs with fracture permeability much higher than the matrix [28,29]. Foam has a high viscosity and a strong “Jamin effect”, but the low strength and poor stability of foam restrict its use in high permeability fractures [27,30]. The two-stage gel channeling plugging system provides a novel idea for effectively plugging viscous fingering and fractures. The essence of this channeling plugging system is a slug combination of starch gel and ethylenediamine. High-strength starch gel is used to effectively plug the fractures, and high-viscosity organic amine salt generated by the chemical reaction of ethylenediamine and CO₂ is used to effectively plug the high-permeability layer [31,32,33]. However, this multi-level plugging system does not take into account the impact of plugging on subsequent gas injection pressure. For the development of ultra-low-permeability reservoirs, the gas injection pressure decreases with an increase in the gas injection cycle, wherein, it remains at a relatively high level with an average value of around 15 MPa. The research shows that gas injection pressure is an important factor affecting oil recovery and gas injection cost [34,35,36,37]. The commonly used plug systems are a single plugging agent and a combination method that matches the pressure gradient, but the impact of plugging on subsequent CO₂ injection pressure has not been considered. Therefore, it is necessary to consider the effect of plugging on gas injection pressure.

In this work, the plugging effect of four combinations of plugging agents in a heterogeneous reservoir during CO₂ flooding was investigated, including a single plugging agent (S-A), a strong–medium–weak (S-M-W) combination, a strong–weak–strong–weak (S-W-S-W) combination, and a weak–strong–weak–strong (W-S-W-S) combination. Two kinds of plugging agent systems were initially selected as the materials for the plugging agent combinations. Using a physical model of gas channeling in a horizontal well, the plugging effect of these four plugging agent combinations was evaluated based on the temperature field variation coefficient (TFVC), the medium-permeability diversion rate (MPDR), and the subsequent injection pressure coefficient (SIPC). This study provides reference and guidance for the personalized design of plugging agent combinations for gas channeling during CO₂ flooding in ultra-low-permeability reservoirs.

2. Materials and Methods

2.1. Experimental Materials

The experimental materials included a thermosetting resin plugging agent (plugging strength of 17–38 MPa/m; laboratory owned, code A), polymerization monomers (plugging strength of 8.3–14.6 MPa/m; Green Source Chemical Co., Ltd., Beijing, China, code B), a cationic gel (plugging strength 6.8–12.4 MPa/m, Shengli Chemical Co., Ltd., Beijing, China, code C), and a composite nano plugging system (plugging strength of 12.3–22.6 MPa/m, Tianjin Yijie Chemical Co., Ltd., Hebei, China, code D). The viscosity of the formation crude oil was 37.87 mPa·s, and the density was 0.8991 g/cm³. The type of formation water was NaHCO₃, and the salinity was 2215 mg/L. Heterogeneous models were prepared using quartz sand with different mesh sizes (180 mesh, 120 mesh, and 60 mesh), which was unconsolidated. Figure 1 shows a schematic diagram of the three-dimensional heterogeneous core model. Along the horizontal well section, from target A to target B, the sequence was high permeability, medium permeability, and low permeability. The volume ratio of each part was 1:1:1, and the permeability of the heterogeneous rock cores was 1500 mD, 800 mD, and 300 mD.

2.2. Experimental Methods

(1)

Model establishment

A three-dimensional physical simulation of the gas channeling device for horizontal wells was established according to the principle of size similarity (Figure 2). The model with the size of 40 cm × 40 cm × 4 cm was equipped with 13 temperature and pressure sensors to monitor changes in temperature and pressure. At one end of the model, a steel pipe with a length of 30 cm, an inner diameter of 0.4 cm, and a uniform small hole were used to simulate gas injection at target A of the horizontal well. The disturbed horizontal well was simulated at the other end of the model by designing eight outlet flow measurements;

(2)

Experimental procedure

First, the prepared model was saturated with simulated formation water at 3 mL/min. The simulated crude oil was injected into the model at the same rate, and the pressure measuring point was used as the injection point for saturated crude oil. Subsequently, after aging at 80 °C for 48 h, CO₂ was injected at 7 mL/min, and a back pressure of 0.4 MPa was applied to the model. The changes in temperature and pressure with time were recorded. When the value of the gas flowmeter at the outlet increased, and the injection pressure was stable, the injection was stopped. Then, different combinations of plugging agents were injected into the physical model at 3 mL/min, and the plugging system was gelatinized after aging. Finally, CO₂ was injected into the model again. The temperature and injection pressure before and after the plugging treatment were recorded during the experiment. The injection volume of the plugging system was 0.3 pore volume (PV).

3. Experimental Results

3.1. Changes in Pressure and Temperature during CO₂ Flooding before Plugging

According to the experimental procedure, CO₂ was injected into the heterogeneous model. The changes in the temperature field and pressure field with time were recorded, and the results are shown in Figure 3 and Figure 4, respectively.

As shown in Figure 3, with an increase in CO₂ injection time, the temperature in the high-permeability zone changes first (1–3 h). Then, the temperature in the medium-permeability zone changes (4–6 h), and finally, the temperature in the low-permeability zone changes (7–8 h). The temperature change in the high-permeability zone is significantly greater than that in the low-permeability zone. This indicates that CO₂ mainly crossflows in the medium- and high-permeability zones. It can be seen from Figure 4 that the changes in pressure are mainly concentrated in the high- and medium-permeability zones, while there is no significant change in pressure in the low-permeability zone. The pressure does not change much after 4 h of CO₂ injection, indicating that the pressure field tends to stabilize. This also reflects that the pressure conduction velocity is much greater than the temperature conduction velocity.

3.2. Changes in Pressure and Temperature during CO₂ Flooding after Plugging with Different Combinations

(1)

Single Agent (S-A)

A single plugging agent can mitigate gas channeling to a certain extent and exert a certain plugging effect. The plugging effect of the code C system was investigated in this work. CO₂ was injected into the heterogeneous model for 8 h, and 0.3 PV of the code C system with a concentration of 50 wt% was injected. After aging for 4 h, CO₂ was injected again. The changes in temperature and pressure were observed during CO₂ flooding after plugging with this system, and the results are shown in Figure 5 and Figure 6, respectively.

As shown in Figure 5, there is a significant difference in the temperature field during CO₂ flooding before and after plugging with a single agent. Before plugging, the areas showing significant temperature changes are the medium-and high-permeability zones. After plugging, the areas showing significant temperature changes are the medium- and low-permeability zones. With an increase in CO₂ injection time, the temperature change amplitude increases, reaching a maximum of 8 °C. There is little temperature change in the middle of the high-permeability zone and the lower part of the medium- and low-permeability zones, indicating that these areas are plugged by the code C system. The subsequently injected CO₂ flows around and cannot transfer heat to these zones. The temperature in the middle and upper parts of the medium- and low-permeability zones significantly changes with an increase in CO₂ volume, which indicates these areas are affected by CO₂ flooding. As shown in Figure 6, the pressure field related to the injection pressure after plugging is higher than before, which indirectly reflects the effectiveness of plugging. Due to the simulation of gas injection at target A in the horizontal well section, the flow rate at target A is the fastest. The temperature change at target A is the most significant after plugging. The strength of the injected single agent is not sufficient to completely plug the area of target A;

(2)

Strong–Medium–Weak Combination (S-M-W)

A single plugging agent exerts a certain plugging effect. However, it cannot meet the dual requirements of temperature and pressure at the same time, which limits its plugging effect. The combination of plugging agents was further investigated. The most commonly used combination method is strong–medium–weak (S-M-W), which matches the formation pressure gradient. The further away from the wellhead, the weaker the strength of a plugging agent. In this study, this combination included 100 wt% code B, 50 wt% code C, and 25 wt% code C, and the volume ratio of each component was 3:4:3. CO₂ was injected again after plugging with the S-M-W combination. The changes in temperature and pressure fields were recorded, and the results are shown in Figure 7 and Figure 8, respectively.

As shown in Figure 7, the temperature field during CO₂ injection after plugging with the S-M-W combination changes significantly, especially in the medium- and low-permeability zones. The temperature gradually shifts from the high-permeability zone to the medium- and low-permeability zones with increasing CO₂ injection time. Due to the plugging effect of the S-M-W combination, the temperature of the high-permeability zone does not change much. This indicates that the S-M-W combination exerts a good plugging effect in the high-permeability zone so that the subsequently injected CO₂ sweeps to the medium- and low-permeability zones. As shown in Figure 8, the CO₂ injection pressure after plugging with the S-M-W combination is significantly higher than before plugging, reflecting the significant plugging effect of the S-M-W combination;

(3)

Strong–Weak–Strong–Weak Combination (S-W-S-W)

Some oil reservoirs are deeply buried and have poor physical properties. After several cycles of CO₂ injection, the injection pressure is still high. Therefore, it is necessary to develop a combination method that can effectively plug gas channeling and control the subsequent injection pressure. The strong–weak–strong–weak (S-W-S-W) and weak–strong–weak–strong (W-S-W-S) combinations were designed. An advantage of these two combination methods is that the strong slug can change the flow direction of CO₂ and increase the CO₂ sweep volume. A weak slug can regulate the formation heterogeneity, and CO₂ can flow simultaneously in high- and low-permeability zones, which reduces the subsequent CO₂ injection pressure. The S-W-S-W combination included 100 wt% code B, 25 wt% code C, 100 wt% code B, and 25 wt% code C, and the volume ratio of each component was 3:2:2:3. CO₂ was injected again after plugging with S-W-S-W combination. The changes in temperature and pressure fields were recorded, and the results are shown in Figure 9 and Figure 10, respectively.

As shown in Figure 9, the temperature field during CO₂ injection changes significantly after plugging with the S-W-S-W combination. The temperature of the medium- and low-permeability zones changes significantly with increasing CO₂ injection time, indicating that these areas are affected by CO₂ injection. Due to the plugging effect of the S-W-S-W combination, the temperature of the high-permeability zone does not change much. This result indicates that the S-W-S-W combination exerts a good plugging effect in the high-permeability zone so that the subsequently injected CO₂ could sweep to the medium- and low-permeability zones. As shown in Figure 10, the CO₂ injection pressure after plugging with the S-W-S-W combination is significantly higher than before plugging, thus showing a significant plugging effect. The changes in temperature and pressure fields during CO₂ injection after plugging with the S-W-S-W combination are similar to those after plugging with the S-M-W combination;

(4)

Weak–Strong–Weak–Strong (W-S-W-S) Combination

The W-S-W-S combination included 25 wt% code C, 100 wt% code B, 25 wt% code C, and 100 wt% code B, and the volume ratio of each component was 2:3:3:2. CO₂ was injected again after plugging with the W-S-W-S combination. The changes in temperature and pressure fields were recorded, and the results are shown in Figure 11 and Figure 12, respectively.

As shown in Figure 11, there is a significant difference in the temperature field during CO₂ injection before and after plugging with the W-S-W-S combination. The temperature changes in the lower part of the high-permeability zone and the medium- and low-permeability zones are obvious, which indicates that the W-S-W-S combination exerts a certain plugging effect. As shown in Figure 12, the pressure after plugging is significantly greater than before plugging. However, the plug strength closest to the wellhead is a weak slug, which cannot completely plug the high-permeability zone. The temperature changes significantly in the middle and lower parts of the high-permeability zone. There are significant differences in the temperature and pressure fields during CO₂ injection after plugging with the W-S-W-S combination compared to the results after plugging with the S-W-S-W or S-M-W combinations.

4. Evaluation of the Plugging Effect of the Four Combinations

During CO₂ injection, temperature and pressure are the two most significant parameters. At the same time, the location of CO₂ channeling is measured using a multi-point flow measurement method. The outlet is connected with the high-, medium-, and low-permeability zones. The degree of crude oil utilization in different permeability zones is characterized by observing the changes in flow rates at each outlet. In this study, there was no fluid outflow observed at the outlet of the low-permeability zone. The outlet of the high-permeability zone had fluid flowing out during CO₂ injection before and after plugging. The outlet of the medium-permeability zone only had fluid flowing out during CO₂ injection after plugging. Therefore, the medium-permeability outlet’s flow rate was used to reflect the plugging effect.

Three parameters were used to represent the changes in temperature, the changes in pressure, and the changes in diversion rates in different permeability zones before and after plugging. The temperature field variation coefficient (TFVC) is defined as the ratio of the product of the temperature value in the middle- and low-permeability zones and the square measure contained in this temperature during CO₂ injection before and after plugging with different combinations. The calculation of the TFVC is shown in Formula (1). This parameter characterizes the influence of the plugging effect of different combinations on the temperature field during CO₂ injection as follows

$$\mathrm{TFVC}=\frac{T_1\times S_1}{T_0\times S_0}$$

(1)

where TFVC is the temperature field variation coefficient (dimensionless); T₁ is the temperature during CO₂ injection after plugging with different combinations (°C); S₁ is the square measure contained in this temperature during CO₂ injection after plugging by different combinations (cm²); T₀ is the temperature during CO₂ injection before plugging (°C); and S₀ is the square measure contained in this temperature during CO₂ injection before plugging (cm²).

The subsequent injection pressure coefficient (SIPC) is defined as the ratio of the stable pressure difference of CO₂ injection after plugging with different combinations to the stable pressure difference of CO₂ injection before plugging. The SIPC characterizes the effect of plugging with different combinations on the subsequent CO₂ injection pressure.

The medium-permeability diversion rate (MPDR) is defined as the proportion of the flow rate in the medium-permeability zone to the total flow rate after plugging with different combinations. It is calculated using the flow rate at the outlet section of the medium-permeability zone to characterize the start-up situation of the medium- and low-permeability zones after plugging with different combinations. The TFVC, SIPC, and MPDR of different combinations of plugging were calculated, and the results are shown in Figure 13.

As shown in Figure 13a, the temperature field variation coefficient (TFVC) gradually increases with increasing CO₂ injection time, and the TFVC after plugging with different combinations is larger than that after plugging with the single plugging agent. The result indicates that the plugging effect is remarkable, and the CO₂ sweep volume is improved after plugging with different combinations. The TFVC after plugging with the S-W-S-W combination is the highest, followed by the S-M-W and W-S-W-S combinations. After plugging with the S-W-S-W combination, the CO₂ sweep volume is improved the most, which can maximize oil recovery.

As shown in Figure 13b, the medium-permeability diversion rate (MPDR) first rapidly increases and then decreases to a stable state with increasing CO₂ injection time. The MPDR after plugging with the single plugging agent is the lowest, showing that the utilization degree of crude oil in the middle-permeability zone is the smallest after a single plugging agent blocks the channel. The MPDR after plugging with the S-W-S-W combination is similar to the MPDR after plugging with the S-M-W combination, which is higher than that after plugging with the W-S-W-S combination. The change process of the medium-permeability diversion rate (MPDR) is divided into three stages. In the first stage, as the CO₂ injection volume increases, the diversion rate of the high-permeability zone decreases sharply, while the diversion rate of the medium-permeability zone increases. This is due to the fact that the high-permeability zone is plugged with different combinations. In the second stage, the crude oil in the medium- and low-permeability zones is displaced during CO₂ flooding after plugging the high-permeability zone. Compared to the medium-permeability zone, the flow resistance in the low-permeability zone is greater, so the MPDR remains stable at higher parts. The MPDR can reflect the plugging effect of different combinations. A larger MPDR and a longer stability time indicate a more significant plugging effect. In the third stage, as the CO₂ injection further increases, the CO₂ front edge bypasses the plugging zone and flows again in the high-permeability zone. At this time, the diversion rate in the high-permeability zone gradually increases, and the diversion rate in the medium-permeability zone decreases.

As shown in Figure 13c, the subsequent injection pressure coefficient (SIPC) after plugging with the single agent is smaller than that after plugging with different combinations. The SIPC after plugging with the S-M-W combination is the highest, indicating that the (S-M-W) combination has the strongest plugging ability. The subsequent injection pressure after plugging with the single agent is the highest. The SIPC after plugging with the S-W-S-W combination is greater than that after plugging with the W-S-W-S combination, and both values are smaller than after plugging with the S-M-W combination. After plugging with the S-W-S-W and W-S-W-S combinations, the subsequent CO₂ injection pressure can be effectively controlled to ensure the smooth progress of the on-site operation. Based on the comprehensive evaluation of these three parameters, the results of the plugging effect of different combinations are shown in

Table 1. Comparison of parameters after plugging with different combinations.

Combination Method	TFVC	SIPC	MPDR
S-A	2.5	1.06	26.53
S-M-W	3.7	1.47	57.88
S-W-S-W	3.2	1.34	53.91
W-S-W-S	3.1	1.13	39.7

.

It can be seen from Table 1 that the TFVC, SIPC, and MPDR after plugging with the single agent are the smallest. This indicates that the plugging effect of the single plugging agent is the worst. The TFVC, SIPC, and MPDR after plugging with the S-M-W combination are the highest. The S-M-W combination has the greatest plugging strength, but the subsequent CO₂ injection pressure after plugging with this combination is also the highest. The parameter values after plugging with the S-W-S-W and W-S-W-S combinations are between the values after plugging with the single plugging agent and the S-M-W combination. This indicates that the S-W-S-W and W-S-W-S combinations are beneficial for controlling the subsequent gas injection pressure while effectively plugging gas channeling.

Gas channeling control is to plug the gas channeling channel, which causes CO₂ to flow to the medium- and low-permeability zones and improves the sweep volume of CO₂. This requires that the permeability of the CO₂ channeling channel after plugging should be lower than that of the low-permeability zone. The change in permeability after plugging can be effectively controlled by controlling the strength of the plugging agent. For the S-M-W combination, the channel permeability plugged by the high-strength slug is lower than that of the low-permeability zone. The channel permeability plugged by the medium and low slugs is lower than that of the medium-permeability zone. For the S-W-S-W combination, the channel permeability plugged by the first high-strength slug is lower than that of the low-permeability zone. The channel permeability plugged by the first low-strength slug is greater than that of the medium-permeability zone. The channel permeability plugged by the second high-strength slug is lower than that of the medium-permeability zone. The channel permeability adjusted by the second low-strength slug is greater than that of the medium-permeability zone. The S-W-S-W combination can achieve an effective plugging effect and reasonably control the subsequent CO₂ injection pressure. CO₂ flows to the middle- and low-permeability zones, and the crude oil in the middle- and low-permeability zones is produced to improve the oil recovery of the reservoir.

5. Conclusions

In this study, a three-dimensional physical model of CO₂ gas channeling in a horizontal well was established. Plugging experiments with different combinations were carried out, and three evaluation parameters were defined and analyzed. The main conclusions are as follows:

(1) The three parameters, namely, the temperature field variation coefficient (TFVC), the subsequent injection pressure coefficient (SIPC), and the medium-permeability diversion rate (MPDR) were defined to provide theoretical support for the subsequent evaluation effectiveness of CO₂ flooding after plugging;

(2) The significant changes in TFVC, SIPC, and MPDR of the model before and after plugging indicate that different combinations of plugging agents can improve the sweep volume of CO₂. The TFVC, SIPC, and MPDR after plugging with a single agent are the smallest, and those after plugging with the S-M-W combination are the highest. This shows that the plugging effect of the single plugging agent is the worst, while the plugging effect of the S-M-W combination is the most significant, and the subsequent CO₂ injection pressure is also the highest;

(3) The parameter values after plugging with the S-W-S-W and W-S-W-S combinations are between the values after plugging with the single plugging agent and the S-M-W combination. This indicates that the S-W-S-W and W-S-W-S combinations are beneficial for controlling the subsequent gas injection pressure while effectively plugging gas channeling;

(4) The types of oil reservoirs are complex and variable. In order to further improve the effectiveness of CO₂ flooding in different types of oil reservoirs, in-depth research is needed to select more targeted combination methods to adapt to different types of oil reservoirs.