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Article

Evaluation of Temperature- and Salt-Resistant Foam Acid and Study of Foam Diversion Mechanism

by
Xiangsong Hu
1,
Hui Ma
1,*,
Ya Xu
1,
Fuhua Chang
1,
Jiabao Fan
2,3 and
Chao Zhang
2,3,*
1
No. 2 Oil Production Plant, Jiangsu Oilfield Company, SINOPEC, Jinhu 225000, China
2
Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education, Qingdao 266580, China
3
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
*
Authors to whom correspondence should be addressed.
Processes 2025, 13(9), 2704; https://doi.org/10.3390/pr13092704
Submission received: 18 July 2025 / Revised: 18 August 2025 / Accepted: 19 August 2025 / Published: 25 August 2025
(This article belongs to the Section Chemical Processes and Systems)
Browse Figures
Versions Notes

Abstract

Foam acidification is often employed as a clean and efficient method to remove blockages from wells and promote oil and gas production. In order to effectively control the diffusion of H+ in the acid solution into the rock surface, reduce the acid–rock reaction rate, and achieve deep acidification, a foam-retarding acid with foam stability, temperature and salt resistance, and excellent retarding performance was prepared by studying the synergistic effect of the foaming agent and foam stabilizer. ZG-A was used as the foaming agent, and ZG-B was added as a foam stabilizer to achieve foam stabilization. When the ZG-A/ZG-B ratio was 0.67%/0.33%, the foam exhibited the best comprehensive performance. By measuring and comparing the acid–rock reaction rate under different conditions, the results showed that the average acid–rock reaction rate of the 10% compound acid was 1.412 × 10−3 mg/(cm2·s), while the average acid–rock reaction rate of the foam-retarding acid system was reduced to 6.622 × 10−5 mg/(cm2·s), representing a reduction of two orders of magnitude, and the slow rate reached 95.31%. Foam fluid diversion experiments were carried out on cores with different permeabilities. The results showed that the foam could increase the diversion flow rate of low-permeability cores and reduce the diversion flow rate of high-permeability cores. Thus, the foam fluid could be uniformly propelled in cores with different permeabilities. Based on this principle, foam acid acidification can increase the amount of acid injection into the low-permeability layer and reduce the amount of acid absorption in the high-permeability layer, thereby improving the acidification effect.

1. Introduction

During the development of the Jiangsu Oilfield, various issues have arisen, including hydration swelling, particle migration, solid plugging, and corrosion plugging in injection wells. These problems stem from the incompatibility between the injected fluid and the reservoir fluid and rock, as well as improper operational parameters, such as injection speed and intensity [1,2,3,4]. The findings demonstrate that matrix-acidizing technology efficiently dissolves the matrix framework and plugging materials, facilitating the formation of wormhole channels. This process enhances reservoir permeability, reduces reservoir injection pressure, and successfully accomplishes the objectives of pressure reduction and enhanced injection [2,5,6,7,8]. With multiple injections and acidification rounds, the following problems exist in the injection wells: the injection pressure increases, the amount of water injected decreases, the injection requirements cannot be met, the validity period of repeated acidification gradually decreases, and the average number of acidification cycles per year in a single well increases [9,10,11,12,13]. After the repeated acidification of the water injection wells, the acidification radius of the reservoir gradually increases, and it is necessary to use an acid solution with a longer penetration distance for deep plugging removal. Considering the characteristics of reservoir heterogeneity, it is necessary to improve the water absorption profile and achieve uniform acidification [14,15,16,17].
Acidizing plugging removal can effectively remove plugging components, improve the water absorption capacity of the reservoir, reduce the injection pressure, increase the amount of injected water, and ensure efficient development of the oilfield. Therefore, acidizing plugging removal is often adopted in oilfield water injection wells [18,19,20,21]. At present, conventional acidizing and small-scale fracturing are used to solve the problem of formation plugging in water injection wells in the Jiangsu Oilfield. In the process of plugging removal by conventional acid, the reaction speed between the acid and reservoir minerals is fast, and the effective action distance of the acid is short, which can improve the formation near the wellbore but cannot play a role in deep plugging removal [22,23,24,25]. In addition, conventional acidification is prone to the formation of secondary precipitates, leading to a reduced acidification effect or even negative effects. The use of small fracturing will lead to the expansion of formation fracture channels and accelerate the advance speed of the water flooding front, and the effect of the oil well increase in the region is not obvious. At the same time, it also leads to water channeling and flooding [26,27,28]. Therefore, the technology of deep acidification of oil and gas reservoirs using retarded deep-penetrating acids to increase production is of great practical significance for oilfield water injection development and reservoir protection.
Foam acidification technology mainly uses a foaming agent with good foaming and foam stabilization performance to mix with different acid fluids. The foam system formed by gas can effectively block high water cut reservoirs and improve the seepage resistance of fluids in high-permeability layers. Under the action of gas resistance, the foam acid fluid enters the low-permeability layer and reacts with the rock to develop a low-permeability reservoir [26,29,30,31,32]. The foam acid system is selected for acidification. The H+ in the foam acid system mainly moves and diffuses along the foam wall, which can effectively prolong the reaction time between the acid system and reservoir, expand the acidizing radius of the acid, and ultimately realize deep acidification [33,34,35]. Foam acidification technology is very effective for low-permeability, water-sensitive, and low-pressure reservoirs. Compared with conventional acidification technology, it has the advantages of high viscosity, strong flowback ability, small filtration loss, long acidification distance, low liquid column pressure, simple construction, and low cost [36,37,38,39]. At present, the numerical simulation of foam acidification technology mainly focuses on foam flow, acid–rock reaction, and its propagation characteristics in complex strata, aiming at optimizing foam formulation and operation scheme. Although many studies have been conducted to model the foam behavior and reaction process, accurate simulation under high temperature, high pressure, and high salinity environments still faces some challenges, which need to be further improved and verified. In this study, the optimal ratios of foaming agent ZG-A and foam stabilizer ZG-B were first screened by indoor foam foaming and foam stability experiments, and the foam performance of the foaming agent was investigated under high-temperature and high-mineralization conditions. Then, the average acid–rock reaction rate and retardation rate of the compound acid and foam acid were evaluated and characterized by core scanning electron microscopy. Finally, the mechanism of foam fluid diversion acidification was studied using a single-core plugging experiment and a foam replacement experiment of parallel cores with different permeabilities. In this study, the performance of foam fluid was examined in depth under high temperature and high salinity conditions by optimizing the ratio of foam agents, which filled the gap in the application of foam acidification technology under extreme conditions. At the same time, by comparing the rock reaction rates of composite acid and foam acid, analyzing core scanning electron microscope characterization, and conducting core plugging and foam displacement experiments, the diversion acidification mechanism of foam fluids was revealed. The research findings provide theoretical support for the optimization and application of foam acidification technology and offer important evidence for the improvement of acidification operations and foam displacement technology in oil and gas extraction.

2. Experimental Section

2.1. Experimental Materials

The gas used in the experiment was CO2 with a purity of 99.9 mol%, which was produced by Qingdao Tian Yuan Gas Co., Qingdao, China. The compound acid solution, foaming agent ZG-A, and foam stabilizer ZG-B used in the experiment were provided by the Jiangsu Oilfield of the China Petroleum & Chemical Corporation, Yangzhou, China. The formation water used in the experiment was prepared using NaCl and CaCl2; the mass ratio of the two was 1:1, and the total mineralization was 20,000 mg/L.

2.2. Preparation of the Foam Acid System

First, different mass fractions of the foaming agent ZG-A and foam stabilizer ZG-B were dissolved in deionized water or simulated formation water, and a 10–30% compound acid solution was added and stirred evenly to obtain a foam-acid-based solution. The total mass concentration of ZG-A and ZG-B was 1%, and their mass ratios were 1:1, 2:1, 3:1, and 4:1, respectively.

2.3. Foamability and Foam Stability Measurement

In this experiment, the Waring–Blender stirring method was used to determine parameters such as foam volume, stabilizing time, and foam composite index. The specific steps were as follows: at room temperature, 100 mL of the prepared foam-acid-based solution was poured into the measuring cup of the stirrer and stirred for 3 min at a stirring speed of 8000 r/min, and the generated foam was quickly poured into a 500 mL measuring cylinder. The initial foaming volume (Vmax) and the time of precipitating 50 mL of the liquid, that is, the half-life of the foam (t1/2), were calculated. The foam composite index is a parameter that characterizes the foam foaming volume and foam stabilizing capacity and is calculated as shown in Equation (1):
F C I = V max t 1 / 2
where FCI is the foam composite index (mL·min), Vmax is the foam volume (mL), and t1/2 is the foam drainage half-life (min).

2.4. Test of Temperature and Salt Resistance of the Foam Acid System

2.4.1. Salinity Resistance Test

In this test, different mass surfactants were fully dissolved in the prepared high-salinity simulated formation water. The formation water was prepared using NaCl and CaCl2; the mass ratio of the two was 1:1, and the total salinity was 20,000 mg/L. The foaming volume, foam stabilization time, and foam composite index of the foam were measured using the Waring–Blender stirring method described in Section 2.3.

2.4.2. Temperature Resistance Test

In this test, evaluation of foam temperature resistance was carried out according to the ‘SYT 7494-2020 experimental evaluation method of foaming agent for oil and gas fields’ [40]. The foaming agent and simulated formation water were mixed and added to the reactor chamber. CO2 was introduced to increase the internal pressure above the saturated vapor pressure at 150 °C, and the reactor was aged at 150 °C for 24 h. According to the Waring–Blender stirring method described in Section 2.3, the aging foaming agent solution was used to determine the foaming volume, foam stabilization time, and foam composite index of the foam to evaluate the salt resistance of the foam acid.

2.5. Retarding Performance Test of the Foam Acid System

The acid–rock reaction was evaluated using dynamic reaction rate testing methods. Using laboratory-provided rock samples, the acid solution was placed in the reaction tank of the rotating rock disk tester, with a volume of 3 mL per square centimeter of surface area of the rock samples, and the core dissolution rate of the foam acid was determined at 90 °C. The acid–rock reaction rate (Va), the average acid–rock reaction rate ( V a ¯ ), and the retarding rate (K) were calculated according to the National Energy Administration SY/T 6526-2019 standard [41], and the calculations are shown in Equations (2)–(4):
V a = Δ m 1000 ( S × Δ t )
where Δm is the dissolution mass of the rock sample (g), S is the total surface area of the rock sample (cm2), and Δt is the reaction time (s).
V a ¯ = ∑ i = 1 n V a i / n
where n is the number of experiments.
K = V 0 ¯ − V a ¯ V 0 ¯ × 100 %
where K is the retarding rate (%), V 0 ¯ is the average acid–rock reaction rate of the compound acid solution (mg(/cm2·s), and V a ¯ is the average acid–rock reaction rate of the foam acid solution (mg(/cm2·s).

2.6. Scanning Electron Microscopy Testing of Cores

The same core was cut into two pieces of core slices with a thickness of 10 mm and soaked in compound acid and foam acid for 15 min. Then, the core was removed, and the residual acid on the surface of the core was washed with distilled water. The surface morphology of the core slices was characterized by scanning electron microscopy (SEM, Zeiss SU 500, Oberkochen, Germany). The sample was sprayed with gold on the surface before the core test. The magnification of the core tested by the scanning electron microscope was 2000 times.

2.7. Experimental Study of Foam Diversion

2.7.1. Plugging Experiment of Foam in Single Core

The core was pumped into a vacuum and added to the core holder. The core holder was placed in a thermostat box to simulate formation water replacement at a rate of 5 mL/min. The initial injection pressure was 25 kPa, and the constant temperature was 60 °C. When the pressure stabilized, foam replacement was carried out with a foam liquid flow rate of 1.5 mL/min and a CO2 gas flow rate of 3 mL/min, and the injection pressure during foam replacement was measured. Then, the foam was replaced by simulated formation water, and the pressure change was measured.

2.7.2. Divided-Flow Experiment of Foam in Parallel Cores

Cores with different permeabilities were selected. The simulated formation water was filtered through a filter membrane and set aside, and a foaming agent was added to the intermediate container according to the process. Experiments were conducted on two parallel cores. The cores were replaced with simulated formation water at an injection rate of 4.5 mL/min, and the pressure and partial flow rate of each core were measured. CO2 gas at a certain pressure was added to the gas intermediate container, and the gas and foaming agent were pumped into the foam generator with a pump. The foaming agent was injected at a rate of 1.5 mL/min, CO2 gas was injected at a rate of 3.0 mL/min, the cores were replaced with foam, and the change in the replacement pressure as well as the partial flow rate of the foam liquid components at different times was recorded. When the replacement pressure stabilized, the core was replaced with simulated formation water, and the experimental pressure change was recorded. When the experimental pressure stabilized, the fractional flow rates of the different cores were recorded. The core parameters used in the experiments are presented in Table 1. The cores used in the experiment were homogeneous, with relatively uniform pore distribution.

3. Results and Discussion

3.1. Foamability and Foam Stability of the Foam Acid System

The foam properties of the separate foaming agent ZG-A were first tested, as shown in Figure 1. As the concentration of the foaming agent increased from 0.2% to 1.0%, the foaming volume gradually increased. The half-life of the foam precipitate did not change significantly and was maintained at approximately 7.5 min. With the increase in surfactant concentration, the adsorption of surfactant molecules at the gas–liquid interface gradually reached saturation, and the foam performance was not significantly improved when the concentration continued to increase. The foam performance of ZG-A alone must be improved, and it is necessary to investigate the performance of the foam system after ZG-A is compounded with a foam stabilizer.
Next, the foaming properties and foam stability of the binary compound system of foaming agent ZG-A and foam stabilizer ZG-B were tested. The total concentration of ZG-A and ZG-B was 1%, and their ratios were 0.5:0.5, 0.67:0.33, 0.75:0.25, and 0.8:0.2, respectively. To satisfy the requirements of acidizing construction in different reservoirs, the foaming performance of the foam-acid-based solution was tested for three different compound acid contents (10%, 20%, and 30%), and the results are shown in Figure 2. As shown in Figure 2a, the foaming performance of the three types of foam-acid-based liquids increased gradually with an increase in the proportion of ZG-A. When the ratio of ZG-A/ZG-B was 0.8/0.2, the foaming volume of base liquids with the addition of 10% and 20% compound acid reached the highest, at 415 mL; the foaming property of base liquids with the addition of 30% compound acid first increased and then tended to level off. This may be due to the reduction in surfactant adsorption at the gas–liquid interface as a result of adding too much acid [42,43,44,45,46]. In addition, it can be seen from Figure 2b that with an increase in the proportion of ZG-A, the foam drainage half-life of the three compound-acid-based liquids decreased. When the ratio of ZG-A/ZG-B was 0.8/0.2, the foam drainage half-lives of the three compound-acid-based liquids were the lowest at approximately 16 min.
Based on the above results, the relationship between the foam composite index of the three types of foam-acid-based liquids and the change in ZG-A/ZG-B was obtained, as shown in Figure 3. Overall, when the amount of compound acid increased from 10% to 30%, the foam composite index under the four ratios decreased. When ZG-A/ZG-B was 0.5/0.5, the foam comprehensive index of the three composite foam-acid-based liquids was the highest. However, when ZG-A/ZG-B was 0.5/0.5, the foaming volume of the compound-acid-based solution with an addition of 10% compound acid was only 240 mL. When ZG-A/ZG-B was 0.67/0.33, its foaming volume was 305 mL, and the half-life time was 53 min; the foam comprehensive performance was optimal at this ratio. Therefore, in order to reduce the cost and facilitate field application, the preferred ratio of foaming agent and foam stabilizer is 0.67% ZG-A and 0.33% ZG-B, and the amount of compound acid added is preferably 10%.

3.2. Temperature and Salt Resistance of the Foam Acid System

In the next step, the temperature resistance and salt resistance of the foam solution with a ratio of 0.67% ZG-A and 0.33% ZG-B were investigated, and the results are shown in Figure 4 and Figure 5. Compared with deionized water, the foam volume of the foam solution in the simulated formation water decreased by 30 mL. However, the precipitation half-life of the foam increased by 7.5 min, and the foam composite index did not change significantly. This indicates that the foam system exhibits excellent foam performance, even under high mineralization conditions (20,000 mg/L). When the mineralization increases appropriately, the salt ions can increase the viscosity of the foam liquid, and the foam half-life shows an increasing trend [39]. Figure 5 shows the foam properties of the 0.67% ZG-A + 0.33% ZG-B foam solution at room temperature and at 150 °C. After aging at 150 °C for 24 h, there was no obvious change in the foaming and stability of the solution, indicating that the foaming agent and foam stabilizer have good thermal stability at 150 °C. The experimental results show that the 0.67% ZG-A + 0.33% ZG-B foam solution has excellent temperature and salt resistance properties.

3.3. Retarding Performance of the Foam Acid System

The reaction rate between the acid and rock directly affects whether or not the acid can acidify deep formations. For conventional acid solutions, the reaction rates of acid and rock are faster, which will easily cause excessive dissolution near the wellhead and a significant decrease in the acid concentration in the deep formation, thus failing to achieve the purpose of deep acidization [47,48,49,50,51]. Therefore, it is crucial to experimentally test the dissolution rate of foam acids. The dissolution rate of foam acid on rock chips was tested when the content of compound acid was 10% and the ratio of ZG-A and ZG-B was 0.67/0.33 and compared with the conventional 10% compound acid system to calculate the retarding rate of the foam acid system. The results are presented in Table 2.
As shown in Table 2, the average acid–rock reaction rate of the compound-acid-based liquid with a mass fraction of 10% was 1.412 × 10−3 mg/(cm2·s), while the average acid–rock reaction rate decreased to 6.622 × 10−5 mg/(cm2·s) after the addition of foaming agent ZG-A and foam stabilizer ZG-B, with a retardation rate of 95.31%. The average acid–rock reaction rate decreased by two orders of magnitude, which indicates that the addition of foaming agent ZG-A and foam stabilizer ZG-B significantly improved the acid–liquid foam performance, effectively reduced the acid–rock reaction rate, and had a very good retardation effect.
Figure 6 shows scanning electron microscope (SEM) images of the cores after treatment with compound acid and foam acid. The image reveals a pore-like or worm-like structure, suggesting that acidification significantly enhances the core’s permeability. The proportion of dissolved pore volume in the rock matrix after acidification with compound acid is high, with significant dissolution observed in the skeleton [19,22], as indicated by the red dotted line in Figure 6b. Additionally, the foam acid creates a smaller pore structure compared to compound acid digestion, which helps preserve the supportive skeleton in the rock core, minimizing damage. This contributes to reducing reservoir damage and achieving uniform acidification.

3.4. Study of the Mechanism of Foam Fluid Divided Flow

3.4.1. Plugging Performance of Foam in Single Core

The foam is stable in water and unstable in oil. During acidification, the foam entering the water layer is more stable than that entering the oil layer. When the foam in the oil layer breaks (not all break), the viscosity of the foam acid decreases, which is beneficial for the continuous advancement of foam acid during the acidification process. In the process of acid discharge and production, the bottom-hole pressure can be used to discharge it from the ground, which is conducive to production. The foam that enters the water layer plays a blocking role in acid advancement. In oil production, water is blocked in the formation without a rapid increase in water content. The foam also exhibits shear-thinning characteristics. For high-permeability formations, the shear of rock to foam is weak, and the apparent viscosity of foam in a high-permeability formation is relatively higher than that in a low-permeability layer, which is beneficial to the forward movement of foam in the low-permeability layer, whereas the foam in the high-permeability layer tends to adhere to and block the pores of the formation [13,26,27,28]. When the foam flows through the large pores in the heterogeneous formation, the flow rate becomes faster and the pressure decreases; thus, the foam diameter becomes larger and the Jamin effect becomes more serious, which plays a role in blocking large pores and reducing acid loss [32,36,52,53]. In contrast, the foam acid in the small pores is squeezed owing to resistance, which makes the radius of the foam smaller, meaning it is easier to penetrate the formation. Hence, the foam plugging capability was measured by a single-core displacement experiment, as shown in Figure 7.
Figure 7 shows the pressure change curve from the single-core foam flooding experiment. It can be seen that the plugging ability was enhanced by the foam. With an increase in the foam injection volume, the injection pressure increased, the injection capacity decreased, and the plugging capacity of the foam injection volume increased. This indicates that the foam system formed effective plugging in the core, and the diversion capacity was gradually enhanced. From subsequent experiments on water replacement, it can be seen that the pressure at the time of water replacement was obviously smaller than the pressure at the time of foam replacement, but it also increased with time. When it increased to a certain extent, the pressure suddenly decreased, and there were regular fluctuations. Finally, it tended to be stable and maintained a low-pressure value.

3.4.2. Divided-Flow Performance of Foam in Parallel Cores

As shown in Figure 8, in the early stage of water replacement, the ratio of the high-permeability core and the low-permeability core was approximately 3.5:0.9. After foam injection, the flow rate of the high-permeability and low-permeability cores gradually tended to be close to 1:1, and sometimes the flow rate of the low-permeability core was greater than that of the high-permeability core. The partial flow rate at time 0, as shown in the figure, corresponds to the flow rate after pressure stabilization during the water injection phase. Subsequently, the flow rate curve of the foam injection stage was compared with that of the water injection stage. The alternating change in the flow rate was caused by unsteady seepage of the foam in the core, which indicated that the foam was continuously broken and regenerated in the core.

4. Conclusions

In this study, the foam properties of foaming agent ZG-A and foam stabilizer ZG-B were evaluated, and the foam acid system was formed by compounding the formula with compound acid. The foam properties under high salinity and high temperature conditions, as well as the retarding properties of the foam acid, were investigated. Finally, the diversion acidification mechanism of the foam fluid was studied. The following conclusions can be drawn from this study:
(1) First, the temperature- and salt-resistant foam acid system was screened through indoor experiments: the optimal ratio of foaming agent ZG-A and foam stabilizer ZG-B was 0.67%: 0.33%, the optimal dosage of the compound acid was 10%, and the performance of the foam acid system did not decrease significantly under the conditions of 20,000 mg/L mineralization and 150 °C.
(2) The addition of foaming agent ZG-A and foam stabilizer ZG-B not only improved the foam performance of the foam acid but also significantly reduced the acid–rock reaction rate of the foam acid. At 90 °C, the acid–rock reaction rate was reduced from 1.412 × 10−3 mg/(cm2·s) for the 10% compound acid to 6.622 × 10−5 mg/(cm2·s), representing a reduction by two orders of magnitude, and the retarding rate reached 95.31%. This can effectively delay the reaction between the rock and acid to achieve deep acidification.
(3) Scanning electron microscope images of the cores after the dissolution of compound acid and foam acid further proved the retardation and uniform acidification performance of the foam acid. After compound acid acidification, the volume ratio of dissolved pores in the rock matrix was high, and there was a large amount of dissolution in the skeleton. The foam acid had a smaller pore structure than the compound acid after acidification, which could retain the core support skeleton to the greatest extent and achieve uniform acidification.
(4) The results of the foam fluid diversion experiment showed that the foam could increase the flow rate of the low-permeability core and reduce the flow rate of the high-permeability core so that the foam fluid could be evenly pushed in the cores with different permeabilities. Based on this, foam acid acidification can increase the amount of acid injection in the low-permeability layer and reduce the amount of acid absorption in the high-permeability layer, thereby improving the acidification effect.

Author Contributions

X.H.: investigation, formal analysis, writing—original draft. H.M.: resources, project administration, investigation, funding acquisition, formal analysis. Y.X.: investigation, formal analysis. F.C.: methodology, investigation. J.F.: methodology, investigation. C.Z.: conceptualization, supervision, investigation, writing—review and editing. All authors have read and agreed to the published version of the manuscript.

Funding

This work was supported by the National Natural Science Foundation of China (52204068) and the Program for Scientific Research Innovation Team of Young Scholars in Colleges and Universities of Shandong Province (2022KJ067).

Acknowledgments

We are grateful to the Shandong Engineering Research Center of Carbon Dioxide Utilization and Storage for their assistance with our experimental research. The valuable comments made by the anonymous reviewers are also sincerely appreciated.

Conflicts of Interest

Author Xiangsong Hu, Hui Ma, Ya Xu, Fuhua Chang were employed by the company Jiangsu Oilfield Company. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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Processes 13 02704 g001
Figure 1. Foaming volume and half-life of foaming agent ZG-A at different concentrations at room temperature.
Figure 1. Foaming volume and half-life of foaming agent ZG-A at different concentrations at room temperature.
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Figure 2. Foaming volume (a) and half-life (b) of binary mixtures at different ratios at room temperature.
Figure 2. Foaming volume (a) and half-life (b) of binary mixtures at different ratios at room temperature.
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Figure 3. Foam composite index of binary mixtures with different ratios at room temperature.
Figure 3. Foam composite index of binary mixtures with different ratios at room temperature.
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Figure 4. Foam properties of the foam acid system in deionized water and simulated formation water.
Figure 4. Foam properties of the foam acid system in deionized water and simulated formation water.
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Figure 5. Foam properties of the foam acid system at room temperature and high-temperature conditions.
Figure 5. Foam properties of the foam acid system at room temperature and high-temperature conditions.
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Figure 6. SEM images of the core slices before acidification (a), after compound acidification (b), and after foam acidification (c).
Figure 6. SEM images of the core slices before acidification (a), after compound acidification (b), and after foam acidification (c).
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Figure 7. Pressure change of foam displacement and subsequent water displacement in a single core.
Figure 7. Pressure change of foam displacement and subsequent water displacement in a single core.
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Figure 8. Divided-flow flux of foam replacement test in parallel cores.
Figure 8. Divided-flow flux of foam replacement test in parallel cores.
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Table 1. Data of test core.
Table 1. Data of test core.
NumberLength/mmDiameter/mmHydrometric Permeability/μm2
1300252.100
2300250.705
Table 2. Average reaction rate and retarding rate under different reaction conditions.
Table 2. Average reaction rate and retarding rate under different reaction conditions.
Reaction ConditionRock Core Surface Area/cm2Rock Core Reaction Quality/mgAverage Reaction Rate ( V ¯ a )/mg/(cm2·s)Retarding Rate (K)/%
10% compound acid38.7832.501.412 × 10−3/
38.6933.01
38.1932.8
0.67% ZG-A + 0.33% ZG-B + 10% compound acid41.201.606.622 × 10−595.31
42.031.71
41.781.70
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Hu, X.; Ma, H.; Xu, Y.; Chang, F.; Fan, J.; Zhang, C. Evaluation of Temperature- and Salt-Resistant Foam Acid and Study of Foam Diversion Mechanism. Processes 2025, 13, 2704. https://doi.org/10.3390/pr13092704

AMA Style

Hu X, Ma H, Xu Y, Chang F, Fan J, Zhang C. Evaluation of Temperature- and Salt-Resistant Foam Acid and Study of Foam Diversion Mechanism. Processes. 2025; 13(9):2704. https://doi.org/10.3390/pr13092704

Chicago/Turabian Style

Hu, Xiangsong, Hui Ma, Ya Xu, Fuhua Chang, Jiabao Fan, and Chao Zhang. 2025. "Evaluation of Temperature- and Salt-Resistant Foam Acid and Study of Foam Diversion Mechanism" Processes 13, no. 9: 2704. https://doi.org/10.3390/pr13092704

APA Style

Hu, X., Ma, H., Xu, Y., Chang, F., Fan, J., & Zhang, C. (2025). Evaluation of Temperature- and Salt-Resistant Foam Acid and Study of Foam Diversion Mechanism. Processes, 13(9), 2704. https://doi.org/10.3390/pr13092704

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