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Article

Enhance Oil Recovery in Fracture-Cave Carbonate Reservoirs Using Zwitterion-Anionic Composite Surfactant System

by
Wei Peng
,
Qing You
*,
Xiaoqiang Liu
,
Bojie Zhou
,
Xingxing Ding
,
Yuechun Du
and
Liangfei Xiao
School of Energy Resources, China University of Geosciences, Beijing 100083, China
*
Author to whom correspondence should be addressed.
Energies 2025, 18(2), 383; https://doi.org/10.3390/en18020383
Submission received: 20 November 2024 / Revised: 6 January 2025 / Accepted: 15 January 2025 / Published: 17 January 2025
(This article belongs to the Section H: Geo-Energy)
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Abstract

:
The carbonate fracture-cave reservoir in the Tahe oilfield, China, encounters development challenges because of its substantial burial depth (exceeding 5000 m). Its characteristics are low permeability, pronounced heterogeneity, extensive karst cavern systems, diverse connection configurations, and intricate spatial distribution. Prolonged conventional water flooding leads to predominant water channels, resulting in water channeling and limited sweep efficiency. Surfactant flooding is usually adopted in these conditions because it can mitigate water channeling and enhance sweep efficiency by lowering the interfacial tension (it refers to the force that is generated due to the unbalanced molecular attraction on the liquid surface layer and causes the liquid surface to contract) between oil and water. Nonetheless, the Tahe oilfield is a carbonate reservoir where surfactant is prone to loss near the well, thereby limiting its application. High-pressure injection flooding technology is an innovative method that utilizes injection pressure higher than the formation rupture pressure to alter reservoir permeability, specifically in low-permeability oil fields. Because of the high fluid flow rate, the contact time with the interface is decreased, enabling the ability for surfactants to reach the deep reservoir. In this article, based on the mixed adsorption mechanism of two surfactants and the hydrophilic and lipophilic equilibrium mechanisms, a set of high-temperature and high-salinity resistance surfactant systems appropriate for the Tahe oilfield is developed and its associated performance is evaluated. An oil displacement experiment is carried out to examine the effect of surfactant flooding by high-pressure injection. The results demonstrate that the ideal surfactant system can lower the interfacial tension to 10−2 mN/m and its capacity to reduce the interfacial tension to 10−2 mN/m after different aging periods. Besides, the surfactant system possesses excellent wettability (wetting angle changed from 135° to 42°) and certain emulsifying abilities. The oil displacement experiment shows that the oil recovery rate of surfactant flooding by high pressure reaches 26%. The effect of surfactant flooding by high-pressure injection is better than that of high-pressure injection flooding.

1. Introduction

The fracture-vuggy carbonate reservoirs in western China are characterized by multi-stage tectonic movement, multi-stage karst superposition, and multi-stage accumulation processes, such as substantial heterogeneity, various reservoir types, poor connectivity, difficult fluid flow law, and deep burial [1,2]. In the process of reservoir development, with the growth of oil and gas production, formation energy will be released, and then a formation energy deficit will emerge. Conventional water flooding can supplement the formation energy deficit by injecting a large amount of produced water. However, the carbonate reservoir with significant heterogeneity, huge scale of karst caverns, and complicated connection forms makes it easier to develop beneficial channels during water injection because of the large oil–water interfacial tension, small water injection sweep, and weak oil washing ability [3]. Surfactant flooding technology is a widely utilized technique in oil fields. Daqing Oilfield has achieved great success in oil recovery. The recovery reaches 45% by surfactant flooding in some blocks [4]. It can effectively reduce interfacial tension, improve waterflood sweep rate, boost oil washing capacity, and enhance oil recovery [5,6,7,8,9].
Its basic mode of action is low interfacial tension, wetting reversal, emulsification, polymerization, and the creation of oil bands. However, for the Tahe carbonate reservoir, the reservoir depth is usually over 6000 m, the temperature is high, and the formation water contains high salinity, so the conventional surfactants used in oil displacement are difficult to adapt to the conditions of high temperature and high salt [10,11,12], and the existing single high-temperature and high-salinity resistance surfactants are difficult to apply in the field because of uneconomical reasons [13,14,15,16,17,18,19,20,21,22]. At the same time, carbonate rock minerals are mainly composed of calcite and dolomite, which are rich in a large number of metal cations, and the common oil displacement agent is anionic surfactant. In the process of surfactant flooding, anionic surfactant and metal cations attract each other, resulting in a large amount of anionic surface activity adsorbed on the rock surface. The surfactant is lost near the well before it reaches the remaining oil zone [23,24,25]. Therefore, the surfactant flooding of the carbonate reservoir is difficult to some extent. High-pressure injection flooding is a new water flooding technology that can be effective. The water injection technology can solve the difficulty of surfactant flooding in carbonate reservoirs [26].
According to its characteristics, high-pressure injection flooding is called large pressure differential asymmetric coupling waterflood technology. With the help of large displacement and high-pressure pumping equipment, a large amount of water is injected in a short time at a pumping pressure higher than the rock rupture pressure, and then pressure dispersal methods such as shut-in and stimming are adopted to provide energy for the corresponding wells of well groups and improve the development effect of well groups [27,28,29,30]. This technology can expand the water flooding coverage, change the pore structure, improve the oil–water flow channel, and achieve the goal of enhanced oil recovery. This technology has been applied in the old oilfields in eastern China. The low permeability oilfields in the east use this technology implementation to improve oil recovery, and the cumulative oil increase reaches 55.7 × 10−4 t [31].
As a result of high-pressure injection flooding, the pressure near the injection well is high, close to the rupture pressure, and the pore space expands, the elastic energy of the reservoir is effectively stored, and the physical property of the reservoir near the injection well is improved [32,33,34]. Because of the injection of a large amount of high-pressure fluid, the flow distance of the injected fluid is increased, the swept volume is expanded, and the distribution of remaining oil is changed. At the same time, during the high-pressure injection flooding process, the seepage velocity of the injection fluid is significantly increased, and the contact time with the rock is greatly reduced. The time to reach the dynamic adsorption equilibrium on the core surface is shortened. A lot of surfactants are quickly pumped into the deep formation [35,36]. High-pressure injection flooding technology can solve the technical difficulties of surfactant flooding in carbonate reservoirs, realize carbonate surfactant flooding, and improve oil recovery.
At present, the combination of high-pressure injection flooding technology and surfactant flooding has not been applied to carbonate rock reservoirs. This paper innovatively developed a surfactant system suitable for carbonate rock reservoirs and evaluated the effect of combining high-pressure injection flooding technology. In this paper, the surfactant system is evaluated by the wettability, emulsification ability, and oil film stripping performance. The oil displacement experiment is conducted to evaluate the recovery of surfactant flooding by high-pressure injection. Finally, the mechanism of surfactant flooding by high-pressure injection. This study is expected to provide guidance for enhanced oil recovery in carbonate reservoirs.

2. Construction of Surfactant System

2.1. Materials and Constructed Mechanism

2.1.1. Materials

Crude oil from Tahe oilfield, Xinjiang, China, was selected for the experiment. Its density is 0.89 g/cm3, and its viscosity is 93 mPa·s. The total mineralization of simulated formation water is 20 g/L.

2.1.2. Constructed Mechanism

The constructed mechanism of surfactants is explained from two perspectives [37]. The first is a mixed adsorption mechanism (Figure 1a). Because of the electrostatic repulsion between anionic surfactant molecules, the molecular arrangement on the interface is not tight enough, and the space between anionic surfactants is considerable. The mixed adsorption process is that there is a large gap between the anionic surfactants, and the size of the amphoteric betaine surfactant is lower than that of the gap. Amphoteric betaine surfactants have no strong interaction with anionic surfactants and can be injected into the space between anionic surfactant molecules to form a compact mixed adsorption layer. Because a lot of surfactants adsorb at oil–water surface, the tension value of the oil–water interface is lowered. The second is the hydrophilic and lipophilic equilibrium mechanism (Figure 1b,c). The interfacial tension between oil and water will attain the lowest value only when the hydrophilic capacity and the lipophilic capacity are equivalent.

2.2. Surfactant Optimization

First, anionic surfactants and amphoteric surfactants with temperature and salt tolerance were selected according to the formation conditions. Then, the interfacial tension values of the surfactants under high-salt conditions and high-temperature conditions were measured. Then, anionic surfactants and amphoteric surfactants with relatively low interfacial tension values were selected for compounding at different concentrations. Finally, the system with the lowest interfacial tension value was screened out.

2.2.1. Anionic Surfactant Optimization

According to the characteristics of reservoir temperature and formation water in the Tahe oilfield, the anionic surfactant with temperature and salt resistance is selected. The anionic surfactant with low interfacial tension is selected in the condition of high temperature and salt.
The following three surfactants meet the requirement: alkyl phenol ether sulfosuccinate sodium salt (OS) with 40% purity, sodium dodecyl benzene sulfonate (LAS) with 90% purity, and sodium alkylphenol polyoxyethylene ether carboxylate (APEC). Surfactants were obtained from Yousuo, a Chinese company in Shandong, China.
Their interfacial tension was measured. The value of APEC and LAS is the smallest (Figure 2a). The measurement condition is high temperature, high salinity water, and surfactant with a concentration of 0.1%.
The interfacial tension of anionic surfactants was increased little after the aging test (Figure 2b).
Therefore, the APEC surfactant was selected as one of the components of the surfactant system.

2.2.2. Zwitterionic Surfactant Optimization

Five amphoteric surfactants with high-temperature and high-salinity resistance are selected.
The following five amphoteric surfactants meet the requirement: lauramide propyl hydroxysulfonyl betaine (LHSB), dodecyl dimethyl hydroxypropyl sulfobetaine (HSB-12), dodecyl dimethyl betaine (BS-12), coconut amide propyl hydroxysulfonyl betaine (CHSB), and cocoamidopropyl betaine (CAB). Surfactants were obtained from Yousuo, a Chinese company.
It is found that the interfacial tension of LHSB is the smallest (Figure 3a). The interfacial tension of HSB-12 surfactant decreased significantly after the aging test (Figure 3b). Therefore, the LHSB and HSB-12 surfactants are selected as two of the components of the surfactant system.

2.3. Optimal Surfactant System

APEC surfactant is mixed with LHSB and HB-12. The interfacial tension value of the two systems is compared. The best surfactant system is the one with the lowest interfacial tension.
Aging test is a method to evaluate the stability of surfactant systems. The interfacial tension value after being placed in an oven at 130 °C is measured to evaluate the advantages and disadvantages of the surfactant system. In this paper, aging experiments were carried out at different times of one week, one month, and three months.
The experiment shows that the interfacial tension of the APEC + LHSB surfactant system increases with the increase in aging time. When the aging time reaches 3 months, the interfacial tension value of the APEC + LHSB surfactant system under all ratios is greater than 0.1 mN/m. The interfacial tension of the APEC + HSB-12 (0.4~0.5 wt% APEC and 0.4~0.5 wt% HSB-12) surfactant system does not change with the aging time and is always <10−2 mN/m (Figure 4). It meets the requirements of an oil displacement agent.
Therefore, APEC + HSB-12 (0.45 wt% APEC and 0.45 wt% HSB-12) was chosen as the best surfactant system.

3. Performance Evaluation

3.1. Wettability Evaluation

3.1.1. Experiment

Wettability was evaluated by underwater contact angle measurement. The carbonate core with a diameter of 2.5 cm was cut into core slices with a thickness of 1 cm. The core pieces were placed in kerosene and aged at 110 °C for 3 days. The change in the contact angle of oil droplets on oil-wet core slices in a surfactant and water environment was measured with a contact angle meter (JC2000D, POWEREACH, Shanghai, China).

3.1.2. Result Analysis

The underwater oil contact angle on the carbonate rock core sheet after oil wet treatment is 125°, suggesting that the surface has been converted to oil wet (Figure 5b).
The oil-wet core piece was immersed in a water and surfactant system for 48 h. The changes in underwater oil contact angle over time were measured (Figure 5c–h).
It can be clearly seen that the wetting angle of oil droplets in water does not change with the increase in time (Figure 5c–e). The wetting angle of the oil droplets in the surfactant system changed from 135° to 42° after 48 h. This shows that the surfactant system has a strong wetting reversal ability (the hydrophilic surface becomes hydrophobic).
The system has a strong wetting inversion ability (Figure 5f–h), which can change the lipophilic rock surface into a hydrophilic rock surface and can displace more oil. One of the reasons for the enhanced oil recovery of the experimental surfactant is that the wettability of the rock wall is reversed.

3.2. Evaluation of Oil Film Stripping Performance

3.2.1. Experiment

Prepare two 4 cm × 2.5 cm slides. One side of the oil-wet glass sheet is evenly coated with crude oil and aged at 110 °C for 48 h. The oiled glass sheet is immersed in the formation water and the composite surfactant system, respectively. Photos were taken every 2 h to record the oil film stripping status. ImageJ analysis software (https://imagej.net) was used to calculate the remaining oil film area at different times, and the oil film stripping ratio was obtained.

3.2.2. Result Analysis

The oil film stripping capability of the simulated formation water and surfactant system was evaluated (Figure 6a). At the beginning, the oil film stripping area of the surfactant system was not faster than that of simulated formation water. With the rise of time, the stripping area of the surfactant system was bigger than that of simulated formation water. According to the stripping efficiency (Figure 6b), the final stripping efficiency of the surfactant system was greater than that of simulated formation water.
An oil-wet slide immersed in a simulated formation water and surfactant system (Figure 6c). For the oil film treated by the surfactant system, the stripping process was finished in roughly 4 h. For the oil film treated with simulated formation water, a large amount of oil remains on the surface of the glass sheet after 8 h. This is consistent with wettability results. It reveals that the change in wettability has a substantial effect on oil film peeling.
The surfactant also has the ability to be lipophilic and hydrophilic. When the oil-wet slide is immersed in water containing the surfactant, the surfactant covers the oil–water interface. Due to the decrease in the oil–water interfacial tension value, the oil originally covering the surface of the slide is condensed into oil droplets (as shown in Figure 6d). At the same time, the surfactant is adsorbed on the slide, turning the oil-wet glass sheet into a water-wet glass sheet.

3.3. Emulsification Performance Evaluation

3.3.1. Experiment

The optimum surfactant system is mixed with crude oil and dispersed for 5 min in a high-speed disperser at a rate of 9000 r/min to form an emulsion. The emulsion was slightly disturbed at 75 °C (100 r/min), and the morphological characteristics of the emulsion were observed by an inverted microscope every 30 min.

3.3.2. Result Analysis

The emulsification performance is to evaluate whether the produced liquid after an oil displacement agent is well treated. It is found that (Figure 7) with the increase in time, the originally dispersed small oil droplets gather into continuous large oil droplets. The process from small oil droplets to large oil droplets only takes 3 h, which has a stronger demulsification ability than the crude oil guessed by using polymers [38].

3.4. Oil Displacement Experiment

3.4.1. Experiment

Oil recovery experiment is the study of the efficiency of oil production in a reservoir. The experiment simulates the flow of oil in the underground rock pores. To observe the process of oil displacement by injecting displacement fluid into the device equipped with the reservoir rock model (Figure 8b), the permeability of the core is 0.5 mD and porosity is 19%.
The main steps of this experiment are as follows:
① Preparation of surfactant system solution with simulated formation water.
② Clean model 1 with an ultrasonic cleaning device to prevent model 1 blockage, and then dry it in an oven at 110 °C. The model 1 mass is called M1.
③ After model 1 is cooled to room temperature, diameter, length, porosity, and permeability are measured. After the model 1 is vacuumed for 12 h and saturated with crude oil for 12 h, the wet weight of the model 1 is measured as M2, and the crude oil mass M3 (M2 − M1 = M3) is calculated.
④ Experiment with the displacement device (Figure 8a), and the experimental temperature is set to 80 °C, and the confining pressure is controlled to 3 MPa (formation pressure). Set the injection speed according to the injection method (surfactant flooding: 0.5 mL/min; high-pressure injection: 5 mL/min; surfactant flooding by high-pressure injection: 5 mL/min).
⑤ When the produced oil content of the produced liquid is not changed, the volume of the produced oil V1 in the produced liquid is measured, the crude oil mass M4 is calculated using the crude oil density ρ, and the recovery efficiency is calculated using M4/M3.

3.4.2. Result Analysis

As can be seen from Figure 9, high-pressure injection flooding can generate microfractures, which can be used to communicate with caves.
The recovery rate of first oil recovery in low-permeability fracture-cave core displacement is only 12%. The second oil recovery of surfactant flooding is raised by 4%. When the injection method of high-pressure injection flooding is utilized, the recovery rate approaches 21%. Finally, the recovery rate of surfactant flooding by high-pressure injection is the best, reaching 26% (Figure 10a,b).
Through high-pressure injection, the previously closed fracture is opened (Figure 10c) and connected to the hole with the oil, which can get more oil out, thus boosting the recovery rate.
On the basis of high-pressure injection flooding, surfactant flooding by high-pressure injection reduces the interfacial tension of oil and water, changes the wettability of the rock surface, and removes the oil adsorbed with the rock surface (Figure 10d).
The oil displacement experiment demonstrates that high injection pressure and surfactants have synergistic effects. Surfactant flooding by high-pressure injection can boost oil recovery by modifying seepage space, pore structure, oil–water interfacial tension, and rock surface wettability.

4. Conclusions

(1) The APEC + HSB-12 (0.45 wt% APEC and 0.45 wt% HSB-12) surfactant system is the best surfactant system by interfacial tension measurement and aging experiment. The system can still reduce the oil–water interfacial tension value to 10−2 mN/m after three months of aging in a high-temperature environment. Other surfactant systems cannot stably reduce the interfacial tension under high-temperature and high-salt conditions.
(2) Underwater contact angle measurement and oil film stripping experiments reveal that the system has a greater ability to change wettability than water and can successfully displace residual oil from the reservoir in the process of oil displacement.
(3) The emulsification experiment reveals that the system has a certain emulsification ability, the demulsification time is fast, and the resulting liquid is easy to handle.
(4) The oil displacement experiment demonstrates that the oil recovery rate of surfactant flooding by high-pressure injection is optimal. The mechanism of action is to diminish the oil–water interfacial tension, change rock surface wettability, open closed fractures, and change pore structure.
We predict that this system can reduce the difficulty of developing unconventional oil resources. This technology can also be combined with other chemical flooding technologies such as polymer flooding, which is expected to increase crude oil recovery even more.

Author Contributions

Resources, B.Z., X.D., Y.D. and L.X.; Writing—original draft, W.P.; Writing—review & editing, Q.Y. and X.L. All authors have read and agreed to the published version of the manuscript.

Funding

This study was supported by the National Natural Science Foundation of China (52074249 and 52204024).

Data Availability Statement

The original contributions presented in this study are included in the article. Further inquiries can be directed to the corresponding author.

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. Constructed mechanism. (a) is illustrative diagram of a mixed adsorption mechanism; (b,c) is illustrative diagram of hydrophilic and lipophilic equilibrium mechanism.
Figure 1. Constructed mechanism. (a) is illustrative diagram of a mixed adsorption mechanism; (b,c) is illustrative diagram of hydrophilic and lipophilic equilibrium mechanism.
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Figure 2. Interfacial tension value of anionic surfactant. (a) Anion surfactants interfacial tension diagram; (b) Interfacial tension before and after aging of anionic surfactants with different concentrations.
Figure 2. Interfacial tension value of anionic surfactant. (a) Anion surfactants interfacial tension diagram; (b) Interfacial tension before and after aging of anionic surfactants with different concentrations.
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Figure 3. Interfacial tension value of zwitterionic surfactant. (a) Comparison of interfacial tension values of Different Concentrations of amphoteric surfactants; (b) Comparison of interfacial tension values before and after aging.
Figure 3. Interfacial tension value of zwitterionic surfactant. (a) Comparison of interfacial tension values of Different Concentrations of amphoteric surfactants; (b) Comparison of interfacial tension values before and after aging.
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Figure 4. Diagram of interfacial tension value change with the aging time change.
Figure 4. Diagram of interfacial tension value change with the aging time change.
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Figure 5. Wetting angle inversion diagram. (a) Wetting angle variation over time graph; (b) Interfacial oil wetting diagram; (c–h) Wetting angle variation diagram.
Figure 5. Wetting angle inversion diagram. (a) Wetting angle variation over time graph; (b) Interfacial oil wetting diagram; (c–h) Wetting angle variation diagram.
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Figure 6. Oil film stripping diagram. (a) Oil film stripping ratio diagram; (b) Oil film stripping area diagram; (c) Oil film area over time; (d) Oil film stripping mechanism diagram.
Figure 6. Oil film stripping diagram. (a) Oil film stripping ratio diagram; (b) Oil film stripping area diagram; (c) Oil film area over time; (d) Oil film stripping mechanism diagram.
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Figure 7. Emulsification test diagram.
Figure 7. Emulsification test diagram.
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Figure 8. Device of oil displacement experiment. (a) instrument schematic diagram;(b) physical model of rocky core.
Figure 8. Device of oil displacement experiment. (a) instrument schematic diagram;(b) physical model of rocky core.
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Figure 9. Comparison chart of rocky core.
Figure 9. Comparison chart of rocky core.
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Figure 10. Recovery efficiency diagram of oil displacement. (a) Relationship between crude oil recovery rate and injection number; (b) Instrument diagram of primary oil recovery; (c) Instrument diagram of high-pressure injection flooding; (d) Instrument diagram of surfactant flooding by high-pressure injection.
Figure 10. Recovery efficiency diagram of oil displacement. (a) Relationship between crude oil recovery rate and injection number; (b) Instrument diagram of primary oil recovery; (c) Instrument diagram of high-pressure injection flooding; (d) Instrument diagram of surfactant flooding by high-pressure injection.
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MDPI and ACS Style

Peng, W.; You, Q.; Liu, X.; Zhou, B.; Ding, X.; Du, Y.; Xiao, L. Enhance Oil Recovery in Fracture-Cave Carbonate Reservoirs Using Zwitterion-Anionic Composite Surfactant System. Energies 2025, 18, 383. https://doi.org/10.3390/en18020383

AMA Style

Peng W, You Q, Liu X, Zhou B, Ding X, Du Y, Xiao L. Enhance Oil Recovery in Fracture-Cave Carbonate Reservoirs Using Zwitterion-Anionic Composite Surfactant System. Energies. 2025; 18(2):383. https://doi.org/10.3390/en18020383

Chicago/Turabian Style

Peng, Wei, Qing You, Xiaoqiang Liu, Bojie Zhou, Xingxing Ding, Yuechun Du, and Liangfei Xiao. 2025. "Enhance Oil Recovery in Fracture-Cave Carbonate Reservoirs Using Zwitterion-Anionic Composite Surfactant System" Energies 18, no. 2: 383. https://doi.org/10.3390/en18020383

APA Style

Peng, W., You, Q., Liu, X., Zhou, B., Ding, X., Du, Y., & Xiao, L. (2025). Enhance Oil Recovery in Fracture-Cave Carbonate Reservoirs Using Zwitterion-Anionic Composite Surfactant System. Energies, 18(2), 383. https://doi.org/10.3390/en18020383

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