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Article

A Study on the Effect of New Surfactant Proportions on the Recovery Improvement of Carbonate Reservoir

by
Pengfei Li
and
Mingyi Hu
*
School of Geosciences, Yangtze University, Wuhan 430100, China
*
Author to whom correspondence should be addressed.
Appl. Sci. 2024, 14(10), 4028; https://doi.org/10.3390/app14104028
Submission received: 2 April 2024 / Revised: 26 April 2024 / Accepted: 7 May 2024 / Published: 9 May 2024
(This article belongs to the Section Earth Sciences)
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Abstract

:
The strategy of integrating water injection and chemical additives in combining secondary and tertiary oil recovery techniques has been widely investigated in enhancing oil recovery efficiency. Nevertheless, there is a lack of sufficient evidence on the effectiveness of a mixture of cationic and nonionic surfactants combined with water injection techniques in enhancing recovery in the application of carbonate reservoirs. Therefore, it is particularly critical to explore the impact of this combination strategy in enhancing recovery in fractured carbonate reservoirs. The recovery enhancement effect can be assessed by conducting phase behavior experiments and determining interfacial tension and contact angle. Further, the effectiveness of specific surfactant ration solutions in enhancing recovery can be verified by performing drive-off experiments. The results show that low mineralization water and surfactants have a significant synergistic effect in enhancing the recovery efficiency of carbonate reservoirs, with the optimal ratio of cationic to non-ionic surfactants being 2.5:1. The optimized surfactant ratio is able to increase the recovery of carbonate reservoirs by 20% compared to the original recovery rate.

1. Introduction

According to statistics, more than 60% of the world’s oil reserves are located in carbonate reservoirs, many of which are enriched in natural fractures, and the mechanism of oil and gas recovery in natural fracture-type reservoirs is more complicated than that in conventional reservoirs [1]. However, since more than 20% of the world’s oil is extracted from naturally fractured reservoirs, the study of the recovery rate of naturally fractured reservoirs has always been a direction of attention [1,2,3,4,5,6,7,8].
Natural fracture-type reservoirs refer to oil and gas reservoirs in which the storage space and percolation channels of the reservoir are mainly fractures [4,5]. Reservoirs are generally dense and brittle rock formations with non-permeable and poor permeability, and the lithology is highly heterogeneous. The causes of fractures are diverse, but tectonic fractures are predominant, so fractured oil and gas reservoirs are classified into the broad category of tectonic reservoirs, and if the reservoir tectonic map is backslope, it can also be called fractured backslope oil and gas reservoirs. Compared with other types of oil and gas reservoirs, fracture-type oil and gas reservoirs have some significant features. For example, the original porosity of reservoirs in fracture-type reservoirs varies, and the permeability is extremely low, but the permeability is very high in the fracture development zone. In addition, the distribution of pore permeability development in fracture-type reservoirs is extremely uneven, and the oil and gas storage performance varies greatly in different parts of the same reservoir. The core permeability of oil and gas reservoirs measured in the laboratory is often very low, but in the subsurface, due to the development of fractures, communicating the various storage spaces in the reservoir, forming an unimpeded seepage system, the actual permeability of the reservoir in the extraction is very high [7,8,9,10,11].
As a type of fractured reservoir, one of the challenges in hydrocarbon recovery from carbonate reservoirs lies in the wettability characteristics of the reservoir rock. Statistically, it has been observed that up to 77% of carbonate rocks exhibit non-water-wet behavior, indicating that water injected into the fractures and pores does not readily flow [5,6]. Additionally, the permeability in fractured reservoirs is typically significantly greater than that in rock pores, rendering viscous forces relatively insignificant. Consequently, conventional waterflooding techniques for enhanced oil recovery often prove ineffective in propelling surfactants into rock pores, which serve as the primary zones of hydrocarbon accumulation in fractured reservoirs due to their superior retention capabilities compared to fractures. While employing high-temperature and high-pressure gas injection techniques can enhance recovery rates in such reservoirs, this approach invariably incurs elevated costs [10,11,12,13,14,15,16,17,18].
In oil-wet and mixed-wet fractured reservoirs, the conventional secondary recovery strategy of enhancing hydrocarbon recovery via water injection often fails to achieve significant results. This is primarily due to the presence of capillary forces which inhibit the ingress of water into rock pores, thereby impeding the displacement of hydrocarbons. Consequently, it becomes imperative to decrease the interfacial tension (IFT) and modify the contact angle in order to improve recovery efficiencies in these types of reservoirs.
In practical application, interfacial tension is generally reduced by adding surfactants to the injection water [15,16,17]. Furthermore, surfactants are capable of altering the wettability of carbonate rocks to enhance their hydrophilicity. Different classes of surfactants, including cationic, nonionic, and anionic, employ distinct mechanisms to modify wettability. Among these, cationic surfactants are particularly effective in significantly influencing the wettability properties of the rock surfaces. The high cost of adding surfactants alone also means that this method is difficult to scale up [19,20,21,22].
In addition to surfactants, it has been mentioned in past studies that other chemicals can be used to reduce interfacial tension or change rock wettability to a more favorable state [23,24,25,26,27,28,29,30,31,32,33,34,35,36,37,38,39,40,41,42,43]. Among the various enhanced oil recovery techniques, the injection of low-salinity water has garnered significant interest from the research community in recent years, primarily due to its operational simplicity and reduced implementation costs. Currently, international researchers have performed specialized core analysis experiments on samples derived from carbonate reservoirs. These studies have demonstrated that the efficacy of low-salinity water injection is highly dependent on the specific properties of the rock and the chemical composition of the water injected [23]. By manipulating the ionic composition of the injected water, it is possible to enhance recovery rates by modifying relative permeability and altering the wettability of oil-wet and mixed-wet carbonate rocks towards increased hydrophilicity [24,25,26,27,28]. In addition, zeta potential assessments have revealed that the impact of low-salinity water injection in carbonate reservoirs is more pronounced at elevated temperatures [20]. Lower acid values in oil, elevated initial water saturation, and the presence of calcium, magnesium, and sulfate ions in the injected water can also enhance the efficacy of advanced water injection techniques [29,30,31].
In the present research, we have developed a novel enhanced recovery technique for carbonate reservoirs, integrating water injection with surfactants to optimize oil and gas extraction. For this study, rock and oil samples were collected from a fractured reservoir located in the Sichuan Basin. The Sichuan Basin, encompassing approximately 260,000 square kilometers or 46 percent of Sichuan Province’s total area, is geographically delineated by the Tibetan Plateau and the Hengduan Mountains to the west, and the Qinba Mountains to the north, adjacent to the Hanzhong Basin. The primary lithological composition of the basin predominantly includes purplish-red sandstones and shales. Low-salinity solutions were formulated by adjusting the ionic composition and diluting the formation water. Through experimental evaluations of various diluted low-salinity solutions, the optimal salinity level that resulted in the minimum contact angle was identified. Additionally, to enhance the efficacy of water injection, two types of surfactants, cationic and nonionic, were incorporated into the solution with the determined optimal salinity. The stability of the water containing the designed surfactant mixture was assessed through multiple experiments. These assessments confirmed that an optimal proportion of cationic to nonionic surfactant concentrations effectively minimized the interfacial tension. The specific methods and results of the above experiments are described in detail below. The efficacy of the formulated solutions was rigorously assessed through core flooding and seepage experiments, and the outcomes were benchmarked against those achieved with alternative surfactant formulations and low-salinity solutions. The findings substantiated that the specifically tailored surfactant ratios in the designed solution significantly enhance hydrocarbon recovery in carbonate fractured reservoirs, demonstrating a pronounced superiority over other comparable methods.

2. Materials and Methods

2.1. Materials

The core and oil samples utilized in this study were sourced from a fractured reservoir within the Sichuan Basin. Both experimental and simulation activities were conducted at a controlled temperature of 50 °C to mimic reservoir conditions. The samples consistently had the same rock type, predominantly characterized by calcite lithology, with minor lithological variations, including hard gypsum and dolomite colluvium. Subsequent to preparatory procedures, key petrophysical properties such as porosity, permeability, and water saturation of the cores were quantitatively assessed using formation water. The detailed characteristics of the core samples are presented in Table 1.
The diameter of the core used is 4 cm, the properties of crude oil under normal temperature and pressure conditions are shown in Table 2, the results of SARA analysis of the crude oil samples are shown in Table 3, and the characteristics of formation water are shown in Table 4. SARA analysis (also known as four-component analysis) is the separation of bitumen samples into asphaltene, colloidal, saturated, and aromatic fractions by solvent precipitation and column chromatography using a defined solvent and adsorbent. Formation water with different dilutions was used in the experiments, which has a salinity of about 35,000 mg/L and contains a large number of divalent ions. According to previous research experience, the oil drive efficiency of low mineralization water injection can be improved by increasing the divalent ions in the formation water. For this purpose, 800 mg/L of calcium, magnesium, and sulfate ions were added to the solution. Finally, the solution was diluted about 30 times by adding distilled water to obtain the ratio composed of surfactant and water together.

2.2. Methods

2.2.1. Rock Sample Preparation

Core samples were first cleaned with toluene and then with methanol to remove all original fluids present within the pores. Core samples were dried in an oven at 100 °C for 48 h, after which the cores were aged in crude oil for 60 days to restore the wettability of the original rock. Contact angle experiments on the aged cores using formation water and crude oil showed that the cores were slightly oil-wetted. The oil/brine contact angle needs to be checked during the aging process to ensure that a stable oil-wetted and mixed-wetted state is achieved.

2.2.2. Contact Angle Test

In the experiment, the contact angle was measured using a CA200 contact angle tester produced by a precision instrument company in China (Guangdong Beidou Precision Instrument Co., LTD., Dongguan, China). First, we continuously reduced the concentration of the NaCl solution and measured the contact angle by dropping it on the core sheet respectively and recorded it as a graph, and concluded that the contact angle stabilized when the concentration was reduced below a certain value, and this phenomenon indicated that the wettability of the oil/water interface was minimized by salinity at this concentration of the NaCl solution, and the optimal surfactant proportioning concentration was reached. The optimal solution dilution ratio was determined by two sets of contact angle experiments, and the solution that produced the smallest contact angle value and had the highest dilution was selected as the proportioning solution, which was used in the remaining experiments. Subsequently, we designed and employed four different ratios of cationic/nonionic surfactants, which were dripped onto the aging core flakes to measure the contact angle between the oil and the solution and recorded into graphs, and concluded that the contact angle at the oil/water interface reached the minimum value when the mixing ratio of cationic and nonionic surfactants reached a certain value, i.e., this ratio of surfactants could significantly reduce the wettability of the flake-oil-water interface. The analytical results reveal the optimum concentration of surfactant in the formulated solution, which produces the minimum contact angle value.

2.2.3. Phase Behavior Experiments

Phase behavior experiments, mainly water stability experiments and salinity experiments, are performed as a way to study the adsorption capacity of surfactant solutions at the oil/saline water interface. Water stability experiments are mainly to determine the stability behavior of water under different conditions, which can be carried out by methods such as physical tests and chemical tests. Physical tests usually involve observing the stability behavior of water at different temperatures, pressures, and pH values, e.g., by adding different chemicals and examining the rheological properties of the water. Chemical tests, on the other hand, focus on the stability of water through a series of experiments to detect the reactions between water molecules and other chemicals. These experiments can help us to understand the stability of water in different environments and thus speculate on the adsorption capacity of surfactant solutions at the oil/saltwater interface. Salinity experiments, on the other hand, are used to study the adsorption capacity of surfactant solutions at the oil/brine interface by measuring salinity. Salinity is one of the important factors affecting the properties of surfactant solutions, so the adsorption at the oil/brine interface can be understood by measuring the changes in the properties of surfactant solutions at different salinities. Measurements can be carried out using equipment such as a digital salinometer, and attention needs to be paid to sample handling and measurement techniques to ensure the accuracy of the results.
In these experiments, varying amounts of surfactants were incorporated into the solutions to achieve surfactant concentrations ranging from 0.7 to 7 mg/L. Subsequently, 5 mL of crude oil and the prepared surfactant solution were combined in a graduated pipette and agitated for 3 h at 50 °C to simulate reservoir conditions. Following this, the pipettes were maintained at 50 °C to allow for the attainment of phase equilibrium. Ultimately, the volume of microemulsion produced in each pipette was quantified. This measurement is critical as systems exhibiting lower interfacial tensions are capable of generating larger volumes of stable microemulsion through the enhanced dissolution of oil and water.

2.2.4. Experiments on Interfacial Tension

To explore the impact of surfactant solutions on the interfacial tension between oil and brine, measurements of the interfacial tension between the surfactant solution and crude oil were conducted. These measurements utilized the pendant drop method following the attainment of equilibrium between the crude oil and the surfactant solution.
Drawing upon the outcomes from contact angle assessments, phase behavior experiments, and interfacial tension evaluations, it is possible to ascertain the optimal concentration ratio of cationic to nonionic surfactants within the formulation. This ratio is critical for achieving the desired reductions in interfacial tension.

2.2.5. Core Repulsion Experiment

The impact of various injection strategies on core recovery was evaluated through a core flooding experiment. Prior to initial saturation, aged core samples underwent evacuation. Injection was conducted at a controlled low flow rate of 0.15 mL/min to ensure a homogeneous saturation distribution across the core samples and to minimize non-Darcy flow effects and pressure gradients within the cores.

3. Results and Discussion

3.1. Optimal Surfactant Ratio Concentration

In Figure 1, we observe that the oil/formation water contact angle shows a specific pattern of variation as a function of solution salinity. The data clearly show that the contact angle tends to stabilize and maintains a constant value of about 75° as the solution salinity drops below about 1800 mg/L. This phenomenon indicates that at this salinity level, the wetting characteristics of the oil/water interface are less affected by salinity, suggesting that the optimum surfactant ratio concentration is reached.
As can be seen from the graph, the effect of low-salinity rationed solutions on the contact angle is negligible, an observation that provides an important basis for investigating the mechanism of the effect of low-salinity solutions on wettability alteration. The potential causes of wettability alteration are as follows:
(1) Effect of salinity: In low salinity environments, salinization is reduced, making it easier for polar organic molecules to dissolve in the aqueous phase. This is due to the increased solubility of organic molecules under low salinity conditions, which reduces their aggregation in the oil phase. During formation aging, these polar organic substances are usually adsorbed on the surface of hydrocarbon-occupied pores, resulting in an oil-wet surface. As salinity decreases, the desorption of these molecules from the pore surface increases, resulting in a more hydrophilic wettability of the porous medium.
However, in the actual oil recovery process, measures to enhance recovery efficiency tend to have a positive impact only at the micro level due to the spatial distance limitation of the osmotic adsorption effect. This means that although recovery enhancement can be observed at a small scale, it is often difficult to significantly improve overall recovery efficiency at the macro level, i.e., over the entire stratigraphic expanse.
To address this issue, according to the relevant experiments of Li Ting and Xie An et al. (2023) on low-salinity water drive for enhanced recovery, we also used NaCl solutions with mass fractions of 10.00%, 1.00%, and 0.10%, respectively, and kept the injection rate at 0.2 mL/min, and the change of oil drive efficiency with the amount of injection is shown in Figure 2.
As can be seen from Figure 2, in the final stage of the experiment, the recovery rate was 54.79% when the mass fraction of NaCl aqueous solution was 10.00%; while the recovery rate increased to 57.69% when the salinity was reduced to 1.00%; and the recovery rate was highest at 62.17% when the salinity was further reduced to 0.10%. This indicates that low-salinity aqueous solutions can achieve higher recovery rates in the oil drive process. However, higher salinity leads to a faster oil drive rate in the initial stage of injection, which is consistent with the experimental results of Ting Li as well as Alhuraishawy et al. [42,43].
(2) Interlayer Swelling Effect: In the context of fractured reservoirs, the phenomenon of interlayer swelling significantly influences wettability alterations. The rock surface charge distribution is intricately linked to the ionic concentration within the brine. Reducing the salinity of the brine induces swelling of the water molecule layer adjacent to the rock surface. Predominantly, this swelling arises from ion exchange processes, where sodium ions in the aqueous solution are replaced by calcium ions released from dissolved carbonate rocks. This exchange leads to a reduction in the positive charge density on the rock surface. Such a modification facilitates the segregation of oil and water phases, thereby enhancing the wettability of the reservoir.
(3) Dissolution of Carbonate Minerals: Under conditions of low salinity, there is an enhanced solubility of carbonate minerals, such as calcite, which leads to an elevated concentration of calcium ions in the solution. These additional calcium ions engage in reactions with organic carboxylic acid groups adsorbed on the surface of the porous medium, prompting their dissociation from the surface. Concurrently, hydrogen ions in the solution partake in ion exchange with cations present on the surface of the carbonate minerals, thereby elevating the pH level of the solution. This rise in pH potentially facilitates the saponification process when crude oil is present. Moreover, the introduction of surfactants further decreases the interfacial tension at the rock surface, thereby enhancing the optimization of oil-water interfacial properties.
In summary, the wetting characteristics of the oil/formation water interface can be significantly influenced by finely tuning the salinity and surfactant ratios in the solution, which is of great significance for enhancing the recovery of fractured carbonate reservoirs.

3.2. Optimal Surfactant Solution Composition

Figure 3 provides detailed information on the variation of contact angle at the oil/water interface with different surfactant mixture concentrations.
As can be seen from the data in Figure 3, the contact angle at the oil/water interface reaches its lowest at about 55° when the mixing ratio of cationic and nonionic surfactants reaches 2.5:1. This result indicates that at this particular ratio, the surfactant mixture was able to significantly reduce the wettability of the oil/water interface, transforming it from a slightly oil-wet state to a slightly water-wet state. Further increase in concentration beyond 2.8 mg/L did not result in a significant change in contact angle, indicating that the wetting properties of the system were stabilized above this concentration.
Figure 4 demonstrates the variation of interfacial tension with different surfactant mixture concentrations. At a cationic/nonionic surfactant mixture concentration ratio of 2.5:1, a concentration of 2.8 mg/L was able to minimize the interfacial tension to approximately 0.3 mN/m. This low interfacial tension contributes to the formation of a stable microemulsion system, i.e., the Winsor type III, which contains a mixture of the liquid phase of oil, water, and surfactant. The formation of this microemulsion demonstrated the efficiency of the surfactant mixture in reducing the interfacial tension between oil and water.
Based on the results of contact angle measurements and interfacial tension experiments, it can be concluded that the optimal surfactant solution composition is a cationic/nonionic mixture of 2.8 mg/L with a mixing ratio of 2.5:1. This specific composition can effectively regulate the wettability of the oil/water interface and reduce the interfacial tension, which provides a theoretical basis and experimental support for enhancing the oil-water separation efficiency and improving the recovery of crude oil during the oil extraction process.

3.3. Core Replacement Results

Table 5 shows the final recovery rates after using different injected fluids in different core replacement experiments, and these data are essential for assessing the effectiveness of different production enhancement strategies.
As shown in the table, the base recovery rate for the core drive using raw formation water is 25 percent. By ordinary water injection technique, the recovery rate was increased to 37% and 35% in the first and second water injection experiments, respectively, showing some production increase. However, when surfactants were introduced, the recovery enhancement was more significant. When a cationic surfactant was used, the recovery rate increased to 42%, while when a nonionic surfactant was used, the recovery rate was 40%, both higher than the recovery rate achieved through normal water injection only.
Most notably, the highest recovery rate of 45 percent was achieved when a cationic/nonionic surfactant blend was used. This suggests that hybrid surfactants are more effective than a single type of surfactant in reducing oil-water interfacial tension, decreasing capillary confinement, and enhancing micro-scale rejection efficiency.
The observed recovery enhancement can be attributed to the reduction of oil-water interfacial tension by the surfactants, which in turn reduces the capillary pressure and makes it easier for oil droplets to be driven out of the rock pores. Since the capillary effect is one of the main causes of crude oil residue in reservoirs, reducing capillary confinement is a key strategy for recovery enhancement.
The experimental results clearly show that the use of cationic/nonionic hybrid surfactants has significant advantages in production enhancement in carbonate reservoirs. The efficient surface-active capacity of this hybrid surfactant helps to achieve higher crude oil recovery and is an effective method of chemical drive-off in oil fields. Through careful surfactant design, a significant increase in reservoir recovery efficiency can be achieved, which in turn optimizes the field development strategy.

4. Conclusions

In this study, we developed an innovative approach to enhanced recovery for the special properties of fractured carbonate reservoirs. Through careful experimental design and theoretical analysis, we first used contact angle measurement techniques to determine the optimal solution dilution ratio that can be achieved when the solution salinity is lower than approximately 1800 mg/L, thereby optimizing reservoir wettability under different geological conditions. In addition, we prepared several cationic/nonionic surfactant solution mixtures with different concentration ratios through well-designed experiments and accurately found the optimal concentration ratio of surfactant (2.5:1) by using a combination of contact angle measurements, interfacial tension assessment, and phase behavior tests. This key finding provides a new theoretical basis for regulating the oil-water interfacial properties.
Subsequently, we thoroughly investigated the effectiveness of the proportioning solution through core replacement experiments, which showed that the injection strategy using a cationic/nonionic surfactant blend could significantly increase the recovery rate by 20% compared with the original recovery rate. This remarkable result not only demonstrates the importance of surfactant solution ratio optimization but also provides a new technological path for oil recovery efficiency enhancement in fractured carbonate reservoirs.
In the actual oil recovery process, measures to enhance recovery efficiency tend to have a positive impact only at the micro level, limited by the spatial distance of the osmotic adsorption effect. This means that, although recovery enhancement can be observed at a small scale, it is often difficult to significantly improve overall recovery efficiency at the macro level, i.e., over the entire stratigraphic expanse.
In conclusion, the results of this study provide an effective recovery enhancement method for the development of fractured carbonate reservoirs, which has important theoretical significance and application value.

Author Contributions

Writing—original draft, P.L. and M.H.; Analysis, Validation, Data Processing, Graphical Processing, P.L.; Investigation, Conceptualization, Supervision, Review, M.H. All authors have read and agreed to the published version of the manuscript.

Funding

This research received no external funding.

Institutional Review Board Statement

Not applicable.

Informed Consent Statement

Not applicable.

Data Availability Statement

All data and materials are available on request from the corresponding author. The data are not publicly available due to ongoing research using a part of the data.

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. Trend chart of contact angle of oil/formation water with salinity variation.
Figure 1. Trend chart of contact angle of oil/formation water with salinity variation.
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Figure 2. The variation of water-oil displacement efficiency with different salinities over time (according to Ting Li et al., 2023).
Figure 2. The variation of water-oil displacement efficiency with different salinities over time (according to Ting Li et al., 2023).
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Figure 3. Measurement of contact angle of different surfactant solutions.
Figure 3. Measurement of contact angle of different surfactant solutions.
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Figure 4. Measurement of interfacial tension in different surfactant solutions.
Figure 4. Measurement of interfacial tension in different surfactant solutions.
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Table 1. Characteristics of core samples.
Table 1. Characteristics of core samples.
Core NumberLengths (cm)Porosity (%)Permeability (mD)Bound Water Saturation (%)
C1917.61.426.1
C28.516.51.325.8
C3815.91.225.5
C48.516.91.3526
C5817.11.526.5
Table 2. Characteristics of crude oil samples.
Table 2. Characteristics of crude oil samples.
Proportion (API)Stickiness (cp)Densities (g/mL)Acid Value
((KOH) mg/g)
Crude oil samples3240.9273.57
Table 3. SARA analysis of crude oil samples.
Table 3. SARA analysis of crude oil samples.
Saturated HydrocarbonAromatic HydrocarbonColloidAsphaltene
61.730.84.90.81
Table 4. Formation water characteristics.
Table 4. Formation water characteristics.
IonicConcentration (mg/L)
chloride ion39,540
Sulfate ion230
Bicarbonate ion66
Magnesium ion1800
Calcium ion3680
Sodium ion26,000
Iron ions50
Potassium ion200
Table 5. Recovery rates of different core displacement experiments.
Table 5. Recovery rates of different core displacement experiments.
Type of Fluid InjectedRecovery Ratio (%)
Original formation water25
First ordinary water injection37
Second ordinary water injection35
Cationic surfactant42
Non-ionic surfactant40
Mixed cationic/nonionic surfactants45
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Li, P.; Hu, M. A Study on the Effect of New Surfactant Proportions on the Recovery Improvement of Carbonate Reservoir. Appl. Sci. 2024, 14, 4028. https://doi.org/10.3390/app14104028

AMA Style

Li P, Hu M. A Study on the Effect of New Surfactant Proportions on the Recovery Improvement of Carbonate Reservoir. Applied Sciences. 2024; 14(10):4028. https://doi.org/10.3390/app14104028

Chicago/Turabian Style

Li, Pengfei, and Mingyi Hu. 2024. "A Study on the Effect of New Surfactant Proportions on the Recovery Improvement of Carbonate Reservoir" Applied Sciences 14, no. 10: 4028. https://doi.org/10.3390/app14104028

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