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Article

Physical Modeling of High-Pressure Flooding and Development of Oil Displacement Agent for Carbonate Fracture-Vuggy Reservoir

by
Jinghui Li
1,
Wen Zhang
1,*,
Bochao Qu
1,
Enlong Zhen
1,
Zhen Qian
1,
Shufen Ma
1,
Fei Qin
1 and
Qing You
2,*
1
Key Laboratory of Enhanced Oil Recovery in Carbonate Fractured-Vuggy Reservoirs, CNPC, Urumqi 830011, China
2
School of Energy Resources, China University of Geosciences, Beijing 100083, China
*
Authors to whom correspondence should be addressed.
Processes 2025, 13(1), 71; https://doi.org/10.3390/pr13010071
Submission received: 17 October 2024 / Revised: 15 December 2024 / Accepted: 30 December 2024 / Published: 1 January 2025
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
Browse Figures
Versions Notes

Abstract

:
The fracture-cavity carbonate reservoir in Tahe oilfield is buried deep (more than 5000 m). The reservoir has low permeability, strong heterogeneity, large size, diverse forms of connectivity, and complex spatial distribution. In conventional water flooding, it is difficult to improve oil recovery effectively because of small water flood sweep and large injection pressure. Pressure flooding is a new water injection technique that can change the reservoir pore space. Combined with an oil displacement agent, pressure flooding is expected to improve the recovery rate of carbonate reservoirs. In this paper, the influence factors of pressure flooding technology are studied, and a set of surfactant systems suitable for high-temperature and high-salt reservoirs is developed. The results show that only an appropriate injection flow can produce microfractures. Only an appropriate displacement rate can optimize the effects of pressure flooding. With an increase in crude oil viscosity, the recovery rate after pressure flooding decreases gradually. A complex fracture network is formed in reservoirs after pressure flooding. The new surfactant system has good interfacial tension reduction properties and excellent stability. Pressure flooding experiments with the addition of a surfactant showed that the system can help to improve the recovery of pressure flooding.

1. Introduction

The Tahe fracture-cavity carbonate reservoir is a super deep carbonate reservoir in China. It depth is deep; has a high temperature, high formation water salinity, low permeability, strong heterogeneity, large size, diverse connectivity forms, and complex spatial distribution; and is difficult to develop. After natural energy development, this field has experienced a lot of water flooding development. At present, it is difficult to displace more crude oil from the formation because of the poor sweep of conventional water injection and the difficulty of injection [1,2,3].
Water injection pressure flooding technology, also known as asymmetric coupling water injection technology with a large pressure difference, uses high-displacement and high-pressure pumping equipment to pump a large amount of water at a pump pressure higher than the limit pressure in a short period of time [4]. Then, pressure dispersion methods such as well closure and soaking are used to provide energy for the corresponding oil wells in the well group and improve the development effect of the well group. In the process of reservoir development, as oil and gas production progresses, formation energy is released, resulting in a shortage of formation energy [5,6]. A large amount of water can be injected to quickly replenish formation energy via high formation energy. The injection pressure is greater than the fracture pressure, and the pore space changes. As a large amount of high-pressure fluid is injected into the water flood, the flow distance of the injected fluid is increased, the affected volume is enlarged, and the remaining oil is redistributed. At the same time, reducing the injection–production distance is conducive to establishing effective displacement under a large pressure difference [7,8,9,10].
Because the reservoir’s depth is deep in the Tahe oilfield, the injection pressure of water injection pressure flooding is high. It is difficult for water injection equipment to withstand high pressure. So, it is necessary to reduce the injection pressure. Surfactants can change the interfacial tension of oil and water. They can also reduce the injection pressure [11,12,13,14,15,16].
Due to the high temperature of the Tahe oilfield and the high salinity of formation water, conventional surfactants have poor performance in high-temperature and high-salt reservoirs. Therefore, it is necessary to choose surfactants that resist high temperature and high salt, and they should have the characteristic of ultra-low interfacial tension [17,18,19,20].
Ionic surfactants can be used under high-temperature conditions, but they are not salt-resistant. Amphoteric surfactants have high solubility in high-salinity water, but they do not have ultra-low interfacial tension [21,22,23,24,25,26]. Ordinary non-ionic surfactants are easy to hydrolyze at high temperatures. Negative-non-ionic surfactants have high temperature resistance, but a single negative-non-ionic surfactant has limited ability to reduce interfacial tension [27,28,29,30,31,32,33,34].
The surfactant system consists of two or more kinds of surfactants mixed together according to different ratios of concentrations; the mixed surfactant system has a synergistic effect, and compared with a single surfactant, it has more temperature and salt resistance ability [35,36,37,38,39,40,41,42,43,44]. For high-temperature and high-salt reservoirs, the mixture of non-ionic and amphoteric surfactants is selected, and the optimal surfactant system is selected according to the interfacial tension [45,46,47,48,49].
Pressure flooding binding surfactants have been studied by many scholars. However, these studies have mostly focused on low-permeability sandstones or old oilfields in the later stages of development. Based on previous research, factors that influence pressure flooding technology are studied, and a set of surfactant systems suitable for high-temperature and high-salt reservoirs is developed in this paper.

2. Experiment

2.1. Pressure Flooding Experiment

This experiment evaluates factors that influence pressure flooding through recovery and pressure data. The specific operational steps are as follows:
  • Polishing the two ends of the cut, drilled, and opened core to ensure that its cross-section can fully fit the inlet and outlet ends in the core holder. Connect experimental instruments and pipelines, place the core into the core holder, and apply confining pressure around the core.
  • To operate and start the core displacement equipment on the computer, set the water injection flow (or displacement rate), and record the changes in injection pressure during the pressure flooding experiment until the pressure changes stabilize and the outlet of the core gripper releases liquid. Save pressure data during the pressure drive experiment. Record oil recovery data.
  • To change the conditions of different rocky cores, injection flows, and displacement rates. Repeat b and record data. The results of the experiment must be subjected to rigorous analysis.
The experimental equipment is shown in Figure 1.

2.2. Three-Dimensional Fluid Structure Coupling Pressure Flooding Experiment

Using natural carbonate rock slabs for pressure flooding physical simulation experiments, the propagation and development of fractures on a two-dimensional plane were analyzed. A three-axis stress fluid structure coupling experimental device (Shengli Oilfield Exploration and Development Research Institute, Dongying, China) was used for this experiment.
  • To drill holes in a natural carbonate rock salt plate that is 50 cm long, 50 cm wide, and 5 cm high, and place it on a workbench to check the connection of each pipeline.
  • To operate and start the core displacement equipment on the computer to apply confining pressure to the large rock slab. After the pressurization is completed and stabilized, turn on the displacement device and data acquisition system, monitoring and saving experimental data throughout the process.
  • To set the pump inlet flow rate and turn on the collection device to start collecting and replacing. Collect water from the device and wait for the pressure to stabilize before ending the experiment. Inspect, relieve pressure, and unload the device.
  • To take out the large rock slab and observe its crack morphology; take photos and save them.
The experimental equipment is shown in Figure 2.

2.3. Interface Tension Experiment

The interfacial tension experiment was used to measure the tension between liquid and liquid. A rotational interfacial tensiometer was used to determine the interfacial tension between oil and water with different concentrations of surfactants and different aging times. The value of interfacial tension was used to evaluate the goodness of the surfactant system. The experimental equipment is shown in Figure 3.

3. Experimental Results and Analysis

3.1. The Influence of Different Factors on Fractures

3.1.1. Effects of Different Injection Flows on Fracture Propagation

Injection flow rate refers to the flow rate when forming fractures in rock. The injection flow corresponds to the field displacement. Different injection speeds produce different cracks, and the length and width of cracks affect the conductivity of cracks. Therefore, determining the injection speed has a great effect on field guidance. Similar criteria were used to unify the field and laboratory injection flows. The ratio of the field displacement to pipeline cross-sectional area is equal to the ratio of the laboratory injection flow to pipeline cross-sectional area. In other words, 1 m3/min in the field is equal to 1 mL/min in the laboratory.
Figure 4 shows the variation in injection pressure with time during pressure flooding at different injection flows, which is the situation where microcracks communicate with caves. From the figure, it can be seen that the average fracture pressure of the rock core is 17 MPa. According to the relevant literature, the formation pressure gradient ranges from 0.0098 to 0.0102, which can be converted into depth based on confining pressure. When calculating the ruptured pressure gradient using the ruptured pressure measured in the laboratory, due to the confining pressure of 10 MPa and the corresponding depth of 1000 m in this experiment, the ruptured pressure gradient under experimental conditions is 0.0017 MPa/m, which is close to the actual formation fracture pressure gradient.
When the experimental injection flow is 2 mL/min, fractures develop again, and wide fractures are formed. When the injection flow is between 4 and 8 mL/min, the microcracks form after the injection pressure reaches the ruptured pressure. When the injection flow reaches the ruptured pressure at 10 mL/min, wide fractures can be formed, which can easily cause water breakthrough. The optimal flow rate for the core model is 8 mL/min.

3.1.2. Effects of Different Displacement Rates on Fracture Propagation

Displacement rate refers to the rate of water injection that displaces crude oil. The effects of different displacement rates on oil recovery are shown in Figure 5. When the oil displacement rate is lower than 0.5 mL/min, the recovery rate is lower. Because low velocity does not produce a strong impact force, it cannot wash out the crude oil adsorbed on the rock wall. When the flow rate is higher than 0.5 mL/min, the recovery rate increases slowly. Because the displacement rate of 0.5 mL/min can flush out most of the crude oil in the hole, increasing the displacement rate will not allow more crude oil to be flushed out. So, the optimal oil displacement rate is 0.5 mL/min.

3.1.3. Effects of Crude Oil Viscosity on Fracture Propagation

The viscosity of crude oil was measured by a Brookfield viscometer according to GB/T22235-2008 [50]. Crude oil with a viscosity of 10, 20, 100, and 700 was selected for this experiment.
According to Table 1, at the optimal oil displacement rate (0.5 mL/min), the recovery rate gradually decreases with an increase in crude oil viscosity after pressure flooding [50]. When the viscosity of crude oil is less than 100 mPa·s, the recovery rate is 60%. When the viscosity of crude oil is greater than 100 mPa·s, the recovery rate after pressure flooding decreases slowly and gradually stabilizes at around 40%. Therefore, oil viscosity has an important effect on pressure flooding recovery, and the higher the oil viscosity, the lower the recovery.

3.2. Propagation Patterns of Fractures in Rock After Pressure Flooding

From Figure 6, fracture propagation shows that there are naturally closed fractures in the large rock plate of natural carbonate rock fissures, and the natural microfracture morphology of the rock plate model is random. Under the action of pressure flooding, it extends and develops, producing a complicated network of hydraulic fractures. The hydraulic fractures generated by pressure flooding propagate along the direction of the minimum horizontal principal stress of the rock. When natural fractures are encountered, they are opened and propagate along natural fractures.

3.3. Screening and Evaluation of Temperature- and Salt-Resistant Surfactant System

3.3.1. Surfactant System Screening

Seven types of anionic and amphoteric surfactants were collected. The experimental conditions were a high temperature of 130° and high-salinity formation water. As shown in Figure 7, under the condition of high temperature and high salt, the APEC-9 anionic surfactant had the lowest interfacial tension among anionic surfactants, and the BSSB amphoteric surfactant had the lowest interfacial tension among amphoteric surfactants.
The mixed use of anionic and amphoteric surfactants has a synergistic effect. Therefore, APEC-9 and BSSB were selected as a surfactant system.

3.3.2. Stability Evaluation of Surfactant System

After surfactants were injected into the ground, they must be stable for a certain amount of time. That time is 1 month. Therefore, the stability of different concentrations of surfactant systems should be evaluated.
From Figure 8, Figure 9 and Figure 10, the stability of 0.5 wt % APEC + 0.4 wt % BSSB was found to be good. It can be seen that the composite system can reduce the interfacial tension to the order of 10−2 mN/m. After the aging time increases, the interfacial tension value can still be reduced to the order of 10−2 mN/m.

3.3.3. Performance of Surfactant System in Pressure Flooding

According to Table 2, compared to the recovery rate without the addition of surfactants, the recovery rate with the addition of surfactants increased by 13.97%. And through setting up surfactant pressure flooding experiments at different temperatures, it was found that the recovery rate after pressure flooding slightly decreased with an increase in temperature, and overall, it tended to stabilize, indicating that the developed surfactant system has strong stability at high temperatures.
According to Table 3 and Figure 11, it can be seen that by conducting pressure flooding experiments with surfactants at different crude oil viscosities and comparing them with previous pressure flooding experiments without surfactants, it was found that the oil recovery rates at all viscosities were improved, with an average increase of 20.36%, and the higher the crude oil viscosity, the more significant the improvement in recovery rate.
One reason for increasing recovery is that the structure of the pore changes due to pressure flooding. Permeability increases, and sweeping volume also increases. Then, the surfactant system changes the wettability of the rocky surface. Oil is displaced easily by pressure flooding.

4. Conclusions

In this paper, we studied the influencing factors of pressure flooding and developed a set of oil-displacing agents suitable for high-temperature and high-salt conditions. The results show that the injection flow has a large impact on fracture extension, and only a suitable injection flow can produce microfractures that communicate with the hole; the impact of the displacement rate on recovery is relatively large, the recovery rate is small when the displacement rate is small, and the recovery rate increases when the displacement rate increases. When the recovery rate reaches a certain value, the displacement rate increases, and the recovery rate no longer increases. Crude oil viscosity has a greater impact on the recovery rate; the greater the crude oil viscosity, the lower the recovery rate of pressure flooding. Additionally, 0.5 wt %APEC-9 + 0.4 wt %BSSB is a set of surfactant systems suitable for high-temperature and high-salt reservoirs, which can reduce the interfacial tension to 10−2 mN/m and has good stability with an effective time of 1 month. The surfactant pressure flooding experiments show that the addition of surfactants can improve the recovery rate of pressure flooding.

Author Contributions

J.L.: writing review and editing. W.Z.: methodology, investigation, and editing. B.Q.: conceptualization, methodology, and writing—original draft. E.Z.: data curation and visualization. Z.Q.: Data curation. S.M.: investigation and data analysis. F.Q.: conceptualization and supervision. Q.Y.: funding. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by the “Thirteenth Five-Year Plan” major national projects (2016ZX05014-005).

Data Availability Statement

Data are contained within the article. The original contributions presented in this study are included in the article. Further inquiries can be directed to the corresponding author(s).

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. Core model.
Figure 1. Core model.
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Figure 2. Three-dimensional fluid structure coupling pressure flooding experimental equipment. (a) Rocky slabs; (b) Three-axis stress fluid structure coupling experimental device; (c) Cracked rock slabs; (d) Hole; (e) Hydraulic fractures.
Figure 2. Three-dimensional fluid structure coupling pressure flooding experimental equipment. (a) Rocky slabs; (b) Three-axis stress fluid structure coupling experimental device; (c) Cracked rock slabs; (d) Hole; (e) Hydraulic fractures.
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Figure 3. Interface tension experimental equipment.
Figure 3. Interface tension experimental equipment.
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Figure 4. Changes in injection pressure over time at different displacements: (a) 2 mL/min; (b) 4 mL/min; (c) 6 mL/min; (d) 8 mL/min; (e) 10 mL/min.
Figure 4. Changes in injection pressure over time at different displacements: (a) 2 mL/min; (b) 4 mL/min; (c) 6 mL/min; (d) 8 mL/min; (e) 10 mL/min.
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Figure 5. Recovery rate variation curve with oil displacement rate.
Figure 5. Recovery rate variation curve with oil displacement rate.
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Figure 6. Fracture propagation after pressure flooding.
Figure 6. Fracture propagation after pressure flooding.
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Figure 7. Interfacial tension maps of different concentrations.
Figure 7. Interfacial tension maps of different concentrations.
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Figure 8. Equivalent diagram of interfacial tension after one week of aging in composite system.
Figure 8. Equivalent diagram of interfacial tension after one week of aging in composite system.
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Figure 9. Equivalent diagram of interfacial tension after 2 weeks of aging in composite system.
Figure 9. Equivalent diagram of interfacial tension after 2 weeks of aging in composite system.
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Figure 10. Equivalent diagram of interfacial tension after one-month aging of composite system.
Figure 10. Equivalent diagram of interfacial tension after one-month aging of composite system.
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Figure 11. Recovery rate of pressure flooding after adding surfactants to crude oils with different viscosities.
Figure 11. Recovery rate of pressure flooding after adding surfactants to crude oils with different viscosities.
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Table 1. Recovery results of crude oils with different viscosities.
Table 1. Recovery results of crude oils with different viscosities.
Crude Oil Viscosity, mPa·sSewing Injection Speed, mL/minOil Displacement Injection Speed, mL/minRecovery Efficiency, %
1080.576.15
2080.563.6
10080.550.8
70080.539.3
Table 2. Pressure flooding recovery rates with and without surfactant.
Table 2. Pressure flooding recovery rates with and without surfactant.
Pressure Flooding Speed/mL/minPre-Pressure Permeability/mDPermeability After Pressure Flooding/mDRecovery Efficiency/%
80.00841.67976.15
80.00721.59290.12
Table 3. Recovery rate of surfactant pressure flooding under different crude oil viscosities.
Table 3. Recovery rate of surfactant pressure flooding under different crude oil viscosities.
Crude Oil Viscosity/mPa·sSewing Injection Speed/mL/minOil Displacement Injection Speed/mL/minRecovery Efficiency/%Growth Value of Recovery Rate/%
1080.590.1213.97
2080.585.221.6
10080.575.424.6
70080.565.626.3
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Li, J.; Zhang, W.; Qu, B.; Zhen, E.; Qian, Z.; Ma, S.; Qin, F.; You, Q. Physical Modeling of High-Pressure Flooding and Development of Oil Displacement Agent for Carbonate Fracture-Vuggy Reservoir. Processes 2025, 13, 71. https://doi.org/10.3390/pr13010071

AMA Style

Li J, Zhang W, Qu B, Zhen E, Qian Z, Ma S, Qin F, You Q. Physical Modeling of High-Pressure Flooding and Development of Oil Displacement Agent for Carbonate Fracture-Vuggy Reservoir. Processes. 2025; 13(1):71. https://doi.org/10.3390/pr13010071

Chicago/Turabian Style

Li, Jinghui, Wen Zhang, Bochao Qu, Enlong Zhen, Zhen Qian, Shufen Ma, Fei Qin, and Qing You. 2025. "Physical Modeling of High-Pressure Flooding and Development of Oil Displacement Agent for Carbonate Fracture-Vuggy Reservoir" Processes 13, no. 1: 71. https://doi.org/10.3390/pr13010071

APA Style

Li, J., Zhang, W., Qu, B., Zhen, E., Qian, Z., Ma, S., Qin, F., & You, Q. (2025). Physical Modeling of High-Pressure Flooding and Development of Oil Displacement Agent for Carbonate Fracture-Vuggy Reservoir. Processes, 13(1), 71. https://doi.org/10.3390/pr13010071

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