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Article

Investigation of Polymer-Assisted CO2 Flooding to Enhance Oil Recovery in Low-Permeability Reservoirs

by
Xin Chen
1,2,3,*,
Yiqiang Li
4,*,
Xiaoguang Sun
5,
Zheyu Liu
4,
Jianbin Liu
1,2,3 and
Shun Liu
1,2,3,*
1
College of Petroleum Engineering, Xi’an Shiyou University, Xi’an 710065, China
2
Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs, Xi’an 710065, China
3
Ministry of Education Engineering Research Center of Development and Management for Low to Ultra-Low Permeability Oil & Gas Reservoirs in West China, Xi’an 710065, China
4
State Key Laboratory of Oil and Gas Resources and Exploration and College of Petroleum Engineering, China University of Petroleum (Beijing), Beijing 102249, China
5
PetroChina Coalbed Methane Company Limited, Beijing 100028, China
*
Authors to whom correspondence should be addressed.
Polymers 2023, 15(19), 3886; https://doi.org/10.3390/polym15193886
Submission received: 7 August 2023 / Revised: 9 September 2023 / Accepted: 18 September 2023 / Published: 26 September 2023
(This article belongs to the Special Issue New Studies of Polymer Surfaces and Interfaces)
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Versions Notes

Abstract

:
CO2 flooding is a favorable technical means for the efficient development of low-permeability reservoirs, and it can also contribute to the realization of net-zero CO2 emissions. However, due to the unfavorable viscosity ratio and gravity overriding effect, CO2 channeling will inevitably occur, seriously affecting its storage and displacement effects. This paper conducts a systematic study on the application of polymer-assisted CO2 flooding in low-permeability reservoirs. Firstly, the polymer agent suitable for low-permeability reservoirs is optimized through the viscosity-increasing, rheological, and temperature- and salt-resistant properties of the solution. Then, the injectivity performance, resistance-increasing ability, and profile-improving effect of the polymer solution were evaluated through core experiments, and the optimum concentration was optimized. Finally, the enhanced oil recovery (EOR) effects of polymer-assisted and water-assisted CO2 flooding were compared. The results show that the temperature-resistant polymer surfactant (TRPS) has a certain viscosity-increasing performance, good temperature resistance performance, and can react with CO2 to increase the solution viscosity significantly. Meanwhile, TRPS has good injection performance and resistance-increasing effect. The resistance increasing factor (η and η′) of TRPS-assisted CO2 flooding increases with increased permeability, the concentration of TRPS solution, and injection rounds. Considering η′ and the profile improvement effect comprehensively, the application concentration of TRPS should be 1000 mg/L. The EOR effect of TRPS-assisted CO2 flooding is 8.21% higher than that of water-assisted CO2 flooding. The main effective period is in the first and second rounds, and the best injection round is three. The research content of this paper can provide data support for the field application of polymer-assisted CO2 flooding in low-permeability reservoirs.

1. Introduction

With increased international energy consumption and oil exploration and development intensification, low-permeability reservoirs have contributed to Chinese oil and gas resource production. Developing low-permeability oilfields is generally dominated by water injection, and gas flooding, especially CO2 flooding, is an efficient development technology for low-permeability reservoirs with excellent prospects [1,2]. CO2 flooding can play the role of high-efficiency oil displacement and geological storage simultaneously, in line with the policy of carbon peak and carbon neutrality, and has good application advantages. However, due to unfavorable mobility ratio and gravity overriding, CO2 will channel in the reservoir, significantly reducing the development effect [3,4,5]. Therefore, an economical and effective method for mitigating gas channeling is the key to further improving CO2 flooding in low-permeability reservoirs. Polymer flooding is the primary EOR technology in China [6], and it has been successfully applied in Daqing Oilfield, Xinjiang Oilfield, Dagang Oilfield, etc. [7,8]. Polymers can reduce the fluidity of injected fluids, reduce the permeability of advantageous channels through adsorption and retention, and ultimately expand the swept volume [9,10]. The resistance coefficient and residual resistance coefficient are usually used to evaluate the injectivity performance of polymer solutions, and having a suitable resistance coefficient and residual resistance coefficient is the prerequisite for the successful application of polymers [11]. Indoor research results show that polyacrylamide (HPAM) polymers can increase oil recovery by 10–12% of OOIP after water flooding [12]. Meanwhile, the molecular modification of the polymer can play an interface effect, stripping, dispersing, and carrying oil droplets [13]. In addition, polymer gels [14], polymer microspheres [15,16,17], polymeric surfactants [18], and other agents [19] can play a role in profile control and flooding, further improving oil recovery. A comparison of the EOR effects of different enhanced CO2 injection methods is shown in Appendix A Table A1. It can be found that as the system strength increases, the EOR gradually increases. However, due to the high viscosity characteristics of polymers, it must keep a good reservoir matching relationship while exerting the viscosity-increasing effect [20,21], so it is usually used in medium-high permeability reservoirs.
It is of excellent research significance to explore using polymers to assist CO2 flooding in low-permeability reservoirs to improve gas channeling and expand the swept volume. Dann et al. [22] compared the injection performance of polymer solutions in different low-permeability cores through core flooding experiments and pointed out that reservoir core characteristics other than permeability can dominate polymer performance. In addition, Ghosh et al. [23] conducted polymer injectivity experiments on two cores with a permeability of 15 mD but with significant differences in pore throat distribution. The results showed that the polymer could flow smoothly in the cores with a bimodal distribution of pore throats. But in another core with unimodal distribution, the flow is difficult. The above two studies show that the polymer solution has the potential to flow smoothly in the low-permeability reservoir, but it is necessary to meet the matching of the polymer and the reservoir. Marliere et al. [24] used cores with an effective permeability of 1–3 mD to carry out oil displacement experiments with polymers (molecular weight of 3 million Da and viscosity of 2 cP), which can increase oil recovery by 20% to 40% based on water flooding. Bennetzen et al. [25] proved by experiments that partially hydrolyzed polyacrylamide (HPAM, with a molecular weight of 8 million Da and a concentration of less than 5000 mg/L) solution injected into a 0.3 mD carbonate reservoir core at a rate of 0.5 mL/h will not produce core plugging. Mohammed Taha et al. [26] studied the application of low-salinity polymer flooding in high-temperature, high-salt, and low-permeability reservoirs. The polymers can maintain a viscosity of 2–3 cP (2500–4000 mg/L), with good injection and enhanced oil recovery effects. Leon et al. [27] reported a successful field pilot of the polymer in the low-permeability Palogrande-Cehu field. Considering the low permeability of the reservoir (6–150 mD), three polymers with different molecular weights (average concentration 1021 mg/L, viscosity 3.43 cP) were used, and the viscosity change was monitored. It is estimated that EOR efficiency can reach up to 8%, and the water cut of some wells is reduced by as much as 14%. The above studies show that the successful application of polymers in low-permeability reservoirs requires low viscosity and low injection velocity. For CO2 flooding in low-permeability reservoirs, a CO2 response mechanism based on the above studies [28,29,30] can be used to prevent gas channeling. Inject a low-viscosity polymer surfactant into the reservoir, which can react with CO2 to form worm-like micelles, significantly increasing the viscosity of the system [31,32]. However, due to the high viscosity of this type of micelles, it is mainly used for the plugging of fractures in low-permeability reservoirs [33,34,35]. Through the above literature review, two problems exist in the current research on polymer-assisted CO2 flooding in low-permeability reservoirs: (1) how to optimize the polymer agents with reservoir adaptability; and (2) how to apply the CO2 response characteristics in low-permeability reservoirs matrix.
Aiming at the above problems, the present paper studies a temperature-resistant CO2-responsive polymer surfactant (TRPS) to assist CO2 flooding to improve the oil recovery of low-permeability reservoirs. The advantages of it as an assisted agent were evaluated by comparing its static properties, such as viscosifying properties, rheological properties, and temperature and CO2 resistance with xanthan gum. Then, the injection performance, resistance-increasing performance, and profile improvement effect of TRPS were evaluated through core injectability experiments, and the optimal injection concentration was determined. Finally, the enhanced oil recovery effects of water-assisted CO2 flooding and TRPS-assisted CO2 flooding were compared. The research in this paper can provide the experimental basis and data support for agent selection, performance evaluation, and injection parameter optimization in the application process of polymer-assisted CO2 EOR of low-permeability reservoirs.

2. Material and Method

2.1. Material

Polymers: The injectivity performance of polymer solution in the low-permeability reservoirs can only be satisfied when the polymer molecular weight and solution viscosity are low enough. Low-molecular-weight polymers and polymeric surfactants can be used as two typical low-molecular and low-viscosity polymer systems. Here, xanthan gum (molecular weight is about 5 × 106 Da) and a kind of CO2-responsive temperature-resistant polymeric surfactant (molecular weight is about 106 Da) are selected as representatives of two polymer systems to conduct the following research. TRPS with certain interfacial activity and viscosity-increasing properties was obtained by grafting functional functional groups onto the main chain of polyacrylamide. Meanwhile, it has the CO2 corresponding characteristics and can significantly increase the viscosity of the solution in a CO2 environment.
Liquids: The inorganic salt purchased from Shanghai Aladdin Reagent Co. (Shanghai, China) was proportionally added to the deionized water (DI water) to prepare the simulated formation water, and the total salinity was 7000 mg/L. DI water was prepared by UPT-I-10T Ultra-pure Water Purifier from Chengdu Youpu Super Pure Technology Co. (Chengdu, China). The simulated oil is white oil purchased from, Shanghai Aladdin Co. (Shanghai, China), with a viscosity of 15.5 cP at 80 ℃ (target reservoir temperature).
Cores: Cylindrical Berea cores with a size of 3.8 × 30 cm were used for polymer-assisted CO2 flooding experiments, and the gas permeabilities are about 5 mD, 10 mD, and 20 mD, respectively. The effective permeability of each core was specifically tested before each experiment.

2.2. Polymers Static Properties

2.2.1. Viscosity-Increasing Properties

The viscosity-increasing property of a polymer refers to the ability of a polymer to dissolve in water to increase the viscosity of the aqueous phase and is the most critical parameter for evaluating a polymer agent. Use DI water to prepare XG and TRPS mother liquor with a concentration of 5000 mg/L, and stir for 2 h with an electronic stirrer at 400 rpm. Then, the mother liquid could be diluted using simulated formation water to prepare the target polymer solution (100 mg/L, 300 mg/L, 500 mg/L, 700 mg/L, and 900 mg/L). The viscosities of the polymer solutions will be tested by a Brookfield viscometer after stirring for 1 h with an electronic stirrer at 200 rpm. The shear rate of the Brookfield viscometer is 7.4 1/s, and the test temperature is 80 °C.
Next, 100 mL of the XG and TRPS solutions with the target concentration were poured into the Warring agitator, respectively, sheared at 3500 rpm for 1 min, and then we tested the viscosity of the solution again and calculated the viscosity retention rate.

2.2.2. Polymer Rheological Properties

The viscosity of polymer solution decreases with the increase in shear rate, which has a typical shear thinning property. Evaluating the viscosity of polymers at different shear rates is of great significance for testing their EOR efficiency. The rheological curves of XG and TRPS solutions at concentrations of 100 mg/L, 300 mg/L, 500 mg/L, and 1000 mg/L were tested using a Haake rheometer (HAAKE RS6000, Thermo Electron Karlsruhe GmbH, Karlsruhe, Germany), and the shear rate was 0.1 1/s to 1000 1/s, and the test temperature was 80 ℃.

2.2.3. Polymer Reservoir Adaptability

After the polymer is injected into the reservoir, it needs to stay in the reservoir environment for a long time, and its performance under this condition determines its effect. The temperature resistance and CO2 resistance performance requirements of the polymer solution are evaluated by the viscosity retention rate to meet the application conditions of the oil reservoir. Put XG and TRPS solution with a concentration of 200 mg/L, 500 mg/L, 800 mg/L, 1000 mg/L, and 1500 mg/L in a high-temperature aging tank separately and aged in an oven at 80 °C for 30 days. Samples were taken at regular intervals (2, 4, 6, 8, 10, 15, 20, and 30 d) to test the viscosities using a Brookfield viscometer. In addition, injecting CO2 into piston containers with polymer solutions of 300 mg/L, 500 mg/L, and 800 mg/L until the pressure reaches 10 MPa. Then, seal the piston and place it at 80 ℃ for ten days for a certain period to test the viscosity of the solution.

2.3. The Flow Performance of TRPS in Low-Permeability Reservoirs

2.3.1. The Injectivity Ability of TRPS

The injectivity performance of polymer solution is mainly quantitatively evaluated by Resistance Factor (RF) and Residual Resistance Factor (RFF). The specific experimental procedure is as follows: (1) After the core was vacuumed for 3 h, it was saturated with simulated water by self-priming for more than 4 h, and the porosity was calculated; (2) According to Figure 1a, the simulated formation water was injected with the ISCO pump at a constant rate, and the pressure difference between the two ends of the core was recorded as ΔP1 after the pressure became stable, and the core water permeability was calculated using Darcy law; (3) The ISCO pump was used to inject TRPS solution at a constant rate until the pressure is stable, and the pressure difference of the core was recorded as ΔP2; and (4) The ISCO pump was used to inject simulated formation water at a constant rate until the pressure was stable, and the pressure difference at both ends of the core was recorded as ΔP3. The injection rate is 0.3 mL/min, and the TRPS solution needs to be injected continuously for at least 2 PV. Finally, the FR = ΔP2/ΔP1 and the FRR = ΔP3/ΔP1 can be calculated. The specific experimental scheme is shown in Table 1.
In addition, a zeta potential analyzer (Zetasizer Nano ZS, Malvern Panalytical, malvern city, England) was used to test the hydrodynamic size of TRPS solutions with different concentrations, and the Poiseuille formula was used to calculate the mean pore throat size of the cores. The injectivity performance results of TRPS can be analyzed by comparing the above two sizes.

2.3.2. Resistance-Increasing Performance of TRPS-Assisted CO2 Flooding

After clarifying the injectivity performance of TRPS, it is necessary to evaluate the resistance-increasing effect of TRPS in the presence of CO2. Evaluation is also carried out by RF and RFF. The specific experimental procedure is the same as that in Section 2.3.1, except that step (3) is to inject CO2 and TRPS solution into the core simultaneously using the ISCO pump. The specific experimental scheme is shown in Table 2.
Meanwhile, it is necessary to evaluate the resistance-increasing performance of the TRPS-assisted CO2 flooding process. Berea cores with a size of 3.8 cm × 20 cm and a permeability of 5 mD, 10 mD, and 20 mD were selected to evaluate the resistance-increasing effect of TRPS. The specific experimental process is as follows: (1) The core was vacuumed for 3 h and then saturated with water for more than 4 h by self-priming and calculating the porosity; (2) Connected the experiment flow chart in Figure 1a and carried out water flooding and gas flooding at a constant rate using the ISCO pump until the pressure is stable. Recorded the stable pressure P0 as the basic gas flooding pressure; (3) Injected TRPS solutions with concentrations of 200 mg/L, 500 mg/L, and 1000 mg/L at a constant rate, and recorded the stable pressure P1, respectively; (4) Carried out gas flooding again at a constant injection rate to record the pressure P1′ before gas channeling; and (5) Repeated Step (3) and Step (4) multiple times to obtain the pressures Pi and Pi′. TRPS resistance increase coefficient η(i) = Pi/P0 and resistance increase coefficient of gas flooding η′(i) = P′i/P0.

2.3.3. Profile Control Performance of TRPS

The 3.8 cm × 20 cm Berea cores with permeability of 5 mD and 20 mD were connected in parallel to simulate reservoir heterogeneity (permeability difference ratio is 4) to carry out the TRPS-assisted CO2 flooding experiment without oil. The specific experimental procedure is as follows: (1) After the core is evacuated for 3 h, it is saturated with simulated water by self-priming for more than 4 h, and the porosity is calculated; (2) The simulated formation water was injected at a constant rate by an ISCO pump, and the pressure at both ends of the core is recorded after the pressure is stable. The stable pressure difference is recorded as ΔP1, and the core water permeability is calculated by Darcy law; (3) According to Figure 1b, the experimental process was connected and simulated water and CO2 were co-injected using the ISCO pump. Recorded the liquid production conditions and injection pressure of the cores; (4) TRPS and CO2 were co-injected using the ISCO pump at a constant rate until the pressure is stable; and recorded the liquid production conditions and injection pressures of the two cores. The combined injection rate of liquid and gas is 0.6 mL/min (1:1 volume ratio), and if there is no CO2 injection, the TRPS injection rate is 0.6 mL/min. The specific experimental scheme is shown in Table 3.

2.4. EOR Efficiency of TRPS-Assisted CO2 Flooding

The oil displacement experiments were carried out using Berea cores (gas permeability is 10 mD and the water permeability is 5.19 mD). Comparing the oil recovery and pressure change law of water-assisted CO2 flooding and TRPS-assisted CO2 flooding, the advantages of TRPS-assisted CO2 flooding in improving oil recovery were clarified, and the best effect period was determined. The specific experimental procedure is as follows: (1) After the core is evacuated for 3 h, it is saturated with water by self-priming for more than 4 h, and the porosity is calculated; (2) The simulated formation water is injected at a constant rate by an ISCO pump, and the pressure at both ends of the core is recorded after the pressure is stable. The pressure difference is ΔP1, and the core water permeability is calculated by Darcy law; (3) According to the connection experiment process in Figure 1a, the ISCO pump is used to inject crude oil into the core at a constant rate until there is no water production, and the oil saturation is calculated; (4) Simulated formation water was injected with ISCO pump at a constant rate until the water cut reaches 90% and then switched to CO2 flooding until gas channeling without producing oil; (5) Injected TRPS solution (1000 mg/L) with ISCO pump at a constant rate of 0.2 PV and then switched to CO2 flooding until no oil is made again, this is a round of TRPS-assisted CO2 flooding process; (6) Repeated step (5) for a total of three times, that is, three rounds of TRPS-assisted CO2 flooding are completed. During the experiment, the fluid production and injection pressure of the core were recorded. The injection rate of liquid and gas was 0.3 mL/min. During the experiment, a back pressure of 10 MPa was applied at the outlet end of the core by a back pressure valve.

3. Result and Discussion

3.1. Static Performance Comparison between XG and TRPS

3.1.1. Viscosity-Increasing Performance

Figure 2 shows the relationship curves of the viscosity of XG and TRPS polymer solutions with the change of solution concentration at 80 ℃. The results show that both polymers have certain viscosity-increasing properties in terms of demand in the field of oil and gas field development engineering, and the viscosity-increasing effect of XG is more significant. When the solution concentration exceeds 300 mg/L, the viscosity-increasing effect of the XG solution is significantly improved, much higher than that of TRPS at the same concentration. When the solution concentration was less than 1000 mg/L, the viscosity-increasing effect of TRPS gradually increased with the increase in the solution concentration, and the change was stable. When the concentration is 1000 mg/L, the viscosities of XG and TRPS solutions are 15.21 cP and 4.57 cP, respectively. Within this concentration range, XG and TRPS have the potential of low-permeability reservoir injectability [36], meeting the requirements of follow-up research. In addition, the viscosity of TRPS solutions with concentrations of 700 mg/L and 1000 mg/L is similar to that of XG solutions with concentrations of 100 mg/L and 300 mg/L, respectively. The performance of the two solutions at the same viscosity will be compared through the above two concentrations.
Figure 3a,b show that the viscosities and retention rates of XG and TRPS solutions increase with the increase in solution concentration. The relationship between the viscosity retention rate and the solution concentration of XG and TRPS solutions after shearing at 3500 rpm is compared, as shown in Figure 3c. The viscosity retention rates of the two polymer solutions after shearing are both above 80%. Whether the viscosity is the same or the concentration is the same, the viscosity retention rate of TRPS is greater than that of XG because the viscosity-increasing mechanism of XG and TRPS mainly includes: (1) the polymer molecules in water are entangled to form a structure; (2) The hydrophilic groups in the polymer chains are solvated in water, and the apparent molecular volume of the polymer increases. XG has a more considerable molecular weight, and the larger molecular aggregates formed are more easily damaged by shearing.

3.1.2. Rheological Properties

Figure 4 shows the rheological curves of XG and TRPS with four concentrations. Figure 4 shows that the rheological curves of XG and TRPS solutions are power-law curves, showing typical shear thinning characteristics. The shear rates corresponding to the rheological curves of XG and TRPS solutions reaching the second Newton zone are about 10 1/s and 5 1/s, respectively, and the molecular conformation transition has reached the limit value. Because in the practice of oil field production, the shear rate of the polymer system in the underground is about 1–10 1/s, combined with the rheological curve, it is easier for TRPS to reach the second Newton zone in this shear rate range. The adaptability to the reservoir shearing of TRPS is more robust. Meanwhile, comparing the rheological curves of TRPS (1000 mg/L) and XG (300 mg/L) solutions with the same viscosity, it can be found that the viscosity of XG solution is higher at low shear rate, and the viscosity of the two is similar in the second Newton zone. This is mainly because the molecular weight of XG is large, and the viscosity-increasing property of the molecular coil is stronger at a lower shear rate, and as the shear rate increases, the difference between the two molecular weights for the viscosity-increasing performance decreases.

3.1.3. Temperature-Resistance and CO2-Resistance Performance

Figure 5 compares the viscosity retention curves of XG and TRPS solutions after aging in high-temperature and CO2 environments. Figure 5a shows that high temperature has a more significant effect on the viscosity of XG solution but has little impact on the viscosity of TRPS. The viscosity of the XG solution decreased rapidly with the increase in aging time, then reduced steadily after aging for ten days, and the viscosity retention rate after aging for 30 days was less than 20%. The viscosity of the TRPS solution decreased slowly with the increase in aging time, and the final viscosity retention rate was about 80%. This is because high-temperature conditions will gradually untangle the initially entangled polymer coils, and long-term aging will cause further breakage of the stretched molecular bonds, resulting in a significant decrease in the viscosity of the solution. However, TRPS has a temperature-resistant monomer and a short molecular coil, showing good temperature resistance.
Figure 5b shows that the presence of CO2 significantly reduces the viscosity of the XG solution, and the viscosity retention rate drops to about 20% after aging for ten days. However, after aging in a CO2 environment, the viscosity retention rate of TRPS solution increased first (up to more than 150%), then decreased slowly, and finally remained at about 120%. CO2 will increase H+ in the polymer solution and destroy the biomolecular chains in the XG solution, thereby losing the viscosity-increasing effect [37]. The TRPS molecular chain contains tertiary amine groups with CO2 response characteristics. The primary tertiary amine group can undergo an acid-base neutralization reaction with dissolved CO2 in aqueous solution to form a bicarbonate structure. The tertiary amine group is protonated to form a quaternary salt cation structure, and the molecular chain is hydrophilic enhanced. Therefore, the presence of CO2 leads to larger TRPS molecular aggregates and an increase in the viscosity of the system [38,39]. The specific reaction mechanism is shown in Figure 6.
In addition, it can be seen from Figure 5 that regardless of the concentration of the TRPS solution, the viscosity retention rate after high-temperature aging and CO2 environment aging is higher than that of XG. This also shows that under the same viscosity, the temperature resistance and CO2 resistance of the TRPS solution are better than XG.

3.2. Injectivity of TRPS

Figure 7 shows the TRPS injection pressure curves under three concentrations and three core permeabilities. The injection pressure increased significantly during the TRPS flooding, and it decreased slightly and then remained stable in the subsequent water displacement stage. It also showed a certain resistance-increasing ability under the condition of no CO2. RF and RFF increase with the increase in TRPS concentration and the decrease in core permeability. When the concentration of TRPS is fixed at 1000 mg/L, RF and RFF in 5 mD core are 1.36 and 1.28, respectively, indicating good injectivity. However, the RF and RFF of 1000 mg/L TRPS solution in 20 mD cores are both less than 1.1, which means that although its resistance-increasing effect is poor, its injectivity is good. RF and RFF of 500 mg/L, 1000 mg/L, and 1500 mg/L TRPS solutions in 10 mD cores are, respectively, distributed between 1.08–1.27 and 1.01–1.15, indicating that the concentration of TRPS solution will not significantly influence its injectivity. When the core permeability is greater than 5 mD, and the TRPS solution concentration is less than 1500 mg/L, RFF is close to 1, indicating that the TRPS solution has less adsorption and retention in the formation, less damage to the formation, and has good injection performance.
Figure 8 compares the hydrodynamic size of the TRPS solution and the mean pore throat size of the core. It can be found that as the concentration of TRPS solution increases, its hydrodynamic size gradually increases from 150 nm to 350 nm, and no obvious intermolecular association occurs. As the core permeability increases, the mean pore throat size increases from 470 nm to 650 nm. The mean pore throat size of TRPS is smaller than that of the core, ensuring its good injectivity performance. Meanwhile, TRPS molecules can effectively plug pore throats through the 1/2 and 1/3 bridging theory. This can explain why TRPS in Figure 7 can effectively increase the injection pressure while ensuring a low resistance coefficient.

3.3. Resistance Increasing Ablity of TRPS

Figure 9 shows the injection pressure curves of the TRPS injection, HPAM injection, and co-injection of TRPS and CO2. The injection pressure rises rapidly after HPAM injection, which is much higher than that of TRPS injection, showing that even if the viscosity of the polymer solution is the same, the molecular weight of the polymer also affects its injection performance and resistance-increasing performance. The RF of HPAM injection is 7.67, which is not significant in value, but the injection pressure rises above 2.0 MPa, and there will be a problem with too high injection pressure during the oilfield application. Meanwhile, the RFF of HPAM injection is 4.45, indicating that HPAM has a large amount of retention and adsorption in the low-permeability layer, which is not conducive to the subsequent development of the formation. However, the RF and RFF of TRPS injected are 1.13 and 1.09, respectively, and the resistance-increasing effect is poor. The injection pressure during the co-injection of TRPS and CO2 increases significantly because the more complex molecular aggregates formed after the mixing of TRPS and CO2 significantly increase its flow resistance (Figure 6). At this time, RF and RFF rose to 2.67 and 1.23, respectively, and the effect of increasing resistance was improved. Figure 9 shows that it is difficult for conventional polymers (relatively high molecular) to achieve the coordination of injectivity and resistance-increasing in low-permeability reservoirs, while the response of TRPS and CO2 allows it to be injected into the reservoir smoothly and achieve resistance increase inside the reservoir effect.
The injection pressures of multiple rounds of TRPS-assisted CO2 flooding with three kinds of permeability and three kinds of concentrations are collected and the resistance increase coefficients η and η′ of each round are shown in Table 4. Table 4 shows that η is greater than η′ in the same round because the resistance of the injected liquid must be greater than the resistance of the injected CO2. Under the same permeability conditions, η and η′ increased significantly after increasing the concentration of TRPS. When the concentration is 1000 mg/L, η can reach more than three times that when the concentration is 200 mg/L. η′ can reflect the resistance-increasing effect after the reaction of TRPS and CO2, so the relationship between η′ of the above rounds and the change of core permeability is plotted into a resistance-increasing coefficient chart, as shown in Figure 10.
When the concentration of TRPS is lower than 1000 mg/L, the increase in core permeability and alternate rounds will increase η′. This is because although the increase in permeability will reduce the injection pressure of TRPS-assisted CO2 flooding, the gas channeling pressure of CO2 flooding will also decrease, eventually increasing η′. The molecular aggregates produced by the reaction of TRPS and CO2 will be adsorbed and retained in the core, so η′ increases with the increase in injection rounds. When the concentration of TRPS is 1000 mg/L, the relationship curves of η′ change abnormally. This also shows once again the matching between TRPS and the reservoir (the low-permeability reservoir will not have unusually high pressure caused by the poor injectivity of molecular aggregates produced after the reaction of TRPS and CO2) and the cumulative effect of multiple rounds of resistance-increasing performance. When the permeability is 5 mD, the molecular aggregates formed by the reaction of TRPS and CO2 are poorly compatible with the core, resulting in an abnormal increase in injection pressure and a significant increase in η′. Then, the pore throats of the 10 mD and 20 mD cores became more prominent, and the flow capacity increased, which relieved the contradiction between the poor matching between TRPS and the core, and the change law of η′ was normal. In addition, the irregularity of η′ of the TRPS solution with a concentration of 1000 mg/L increases with the increase in injection rounds, mainly in the core with a permeability of 5 mD. This is due to the increase in retention of TRPS in the core due to the decrease in permeability.

3.4. Profle Control Effect of TRPS

Figure 11 shows the injection pressure and fractional flow rate curves of the TRPS-assisted CO2 flooding in a two-core parallel model. Figure 11 shows that the injection pressure of 1000 mg/L TRPS-assisted CO2 flooding is higher than that of TRPS flooding separately, which also leads to a more obvious reduction in the fractional flow rate of the increased permeability layer. The injection pressure of TRPS-assisted CO2 flooding with a concentration of 500 mg/L is lower than that of TRPS separately (1000 mg/L), showing that TRPS needs to reach a certain concentration before fully reacting with CO2. Combined with the resistance-increasing effect of TRPS, it can be determined that the optimal concentration of TRPS should be 1000 mg/L for reservoirs with a permeability above 5 mD and 500 mg/L for reservoirs below 5 mD.

3.5. EOR Effects of TRPS

Figure 12 shows the produced fluids and oil recovery curves of each stage for water-assisted CO2 flooding and TRPS-assisted CO2 flooding. CO2 can dissolve in crude oil and cause it to expand, reducing its viscosity [40,41], and has a higher recovery rate than air and N2. The oil recovery after CO2 flooding to gas channeling is about 46%, and liquid-assisted CO2 flooding can effectively control the gas channeling and further improve the oil recovery. Whether it is water or TRPS solution, the enhanced oil recovery of each round of the liquid injection stage is higher than that of the CO2 injection stage of the same round. TRPS-assisted CO2 flooding enhances oil recovery mainly in rounds 1 and 2, and the EOR effects are 20.71% and 10.00%, respectively. This also led to poorer EOR effects in subsequent rounds, in which the EOR in the third round was lower than that of water-assisted CO2 flooding. The main effect period of water-assisted CO2 flooding is in the first three rounds, but the overall EOR effect is 8.21% lower than that of TRPS-assisted CO2 flooding. The ultimate recovery of TRPS-assisted CO2 flooding and water-assisted CO2 flooding can reach 78.93% and 71.07%, respectively.
Appendix A Table A1 compares the EOR effects of different CO2 enhancement injections. It can be found that compared with the ultrasonic physical method and another polymer-assisted CO2 displacement, the TRPS used in this paper has a significantly better EOR effect. In the literature review, only two scenarios obtained higher EOR than this paper (the bolded items in Appendix A Table A1). The first scenario is for heavy oil reservoirs, where CO2 or WAG recovery is very low due to the extremely unfavorable mobility ratio, so the effect of polymer-assisted CO2 displacement is remarkable. The second scenario is gel particle-assisted CO2 flooding, and the research target is parallel cores. Because the profile improvement effect of gel particles is stronger than that of polymers, its EOR effect in heterogeneous reservoirs is remarkable. Therefore, the TRPS-assisted CO2 flooding in this paper has a considerable EOR effect of 32.93% compared with CO2 flooding and 8.21% compared with water-assisted CO2 flooding.
Figure 13 is the pressure difference comparison curve of water-assisted CO2 flooding and TRPS-assisted CO2 flooding. The increase in injection pressure during the liquid injection is more significant than that of the gas injection, which can also explain the better EOR effect of each round of liquid injection in Figure 12. For water-assisted CO2 flooding, the gas-injection pressure in each round is close to the initial gas channeling pressure, indicating that gas–water alternation can increase the flow resistance of two-phase flow to a certain extent, but the gas channeling will quickly occur and form a dominant channel again. However, the CO2 injection pressure of each round of TRPS-assisted CO2 flooding is significantly higher than that of water-assisted CO2 flooding because the molecular aggregates produced by TRPS can effectively increase the flow resistance and adsorption time in the channeling channel. Figure 13 shows that, whether water or TRPS solution, the injection pressure of each round of the water injection stage and the end of the CO2 injection stage is significantly higher than that of the previous round, which has a significant cumulative effect. The higher injection pressure is the main reason for the quicker effect of TRPS-assisted CO2 flooding and better EOR effect. The injection pressure of liquid-assisted CO2 flooding will continue to increase with the injection round, but the EOR will drop significantly after the third round, so the optimal development round should be three. In addition, the increased injection pressure difference of liquid-assisted CO2 displacement can not only expand the swept volume [42], but also effectively promote the dissolution of CO2 into crude oil and reduce its viscosity. The high-pressure CO2 environment will reduce the viscosity of the TRPS solution, but the viscosity of crude oil will be reduced to a greater extent, so TRPS-assisted CO2 flooding has good EOR potential.

4. Conclusions

This paper investigated the improvement of CO2 channeling in low-permeability reservoirs by polymer solutions. Through the experimental evaluation of the static properties, flow properties, resistance-increasing effect, and EOR effect of the polymer solution, the polymer surfactant (TRPS) with CO2 response was selected as the assisted agent, which has a good application effect. The specific conclusions are as follows:
(1)
TRPS has a certain viscosity-increasing property, and the viscosity of the solution is 4.57 cP when the concentration is 1000 mg/L. It has good temperature resistance, and its viscosity retention rate is above 80% after aging at 80 °C for 30 days. In addition, TRPS can react with CO2 to increase the size of molecular aggregates significantly, and the viscosity retention rate is about 120% after aging in a CO2 environment for 10 days.
(2)
The RF and RFF of the TRPS solution with a concentration of 1000 mg/L in 5 mD cores are 1.36 and 1.28, respectively, showing good injectivity performance. Increasing the concentration of TRPS to 1500 mg/L had little effect on its injectivity performance.
(3)
The injection pressure of TRPS and CO2 co-injection is between the injection of HPAM with the same viscosity and the injection of TRPS solution alone, which has good flow performance and resistance-increasing effect. The η and η′ of TRPS-assisted CO2 flooding increase with increased permeability, concentration of TRPS solution, and injection rounds. When the permeability is 5 mD, the base pressure of gas channeling is high, which will reduce the matching system between TRPS and the reservoir, thus affecting the change law of η′.
(4)
The effect of TRPS solution on profile improvement: 1000 mg/L TPRS + CO2 > 1000 mg/L TRPS > 500 mg/L TRPS + CO2, considering the η′ and profile improvement effect, the application concentration of TRPS should be 1000 mg/L.
(5)
The EOR effect of TPRS-assisted CO2 flooding is 8.21% higher than that of water-assisted CO2 flooding. The EOR effect of TRPS-assisted CO2 displacement is mainly reflected in the first to second rounds, while the EOR effect of water-assisted CO2 displacement is primarily reflected in the first to third rounds. The injection pressure of liquid-assisted CO2 flooding has a cumulative impact of multiple rounds, so the optimal injection round is 3.

Author Contributions

Methodology, X.C.; Investigation, X.C.; Resources, X.S.; Data curation, Z.L.; Writing—original draft, X.C.; Writing—review & editing, Z.L. and J.L.; Supervision, Y.L. and S.L.; Project administration, Y.L. and S.L. All authors have read and agreed to the published version of the manuscript.

Funding

The work was supported by the National Natural Science Foundation of China (Grant 52074318, 52174032, 52304035), the China Scholarship Council (No. 202106440061).

Institutional Review Board Statement

Not applicable.

Data Availability Statement

Not applicable.

Acknowledgments

This work was supported by the National Natural Science Foundation of China (Grant 52074318, 52174032, and 52304035) and the China Scholarship Council (No. 202106440061). The authors express their appreciation to technical reviewers for their constructive comments.

Conflicts of Interest

Author Xin Chen was employed by the company Xi’an Shiyou University. 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.

Appendix A

Table A1. EOR comparison of CO2 flooding with different strengthening methods.
Table A1. EOR comparison of CO2 flooding with different strengthening methods.
NumberLiteratureContentsAgentModelsEOR
0This paperPolymer-assisted CO2 floodingCO2-responsive polymer, TRPSCores, 5–20 mDBased on CO2 flooding is 32.93%;
based on water-assisted CO2 flooding is 8.21%
1Chaturvedi [43]Polymer-enhanced carbonated water injectionPAMSandpack, ~780 mDBased on water flooding is 16.00%
2Zhao [44]CO2 foamAOSMicrofludicBased on water flooding is 13.8–22.4%
3Hossein [45]Ultrasound-assisted CO2 flooding/SandpackBased on CO2 flooding is less than 15%
4Li [42]Polymer-assisted CO2 floodingPolymerSimulation, 1–2000 mDBased on water flooding ranges from 20–30%
5Luo [33]Polymer-assisted CO2 floodingThermo- and CO2-triggered copolymerCoreBased on water flooding is 21–23%
6Yang [46]Polymer-assisted CO2 flooding in heavy oil reservoirPolymerSimulation, 500 mDBased on WAG is 57%
7Gandomkar [47]Polymer thickening CO2 floodingPolydimethylsiloxane (PDMS)Core, 6–8 mDBased on CO2 flooding is 6–15%
8Manan [48]Polymer/surfactant/nano-particles assisted CO2 floodingAOS, NPs (TiO2, CuO, SiO2, and Al2O3)SandpackBased on water flooding is about 5.1–15.6%
9Zaberi [49]Polymer-assisted CO2 floodingPolyfluoroacrylate (PFA)Berea sandstone, ~31 mDBased on CO2 flooding is 16%
10Liu [5]Microgel alternate CO2MicrogelCore, 2800 mD/780 mD/360 mDBased on WAG is 12.4%

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Polymers 15 03886 g001
Figure 1. The flowchart of the flow performance of the TRPS solution. (a) Single core flooding flow chart, suitable for injectivity ability testing, resistance-increasing performance testing, and EOR efficiency evaluation. (b) Two-core parallel core flooding flow chart, suitable for profile control performance evaluation.
Figure 1. The flowchart of the flow performance of the TRPS solution. (a) Single core flooding flow chart, suitable for injectivity ability testing, resistance-increasing performance testing, and EOR efficiency evaluation. (b) Two-core parallel core flooding flow chart, suitable for profile control performance evaluation.
Polymers 15 03886 g001
Polymers 15 03886 g002
Figure 2. The viscosity-increasing ability of XG and TRPS.
Figure 2. The viscosity-increasing ability of XG and TRPS.
Polymers 15 03886 g002
Polymers 15 03886 g003
Figure 3. Viscosity and viscosity retention rate of polymer solution after shearing, (a) XG, (b) TRPS, (c) comparison of viscosity retention rate.
Figure 3. Viscosity and viscosity retention rate of polymer solution after shearing, (a) XG, (b) TRPS, (c) comparison of viscosity retention rate.
Polymers 15 03886 g003
Polymers 15 03886 g004
Figure 4. The rheological curve, (a) XG, (b) TRPS.
Figure 4. The rheological curve, (a) XG, (b) TRPS.
Polymers 15 03886 g004
Polymers 15 03886 g005
Figure 5. The viscosity retention ratio of XG and TRPS solutions, (a) high-temperature aging, (b) CO2 environment.
Figure 5. The viscosity retention ratio of XG and TRPS solutions, (a) high-temperature aging, (b) CO2 environment.
Polymers 15 03886 g005
Polymers 15 03886 g006
Figure 6. Schematic diagram of the mechanism of viscosity increase in response to TRPS and CO2.
Figure 6. Schematic diagram of the mechanism of viscosity increase in response to TRPS and CO2.
Polymers 15 03886 g006
Polymers 15 03886 g007
Figure 7. TRPS injection pressure curve. (a) The TRPS concentration is 1000 mg/L, and the core permeability is 5 mD, 10 mD, and 20 mD. (b) The core permeability is 10 mD, and the TRPS concentration is 500 mg/L, 1000 mg/L, and 1500 mg/L.
Figure 7. TRPS injection pressure curve. (a) The TRPS concentration is 1000 mg/L, and the core permeability is 5 mD, 10 mD, and 20 mD. (b) The core permeability is 10 mD, and the TRPS concentration is 500 mg/L, 1000 mg/L, and 1500 mg/L.
Polymers 15 03886 g007
Polymers 15 03886 g008
Figure 8. Comparison of the pore throat sizes of cores and the hydrodynamic sizes of TRPS solutions.
Figure 8. Comparison of the pore throat sizes of cores and the hydrodynamic sizes of TRPS solutions.
Polymers 15 03886 g008
Polymers 15 03886 g009
Figure 9. The injection pressure curves of TRPS injection, HPAM injection, and co-injection of TRPS and CO2.
Figure 9. The injection pressure curves of TRPS injection, HPAM injection, and co-injection of TRPS and CO2.
Polymers 15 03886 g009
Polymers 15 03886 g010
Figure 10. The resistance-increasing coefficient chart.
Figure 10. The resistance-increasing coefficient chart.
Polymers 15 03886 g010
Polymers 15 03886 g011
Figure 11. TRPS-assisted CO2 parallel flooding characteristic curves. (a) Injection pressure curves, (b) fractional flow rate curve.
Figure 11. TRPS-assisted CO2 parallel flooding characteristic curves. (a) Injection pressure curves, (b) fractional flow rate curve.
Polymers 15 03886 g011
Polymers 15 03886 g012
Figure 12. Experimental photos and data analysis of water-assisted CO2 flooding and TRPS-assisted CO2 flooding. (a) Liquid production photos, (b) EOR curves of each round.
Figure 12. Experimental photos and data analysis of water-assisted CO2 flooding and TRPS-assisted CO2 flooding. (a) Liquid production photos, (b) EOR curves of each round.
Polymers 15 03886 g012
Polymers 15 03886 g013
Figure 13. The injection pressure difference curves of water-assisted CO2 flooding and TRPS-assisted CO2 flooding.
Figure 13. The injection pressure difference curves of water-assisted CO2 flooding and TRPS-assisted CO2 flooding.
Polymers 15 03886 g013
Table 1. The experimental scheme of TRPS injectivity properties.
Table 1. The experimental scheme of TRPS injectivity properties.
Polymer Concentration, mg/LGas Permeability, mDWater Permeability, mDCore Volume, cm3Pore Volume, cm3Porosity, %
100052.99226.724.3210.73
500105.36226.734.2815.12
1000105.23226.735.8215.8
2000105.38226.7133.5614.80
10002010.12226.7143.8019.32
Table 2. Scheme of the evaluation of the resistance-increasing performance of TRPS.
Table 2. Scheme of the evaluation of the resistance-increasing performance of TRPS.
SolutionViscosity, cPInjection CO2Gas Permeability, mDWater Permeability, mDPorosity, %
TRPS9.3Yes105.2015.51
HPAM10.1No105.3614.98
TRPS9.3No105.3215.11
Table 3. TRPS profile control effect experimental scheme.
Table 3. TRPS profile control effect experimental scheme.
SolutionConcentration, mg/LInjection CO2Gas Permeability, mDWater Permeability, mD
TRPS500Yes5/203.12/9.98
TRPS1000No5/203.03/10.20
TRPS1000Yes5/203.21/10.15
Table 4. η and η′ of each round of TRPS-assisted CO2 flooding.
Table 4. η and η′ of each round of TRPS-assisted CO2 flooding.
ParametersRound 1Round 2Round 3Round 4
Permeability, mDConcentration, mg/LGas Channeling Pressure, MPaηη′ηη′ηη′ηη′
52000.251.961.363.081.723.922.125.603.16
5000.332.701.556.182.21////
10000.316.746.5311.210.816.115.722.922.5
102000.132.201.733.232.204.962.609.374.17
5000.155.002.609.533.47////
10000.148.436.9312.47.8620.010.028.013.2
202000.072.571.864.433.147.435.4310.47.14
5000.087.504.1314.15.75////
10000.088.505.2518.07.1329.114.642.317.7
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Chen, X.; Li, Y.; Sun, X.; Liu, Z.; Liu, J.; Liu, S. Investigation of Polymer-Assisted CO2 Flooding to Enhance Oil Recovery in Low-Permeability Reservoirs. Polymers 2023, 15, 3886. https://doi.org/10.3390/polym15193886

AMA Style

Chen X, Li Y, Sun X, Liu Z, Liu J, Liu S. Investigation of Polymer-Assisted CO2 Flooding to Enhance Oil Recovery in Low-Permeability Reservoirs. Polymers. 2023; 15(19):3886. https://doi.org/10.3390/polym15193886

Chicago/Turabian Style

Chen, Xin, Yiqiang Li, Xiaoguang Sun, Zheyu Liu, Jianbin Liu, and Shun Liu. 2023. "Investigation of Polymer-Assisted CO2 Flooding to Enhance Oil Recovery in Low-Permeability Reservoirs" Polymers 15, no. 19: 3886. https://doi.org/10.3390/polym15193886

APA Style

Chen, X., Li, Y., Sun, X., Liu, Z., Liu, J., & Liu, S. (2023). Investigation of Polymer-Assisted CO2 Flooding to Enhance Oil Recovery in Low-Permeability Reservoirs. Polymers, 15(19), 3886. https://doi.org/10.3390/polym15193886

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