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Dispersed Particle Gel Strengthened Polymer/Surfactant as a Novel Combination Flooding System for Enhanced Oil Recovery guang zhao, Jiaming Li, Chenglin Gu, Lin Li, Yongpeng Sun, and Caili Dai Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b02720 • Publication Date (Web): 05 Oct 2018 Downloaded from http://pubs.acs.org on October 15, 2018

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Energy & Fuels

Dispersed Particle Gel Strengthened Polymer/Surfactant as a Novel Combination Flooding System for Enhanced Oil Recovery

Guang Zhao*, Jiaming Li, Chenglin Gu, Lin Li, Yongpeng Sun, Caili Dai*

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, Shandong 266580, People’s Republic of China

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*Corresponding Authors. Tel.: +86-532-86981183 Email: G.Z: [email protected]; C. D.: [email protected]

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ABSTRACT A novel dispersed particle gel strengthened polymer-surfactant (DPS) combination flooding system was proposed and demonstrated for enhanced oil recovery in high water cut mature oilfields. Compared with a conventional polymer-surfactant (PS) combination flooding system, DPS systems have a higher viscosity and a more stable network structure. The polymer is mainly a source of the viscosity, while the surfactant plays a key role in reducing the interfacial tension (IFT). The added dispersed particle gel (DPG) has a synergistic viscosity increase effect, whereas for the DPG particles, the salinity and aging time have a slight effect on the IFT reduction capacity of the DPS system. Based on sandpack flowing experiments, the DPS system has a better mobility control capacity than the PS system in the combination flooding stage and the following water flooding stage. Parallel sand-pack flowing experiments indicate that injection of a DPS system can effectively improve the profile control. The added DPG particles could intersperse in the three-dimensional network structure, which increases the stability of the DPS system in solution and porous media. Through the improved synergistic effect of the swept volume capacity and high displacement efficiency, the oil recovery capacity of the DPS system is significantly enhanced. The DPS system may be an alternative for enhanced oil recovery in other similar high water cut mature oilfields.

KEYWORDS: DPS combination flooding system; DPG particles; morphology; enhanced oil recovery


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1. INTRODUCTION Water flooding is one of the most commonly used and economical treatments in the oilfield development process, accounting for more than 50% of global oilfield development treatments. Water injection can effectively provide additional energy to maintain formation pressure when the natural reservoir energy is depleted. Approximately 20-40% of crude oil is typically driven out via water flooding treatment. However, oil recovery becomes more difficult when conducted after long-term water flooding treatments. The changes of the water-oil flow ratio and reservoir homogeneity cause difficulties for further enhanced oil recovery.1-3 Generally, the viscosity of the water is lower than the viscosity of oil, which brings a lower water-oil flow ratio in the water flooding stage, thus resulting in the injected water being easily channeled from the injection wells to the oil production well. Additionally, the permeability of the reservoirs significantly increases after long-term water flooding, which exacerbates the heterogeneity of these reservoirs and forms water channels that decrease the necessity for water flooding treatment. The changes in both the water-oil flow ratio and reservoir homogeneity can reduce the swept volume of injected water, thus decreasing the amount of oil recovered. Therefore, improving the water-oil flow ratio and reducing the formation heterogeneity have become urgent problems for oil recovery in oilfields. Recently, successful applications of micro-gel flooding technology

4-6

and polymer

flooding technology 7-12 have emerged in worldwide oilfield trials. The micro-gel is usually formed by polymer and cross-linkers under reservoir conditions. However, the critical cross-link concentration of the polymer and cross-linkers in the micro-gel system is significantly lower than the gelation concentration. For example, the polymer concentration of micro-gel is usually in the range of 300~1200 mg/l, and the cross-linking


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ratio of polymer to cross-linker is set as 20:1~100:1. The lower concentration and crosslinking ratio have inherent drawbacks, which may lead to a poor water production control. Due to the polymer in micro-gel systems, the shear degradation due to the injection device and seepage shearing in formation, and dilution caused by contacting with the reservoir minerals and fluids are inevitably generated. The effective content of polymer reduces which brings an uncertainness of cross-linking. It limits the development of micro-gel technology application in oilfields. For the polymer systems, the polymers used in the flooding are a viscoelastic system which could increase the viscosity of injected water. This will improve the water-oil flow ratio and produce a higher flow resistance of injected water when flowing in the porous media of the formation. The increased viscosity causes the polymer flooding to act via a piston-like displacement effect.13-15 The swept volume is then enhanced. Additionally, the injected polymers preferentially enter into high permeability zones, which could increase the flow resistance and divert the following fluid into un-swept zones; thus, the formation heterogeneity is reduced, and the oil recovery is improved. Based on the improvement in the water-oil flow ratio and profile control, PS combination flooding technology has been further developed. The added surfactant reduces the IFT, which could improve the displacement efficiency of PS systems. Through the synergetic effect of the swept volume and displacement efficiency, the oil recovery can be significantly improved. Although polymers or PS flooding technologies based on polymers have been successfully used in oilfield trials, inherent shortcomings still exist.16-20 The improvement of the water-oil flow ratio and swept volume mainly depends on the polymer’s viscosity in the flooding systems. However, the viscosity based on the polymer systems is easily affected by shear degradation and the dilution effect in porous media. The system’s viscosity is significantly reduced when the system is returned to water flooding after combination flooding. This causes weak water-oil flow ratio and profile control when the system flows in porous media and then produces a rapid drop in the injection pressure. Therefore, it is difficult to obtain long-term validity for enhanced oil recovery of polymer


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systems. Although a large amount of polymers is injected into the formation to avoid a reduction of viscosity, it is not a good idea to enhance oil recovery by continuous injection of polymer systems. To overcome problems of the polymer systems, particles are added to improve the stability of polymer system or PS system. Currently, most researches are focused on silica nanoparticle augmented other chemical agents like polymer system or PS system to change the fluid’s property like, viscosity, IFT, stability and so on.21-23 When adding silica nanoparticles into polymer flooding system or polymer/surfactant (PS) combination flooding system, the silica nanoparticles could be interspersed in the network of polymer by hydrogen bonding and electrostatic interaction. The added silica nanoparticles could obviously improve the stability of polymer in the polymer flooding stage or PS combination flooding stage.24-26 It brings a higher flow resistance in the combination flooding stage and following water flooding. Although the stability of polymer viscosity is obviously improved when adding silica nanoparticles, the improvement of the water-oil flow ratio and swept volume mainly depends on the polymer’s viscosity in the flooding systems. Due to shear degradation and dilution effect in porous media, the system’s viscosity is significantly reduced when returned to water flooding after polymer flooding or PS combination flooding. Therefore, the viscosity is no longer the main forces for the water-oil flow ratio and profile control in the following water flooding stage. Additionally, the size of throat hole are usually micron size distribution in the polymer flooding or PS combination flooding reservoirs. It is difficult for the retained silica nanoparticles to plug these throat holes in theses reservoirs. Therefore, it is difficult to obtain long-term validity for enhanced oil recovery of polymer systems in the following water flooding stage. To further enhance the stability of polymer system, mobility control capacity and profile control capacity, a novel strengthened DPS combination flooding system is initially used by adding DPG particles. In our group’s previous studies, we have reported that DPG particles have excellent characteristics, such as softness, viscoelasticity, high-temperature


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tolerance, thermal stability, and high expansion.

27-29

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DPG particles can also effectively

improve the profile control through direct plugging or bridging across pore throats in the formation. These characteristics demonstrate a great potential for the strengthened DPS system. In this work, the synergistic effect among DPG particles, polymers and surfactant, mobility control, profile improvement capacity, and enhanced oil recovery are systematically investigated. Moreover, a detailed study on the distribution behaviors in solution and porous media are also conducted. Through the experimental results, the enhanced oil recovery mechanism of the DPS combination flooding system is proposed. Moreover, the DPS combination flooding treatment proposed in this work shows promise as an acceptable alternative to the conventional PS combination flooding treatment for enhanced oil recovery in other high water cut mature oilfields. 2. Experimental procedures 2.1. Materials. Hydrophobically associating polymer (HAP) with a hydrolysis degree of 20% and an average molecular weight of 18,000,000 were obtained from Gaoyuan Co. Ltd. (Dongying, China). The used surfactant was a compounding system consisting of tetradecyl sulfobetaine (THSB) and fatty alcohol polyoxyethylene ether sulfate (AES), with the mass ratio of THSB to AES set at 1:1. The viscosity of simulated oil was 20 mPa·s at 60 °C, which was provided by the Daqing oilfield in China. The salinity of the used simulated water was 5000 mg/l (NaCl: 4700 mg/l; CaCl2: 200 mg/l; MgCl2: 100 mg/l). The DPG particles were prepared by using a high-speed shearing method in our laboratory.27 In brief, the preparation procedures are divided into two stages: the bulk gel cross-linking reaction stage and the DPG particle milling stage. (1) Bulk gel cross-linking reaction stage: the polymer solution is first diluted with the mass concentration of 0.3% using brine (salinity: 400 mg/l); then phenolic resin crosslinker is dropped slowly into the polymer solution, which is consequently stirred to produce uniform gelation solution at room temperature. Next, 2000 mL of the gelation solution is injected into sealed jars, and the crosslinking reaction is initiated in the oven at 95 oC for 6


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hours. In the experiment, the concentration of phenolic resin cross-linker is set as 0.9%. (2) DPG particle milling stage: 1000 g for each brine water and bulk gel are mixed with a colloid mill (CM-2000 type, Shanghai Yiken Instruments Ltd., China) at a rotation speed of 45 Hz for 15 min at the room temperature. Finally, the yellowish solution is the obtained DPG products. The size of DPG particles is measured at 30 °C using a scanning electron microscopy (SEM, Hitachi S-4800, Hitachi High-Technologies Co., Ltd.) and dynamic light scattering (DLS, Bruker-Nano, Bruker Instruments Ltd.), and the averaged size was 2 μm (Figure 1) in all the experiments.

Figure 1. The morphology and average size of DPG particles, (a) morphology; (b) size distribution.

2.2. Characterization of DPS combination flooding system. A TX-500C interfacial tensiometer (Kono Industrial Co., Ltd., UAS) was used to determine the IFT of the DPS system. A Brookfield DV-2 viscometer (Brookfield Viscometers Ltd., Harlow, UK) was used to demine the viscosity of the DPS system, with the shear rate set to 6 rpm at 60 °C. Hitachi S-4800 scanning electron microscopy measurements (SEM, Hitachi, Japan) were used to investigate the morphologies of the PS and DPS system. 2.3. Measurement of mobility control capability. In the experiments, the resistance factor was used to evaluate the mobility control capability. The mobility control capabilities of PS (0.25% polymer+0.25% surfactant) and DPS (0.06% DPG particle + 0.25% polymer+0.25% surfactant) were compared via single sand-pack flow experiments (Figure


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2) at 60 oC. The PS solution or DPS solution at 1.0 pore volume (PV) was injected into sand-packs (length: 10 cm, diameter: 2.5 cm) and then water flooding followed until a stable pressure was achieved, and the injection pressure was recorded to calculate the resistance factor. In this process, the injection flowing rate was set as 1 ml/min.

Figure 2. Single sand-pack flow chart.

2.4. Measurement of profile improvement capacity. Parallel sand-packs models (Figure 3) were used to evaluate the profile improvement capacity of the DPS system at 60 oC.

When conducting these experiments, 1 PV of DPS solution (0.06% DPG particle + 0.25%

polymer+0.25% surfactant) was injected into the parallel sand-packs and then water flooding followed until a stable pressure and produced fluid were achieved. The pressure and produced fluid were used to calculate the profile improvement rate. In this process, the injection flowing rate was set as 1 ml/min.


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Figure 3. Parallel sand-pack flow chart.

2.5. Measurement of enhanced oil recovery capacity. The enhanced oil recovery capacities of PS (0.25% polymer+0.25% surfactant) and DPS (0.06% DPG particle + 0.25% polymer+0.25% surfactant) were evaluated using the single sand-pack flow model (Figure 2) at 60 oC. The sand-pack (length: 9 cm, diameter: 2.5 cm) was subsequently saturated with simulated water and simulated oil. Then, water flooding was conducted on the sandpack until the water cut reached 98%. Next, the sand-pack was injected with 1 PV of a PS solution or DPS solution. Finally, water flooding was conducted on the sand-pack again until the produced fluid and injected pressure reached a stable state. The injection flowing rate was set as 0.5 ml/min in the experiments, the permeability and porosity of the sandpack were 0.5 μm2 and 38%, respectively, and the initial oil saturation was 81.3%. 3. RESULTS AND DISCUSSION

3.1. Factors influencing the viscosity and IFT of the DPS combination flooding system 3.1.1 Effect of the DPG concentration. High viscosity and low IFT are the key indicators in the DPS combination flooding process. A high viscosity usually produces a higher swept volume, while a low IFT improves the displacement efficiency. Therefore, the effects of the DPG concentration on the viscosity and IFT of the DPS system are investigated in the experiments. Figure 4 (a) shows that there is almost no effect on the


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viscosity when the DPG particles have a low concentration. However, the difference of the viscosity between PS systems and DPS g systems increases with the DPG particle concentration. The viscosity of polymer system (i.e., 0.25% polymer + 0.2% surfactant) is 244.3

mPa·s, while the viscosity of DPS combination flooding system (i.e., 0.25%

polymer + 0.2% surfactant + 0.15% DPG) increases to 267 mPa·s when DPG particles are added. This relates to the intrinsic characteristics of the DPG particles. The particles are prepared in a high viscoelastic bulk gel. Although the viscosity of the bulk gel is significantly reduced due to the high-speed shearing force, the formed DPG particles still have a low viscosity during the preparation process. The added low viscosity of the DPG particles could increase the viscosity of the DPS system. A higher concentration of DPG particles usually produces a higher solid content of the DPS system. This phenomenon can reduce the distance between the particles and increase the collision probability of particles, resulting in a high inner friction among these particles; then, the viscosity of the combination flooding system will increase. Moreover, the DPG particles can be interspersed in the network structure of the polymer, which further synergistically increases the viscous forces in the solution. Figure 4 (b) shows that the IFT of the DPS system slightly increases with the DPG particle concentration. A reason for this phenomenon could be the adsorption behavior of the surfactant. Due to the hydrophobic interaction, the surfactant molecules could adsorb on the DPG particle surface, which would reduce the amount of surfactant molecules at the oil-water interface. Moreover, the DPG particles could occupy and reduce the adsorption sites of the oil-water interface. Therefore, the surfactant molecules adsorbed on the oil-water interface are reduced; then, the IFT increases with the DPG particle concentration in the combination flooding system.


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Figure 4. The viscosity and IFT changes of the DPS system with DPG concentration: (a) viscosity changes; (b) IFT changes.

3.1.2 Effect of HAP polymer concentration. The HAP polymer is the main source of viscosity in the DPS system. It directly affects the mobility control capacity and the swept volume in the combination flooding process. In the experiments, 0.06% DPG particles and 0.25% surfactant are used, and the polymer concentration ranges from 0.05% to 0.3%. The results are presents in Figure 5. Figure 5 (a) shows that the HAP polymer has a great effect on the viscosity of the DPS system. The viscosity of the DPS system is less than 30 mPa·s when the polymer concentration is less than 0.1%. However, the viscosity of the DPS system substantially increases when the polymer concentration is greater than 0.15%. This may be related to the critical association concentration (CAC) of the HAP polymer in the DPS system.30-33 When the HAP polymer concentration is lower than that of the CAC, the molecules are mainly present in the form of single molecules in the solution, which reduces the probability of hydrophobic interactions between polymer molecules. The structure viscosity of the HAP polymer cannot be formed, which produces a lower viscosity. When the HAP polymer concentration is higher than the CAC, the polymer structure will change in the solution. Due to the increased numbers of polymer molecules in the solution, the probability of hydrophobic association increases. More polymer molecules will be involved in the hydrophobic interaction, which could form a three-dimensional network structure in the DPS combination flooding solution. A higher polymer concentration of the


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DPS system usually leads to a stronger hydrophobic association. As a result, the viscosity of the DPS system rapidly increases when the polymer concentration is greater than 0.15%. Additionally, the added DPG particles could intersperse in the network structure of the polymer, which would further strengthen the crosslinking density of the network structure. As a result, the viscosity of the DPS system is slightly higher than that of the PS system. However, the IFT of the DPS system rises when increasing the polymer concentration (Figure 5 (b)). The high viscosity of the DPS system affects the delivery and adsorption of the surfactant molecules from the solution phase to the oil-water interface.34, 35 Moreover, the high concentration of polymer systems usually leads to adsorption of more surfactant molecules on the network structure, which may decrease the number of surfactant molecule at the oil-water interface. As a result, the IFT of the DPS system increases with the polymer concentration.

Figure 5. The viscosity and IFT changes of the DPS system with polymer concentration: (a) viscosity changes; (b) IFT changes.

3.1.3 Effect of surfactant concentration. A low IFT is one of the most important characteristics in the DPS combination flooding process. In the experiments, 0.06% DPG particles and 0.25% polymer are used, and the surfactant concentration ranges from 0.05% to 0.3%. The experimental results show that the viscosity of the DPS system increases when increasing the surfactant concentration. However, the viscosity value only increases from 253 mPa·s to 256 mPa·s (Figure 6 (a)). The slightly increased viscosity may be related


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to the adsorption behavior of the surfactant. 36, 37 Although the surfactant system is a thin solution, the surfactant molecules could adsorb onto the DPG particle surfaces or polymer network structures via a hydrophobic interaction. This adsorption behavior could strengthen the hydrophobic interaction between hydrophobic groups in the DPS solution. Therefore, the viscosity of the DPS combination flooding system increases. In contrast, Figure 6 (b) shows that a higher surfactant concentration produces a lower IFT. A higher surfactant concentration usually generates more surfactant molecules, which could adsorb at the oil-water interface, greatly reducing the IFT. However, desorption behavior and adsorption behavior of surfactant molecules simultaneously exist at the oil-water interface. When the surfactant concentration is over a certain value, desorption and adsorption can reach a dynamic equilibrium state. Therefore, the IFT value is almost not changed with the increasing surfactant concentration.

Figure 6. The viscosity and IFT changes of the DPS system with surfactant concentration: (a) viscosity changes; (b) IFT changes.

3.1.4 Effect of salinity. When the DPS system is dissolved by simulation water in porous media, it inevitably contacts with salt ions. The high viscosity of the system in salt water is important for the combination flooding treatment. In this section, the effect of the salinity on the DPS combination flooding system (0.06% DPG + 0.25% polymer + 0.25% surfactant) is investigated. Figure 7 shows that the viscosity of the DPS system increases with the salinity. However, the viscosity begins to decrease when the salinity is higher than


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5000 mg/l. The special structures of the HAP polymer in the DPS combination flooding system are the driving force for the different viscosities. Electrostatic repulsion and hydrophobic association coexist in the HAP polymer. When a sodium ion is added into the solution, the ion shields the electrostatic repulsion between the carboxyl ion groups. Therefore, the hydrophobic association between the HAP polymer molecules becomes easier, and the HAP polymer chains freely stretch in the solution. As a result, a threedimensional network structure is formed in the DPS combination flooding solution, resulting in a viscosity increase in the solution. However, when the salinity continues to increase, the shielding effect between the carboxyl ion groups is enhanced, which leads to the polymer chains being curled and a reduction of the hydrodynamic radius. 38-40 Thus, the binding force of the three-dimensional network structure in the DPS combination flooding solution weakens, and the viscosity decreases. Additionally, the salinity has a slight effect on the IFT of the DPS system. This can be attributed to the fact that the used surfactant is a sulfonate betaine surfactant, which contains salt-tolerant sulfonic acid groups. The groups could produce a chelation effect when ions exist in the salt water. Therefore, they can enhance the salinity resistance of the DPS system when conducting combination flooding in a higher salinity reservoir.

Figure 7. The effect of salinity on the viscosity and IFT of the DPS system: (a) viscosity changes; (b) IFT changes.

3.1.5 Effect of aging time. Thermal stability is very important for the long-term validity


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of DPS combination flooding systems. In the section, the viscosity and IFT changes of the system (0.06% DPG + 0.25% polymer + 0.25% surfactant) were determined. From Figure 8 (a), it can be observed that the viscosity decreases when the system is continuously aged at 60 °C. However, the viscosity reduction rate is less than 10% after aging for 50 days. This can be attributed to the special association structures and DPG particles in the DPS system. The association structure is a dense three-dimensional structure that cannot be easily degraded under these conditions. Additionally, the DPG particles could be combined to form aggregates, which could improve the strength of the three-dimensional structure in the combination flooding system. Therefore, the viscosity can still be maintained at a high value after long-term aging under the reservoir conditions. Figure 8 (b) further shows that the IFT increases with the increasing aging time, and the final IFT is still in the range of 10-1 mN/m and 10-2 mN/m. Although an increase in the aging time could decrease the IFT reduction capacity, the effect of long-term aging is slight. The reasons for this phenomenon could be the anionic hydrophilic groups and cationic hydrophilic groups in the DPS systems. These two groups have good temperature and salt resistance capacities, which strengthen the adsorption capacity of the surfactant molecules at the oil-water interface. Therefore, the DPS system still has a better IFT reduction capacity after long-term aging under the reservoir condition.

Figure 8. Viscosity and IFT changes of the DPS system with aging time: (a) viscosity changes; (b) IFT changes.


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3.2. Profile control capacity of the DPS combination flooding system

3.2.1 Mobility control capacity. Figure 9 shows the changes in the resistance factor in the PS and DPS systems. It can be seen that both resistance factors are greater than 50 in the combination flooding stage. These results indicate that injections of PS and DPS systems can improve the formation profile. Due to the selective capacity of the combination flooding system, the viscoelastic solution preferentially enters and retards in the high permeability channels. The viscosity of the combination flooding system plays an important role in improving the mobility control at this stage. Through the viscosity increase in the water, the water permeability can be effectively reduced. Additionally, the polymer molecules of the combination flooding system can adsorb onto the sand surface via hydrogen bonding. This reduces the effective radius of the pore throat and further increases the flow resistance. Therefore, the combination flooding system obtains a high resistance factor during the injection stage. However, the resistance factor of the DPS system is higher than that of the PS system (Figure 9 and Figure 10). The differences can be related to the plugging behavior of DPG particles in the DPS system. The DPG particles can directly plug or bridge across the pore throats, which improves the profile control of reservoirs. Additionally, the synergetic thickening effect of DPG particles can enhance the viscosity of the DPS system. As a result, the resistance factor of the DPS system has a higher resistance factors. However, the resistance factors of these two combination flooding systems have significant differences when the sand-packs are changed to the following water flooding stage. The resistance factor of the PS system decreases more rapidly than that of the DPS combination flooding system (Figure 9). For the PS combination flooding system, the viscosity is the driving force for the mobility control. In the following water flooding stage, the polymer in the PS combination flooding system can be easily diluted by contacting the injected water; then the viscosity gradually decreases, thus leading to a lower resistance factor (Figure 9 and Figure 10). When conducting water flooding after DPS combination


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flooding, the viscosity of the DPS system and the plugging behaviors of the DPG particles can produce a high water flow resistance in the porous media. Although the viscosity of the DPS system gradually decreases with the following water flooding, the DPG particles can effectively improve the profile control through the plugging behaviors of the particles themselves. Therefore, the DPS system can maintain a higher mobility control capacity in the following water flooding stage.

Figure 9. The resistance factor changes of the PS and DPS systems in the combination flooding stage and following water flooding stage.


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Figure 10. Comparison of the resistance factors of the PS and DPS systems.

3.2.2 Profile improvement capacity of DPS systems. The changes in the shunt rate and pressure are presented in Figure 11. The results show that the shunt rate of high permeability sand-packs gradually rises while the injection pressure decreases (Figure 11). This indicates that more water is produced from high permeability sand-packs, and the heterogeneity of the formation is formed after long-term water flooding. However, when conducting DPS combination flooding, the produced water of low permeability sand-packs and the injection pressure gradually increase. When further continuous water flooding occurs after the injection of the DPS system, the shunt rate of low permeability sand-packs further increases. Finally, the profile improvement rates of these sand-packs reach up to 64.52%, 83.57% and 86.68%, respectively. This results indicate that the injected DPS system can improve the formation profile control. The good profile improvement capacity is related to the special characteristics of the DPS system. Due to the viscoelasticity behavior of the polymers, the plugging behavior of the DPG particles, and the synergetic effect between the polymers and DPG particles, the DPS system can effectively reduce the water permeability in porous media. Therefore, the formation heterogeneity is reduced, and the profile control is improved. In addition, the


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sand-packs with higher permeability ratio usually have a lower injection pressure, which leads to the DPS system more easily entering the reservoir formation. Thus, the sand-packs with a higher permeability ratio have a better profile improvement capacity than the sandpacks with a smaller permeability ratio.


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Figure 11. The profile improvement capacity of the DPS system with different permeability ratios (a) permeability ratio and profile improvement rate: 1.28 and 64.52%; (b) permeability ratio and profile improvement rate: 1.89 and 83.57%; (c) permeability ratio and profile improvement rate: 3.84 and 86.68%.

3.3. Enhanced oil recovery capacity of the DPS combination flooding system Figure 12 shows that the enhanced oil recovery of the PS and DPS systems are 21.03% and 40.28%, respectively. This results indicate that the injection of PS or DPS systems can enhance oil recovery, but the capacities of these two systems are significantly different during the combination flooding stage and the following water flooding stage. For the PS system, the enhanced oil recovery mainly occurs during the combination flooding stage (Figure 12(a)). The viscoelastic and IFT reduction capacity are the driving forces for the enhanced oil recovery of the PS system. The viscoelastic polymer in the PS system could increase the mobility ratio of water, diverting the flowing water into medium or low permeability zones, thus resulting in a rise in the injection pressure. In contrast, the surfactant in the system could reduce the IFT and change the wettability of the sand surface, thus improving the swept efficiency. As a consequence, the residual oil in un-swept zones can be easily driven out, improving the oil recovery. However, the viscosity of the PS


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system is gradually reduced in the following water flooding stage. This leads to reductions of the profile control capacity and injection pressure in this stage. Therefore, the oil recovery is almost not enhanced during this stage. When conducting the DPS compound flooding, the system has the characteristics of the above PS system. Additionally, due to the DPG particles in the DPS system, the system has its own unique features for improving the oil recovery. The plugging behavior of DPG particles and the synergetic thickening effect could strength the plugging capacity of the DPS system in the compound flooding stage and following water flooding stage. Consequently, the injection pressure of the DPS system maintains a higher level than that of the PS system in these two stages (Figure 12(b) and (c)). Although the viscosity of the DPS system gradually deceases with long-term water flooding, the DPG particles can effectively improve the profile control through the plugging behaviors of the particles themselves. As a consequence, the oil recovery capacity of the DPS system is better than that of the PS system, and more oil is driven out from the medium and low permeability zones.


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Figure 12. The oil recovery capacity of the PS and DPS combination flooding system, (a) PS system; (b) DPS system; (c) comparison of recovery rates between PS and DPS system. 3.4. Distribution behavior of the DPS combination flooding system in solution and porous media 3.4.1 Morphology of the DPS combination flooding system in solution. Figure 13 presents

SEM images of the PS and DPS systems. It can be seen that a three-dimensional network structure is formed in the PS system (Figure 13 (a) and (b)). The intermolecular


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hydrophobic associations are the driving forces for the formation of the network structure. The skeleton structure exists in the polymer chains, which may play an important role in strengthening the stability of the systems. Many branch chains are distributed on both sides of the skeleton structure, which could improve the intertwining of molecular chains in the solution. Therefore, the viscosity of the PS system increases. Figure 13 (c) ~ (f) shows that the three-dimensional network structure still exists when adding DPG particles into the PS system. The skeleton structure with branched chains and the DPG particles are tightly locked together to form a compact and continuous network, whereas the DPG particles have a special distribution behavior in DPS systems. Some of the DPG particles are disorderly distributed in the solution, whereas some particles are adsorbed and interspersed in the network structure, which increases the viscosity and strength of the DPS system (Figure 13 (d) ~ (f)). The adsorption behavior can be attributed to the hydrogen bonding interactions among particles, polymers, and surfactant, which strengthen the stability of the DPS system in the combination flooding stage and following water flooding stage.

Figure 13. Morphology of the DPS combination flooding system in solution: (a), (b) PS system; (c) ~ (f) DPS system. 3.4.2 Distribution behavior of the DPS combination flooding system in porous media. Figure

14 presents the typical distribution behavior of the PS and DPS systems in porous media.


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However, the distribution behaviors of the PS and DPS combination flooding systems are significantly different in the porous media. As presented in Figure 14 (a) and (b), a threedimensional gel network of the PS system can be formed in small pore throats. However, as the pore throat size increases, the PS system network is not sufficiently compact, so bridging becomes more difficult in these zones (Figure 14 (b) and (c)). Moreover, the network of the PS system gradually changes into an instability system due to the dilution effect and shearing effect. Although the network is more or less present in the porous media, the viscosity of the PS system is greatly reduced. This presents a problem for the PS system in terms of control of the high permeability zones in the following water flooding stage. When conducting DPS combination flooding, the network still exists (Figure 14 (d) and (e)). Due to the polymer and surfactant in the DPS system, the DPS system has similar mobility ratio improvement and profile control mechanisms. However, due to the DPG particles in the DPS system, there are special distribution behaviors in porous media. In the DPS combination flooding stage, the synergetic effect among the DPG particles, polymer, and surfactant could increase the viscosity of the system. Additionally, the DPG particles are interspersed in the network structure, which could strengthen the flowing ratio of water to oil during this stage (Figure 14 (d) and (e)). When conducting the following water flooding, two or more DPG particles can bridge together and effectively plug the pore throats (Figure 14 (f)). Therefore, the DPS system can easily reduce the water permeability when the injected following water passes through these high permeability zones.


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Figure 14. Morphology of the PS and DPS combination flooding system in solution: (a), (b) PS combination flooding system; (c)~(f) DPS combination flooding system. 3.5. Enhanced oil recovery mechanism of the DPS combination flooding system

Figure 15 presents a schematic diagram of the network structure changes in the enhanced oil recovery process of the DPS system. As presented in Figure 15 (a), the PS combination flooding system is a compact three-dimensional network structure, whereas the structure is further strengthened when adding DPG particles into the DPS system. The DPG particles are interspersed in the network, which could improve the stability of the DPS system in the combination flooding stage (Figure 15 (b)). As long-term water flooding continues, the three-dimensional network structure of the DPS system gradually loosens and becomes unstable due to the dilution effect and shearing effect in the porous media (Figure 15 (c)). This leads to a reduction of viscosity in the DPS system; thus, the viscosity is no longer the driving forces for the profile control in this following stage. Although the viscosity is greatly reduced and the network structure of the DPS gradually disappears, the DPG particles are still present in the DPS system (Figure 15 (d)). The plugging behaviors of the DPG particles will play a leading role in the following water flooding stage. It is easier for the DPG particles to bridge across the pore throats and form effective profile control in the formation, which thereby promotes the surfactant in the DPS system to enter into the medium and low permeability zones. Then, the IFT is reduced. As a result, the residual oil


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is easily driven out and the oil recovery is then improved.

Figure 15. Schematic diagram of network structure changes of the DPS system: (a) network structure of PS; (b) network structure of DPS; (c) loose network structure of DPS; (d) disappeared network structure of DPS.

4. CONCLUSIONS In this work, a novel DPS combination flooding system composed of DPG particles, polymers, and surfactants was used for enhanced oil recovery in high water cut mature oilfields. Compared with a conventional PS combination flooding system, the DPS system has a higher viscosity and a more stable network structure due to the addition of DPG particles. The added DPG particles have a slight effect on the reduction of the IFT, while they can significantly increase the viscosity in the DPS system. A high concentration of polymers usually produces a higher viscosity, while a high concentration of surfactant leads to a lower IFT. The salinity and aging time have a slight effect on the stability of the DPS system. The DPG particles could be interspersed in the network and form a compact threedimensional network structure. The structure could improve the stability of the DPS system in the combination flooding stage and the following water flooding stage. The DPS system has a better mobility control capacity than the PS system. Moreover, the DPS system has a better profile improvement capacity in higher permeability ratio formations. The


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viscosity is the driving force for the mobility control in the combination flooding stage, while the plugging behaviors of the DPG particles are the main reason for the profile control in the following water flooding stage. Through the improved synergistic effect of the swept volume capacity and high displacement efficiency, the enhanced oil recovery capacity of the DPS system is superior to that of the PS compound flooding system.

ACKNOWLEDEMENTS This work was supported by the National Natural Science Foundation of China (5170431 4), Science Funds for Doctoral fund of Shandong Province (ZR201702170502),

and

Fundamental Research Funds for the Central Universities (18CX02167A).

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