Comparative Effectiveness of Alkaline Flooding and Alkaline

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Comparative Effectiveness of Alkaline Flooding and Alkaline− Surfactant Flooding for Improved Heavy-Oil Recovery Haihua Pei,† Guicai Zhang,*,†,‡ Jijiang Ge,*,† Mingguang Tang,† and Yufei Zheng† †

College of Petroleum Engineering, and ‡State Key Laboratory of Heavy Oil Processing, China University of Petroleum, Qingdao 266555, People’s Republic of China ABSTRACT: Chemical flooding is a promising technique for enhanced heavy-oil recovery, especially for reservoirs where thermal methods are not feasible. This paper discusses results of a laboratory investigation, including sandpack flooding experiments and micromodel flooding studies, for assessing the suitability and effectiveness of alkaline flooding and alkaline−surfactant (AS) flooding for heavy-oil recovery. The sandpack flood results show that the tertiary oil recovery of AS flooding is lower than those of alkaline-only flooding, although the interfacial tension between the heavy oil and AS system can be reduced to be ultralow. The micromodel tests indicate that the mechanisms for enhanced oil recovery by alkaline flooding are the penetration of the alkaline solution into the crude oil and the subsequent formation of water-in-oil (W/O) droplet flow that tend to reduce the mobility of the water phase and damp viscous fingering, leading to the improvement of sweep efficiency. However, the formation of W/O droplet flow is inhibited with the addition of surfactant, and the viscous oil is easily emulsified into the water phase to form oil-in-water emulsions and then entrains along with the flowing aqueous phase. As a result, viscous fingering phenomena occur during the AS flooding, resulting in a relatively lower sweep efficiency.

1. INTRODUCTION With the continuous reduction of light-oil resources and sustained high oil prices, the exploitation of heavy-oil resources is becoming increasingly important. However, the high viscosity of heavy oil makes it difficult to recover. The majority of enhanced oil recovery (EOR) techniques being employed for recovering heavy oil are thermal methods, such as cyclic steam stimulation, steam flooding, and steam-assisted gravity drainage.1 The principle of these thermal techniques is to improve oil mobility by reducing the viscosity of heavy oil. These thermal techniques have been successful in certain reservoirs with favorable conditions, such as thick pay zones and absence of bottom water.2 Unfortunately, many oil reservoirs in China are relatively thin or deep formations. As a result, thermal recovery techniques are not economic because of the excessive heat losses. For these heavy-oil reservoirs, nonthermal EOR techniques are required to recover the remaining oil in place. For heavy-oil reservoirs with oil viscosities ranging from 100 to 10 000 mPa s, only about 3−10% of the initial oil in place (IOIP) can be recovered under primary production.3 At the end of the economical life of primary production, water flooding is performed as the most widely used secondary recovery technique.4,5 However, the incremental recoveries by water flooding are quite low, because of the poor sweep efficiencies caused by the adverse mobility ratio between oil and water.6 Therefore, a large amount of the residual oil at the end of water flooding is significantly bypassed in these reservoirs, which is greatly different from that of the residual oil trapped by capillary forces in conventional oil reservoirs. As a result, these oils are still continuous and capable of flow.7 Therefore, to recover additional heavy oil after water flooding, the injected fluids must somehow improve the mobility ratio between the oil and water. © 2012 American Chemical Society

Table 1. Basic Properties of the Heavy-Oil Sample oil sample

viscosity at 55 °C (mPa s)

density at 55 °C (g/cm3)

acid number (mg of KOH/g)

resin (wt %)

normal heptane asphaltene (wt %)

Binnan

2000

0.9472

2.69

19.5

2.033

Figure 1. Dynamic IFT curves between the Binnan oil and brine with different NaOH concentrations at T = 55 °C.

For heavy oil, its characteristics are different from those of conventional oil. First, heavy oil is so vicious that it is impossible to reduce the mobility ratio greatly by increasing the viscosity of the displacement system. Second, heavy oil contains much more natural petroleum acid than conventional Received: February 3, 2012 Revised: April 16, 2012 Published: April 17, 2012 2911

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oil. To improve the heavy-oil recovery, a great deal of research has been performed on chemical flooding in recent years, including alkaline flooding, alkaline−surfactant (AS) flooding, etc. The mechanism of improved heavy-oil recovery is the formation of an emulsion in the chemical flooding. With the addition of alkali and surfactant mixtures in the water, the

viscous oil is easily emulsified into water to form oil-in-water (O/W) emulsions. Such formed emulsions either plug pore throats, leading to improved sweep efficiency, or are entrained along with the flowing aqueous phase.8−11 Therefore, the suggested recovery mechanism for O/W emulsions is that they will be first dispersed and carried in the aqueous phase

Figure 3. Effect of the alkaline concentration on the pressure drop as a function of the fluid injected.

Figure 2. Dynamic IFT between the Binnan oil and brine with 0.1 wt % surfactant and NaOH at different concentrations at T = 55 °C.

Figure 4. Effect of the alkaline concentration on the tertiary oil recovery and pressure drop.

Table 2. Summary of Sandpack Flood Tests run number

porosity (%)

permeability (mD)

initial oil saturation (%)

waterflood recovery (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

43.85 42.19 43.10 44.23 42.78 43.50 43.85 44.70 45.10 43.97 43.40 43.50 43.21 44.21 43.97 43.40 44.21

1964 2259 2193 2260 2193 2193 2015 2131 1986 2130 2034 1994 2193 2016 2015 2018 2071

89.01 90.14 91.20 90.05 90.28 89.43 90.14 91.80 91.00 90.19 91.80 91.50 90.71 90.05 90.54 91.80 91.40

33.87 32.81 32.40 32.24 31.69 32.19 31.76 30.70 31.80 32.70 35.80 35.30 34.75 34.33 33.01 35.80 30.29

chemical formula 0.1% 0.2% 0.3% 0.4% 0.6% 0.8% 1.0% 0.3% 0.3% 0.4% 0.8% 0.8% 1.0% 1.0% 0.4% 0.8% 1.0%

2912

NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH NaOH

+ + + + + + + + + +

0.03% SLPS 0.1% SLPS 0.1% SLPS 0.03% SLPS 0.1% SLPS 0.03% SLPS 0.1% SLPS 0.1% ORS 0.1% ORS 0.1% ORS

tertiary recovery (% IOIP)

final recovery (% IOIP)

6.29 10.63 13.50 16.04 17.08 18.65 19.96 12.10 11.88 13.27 13.80 15.80 17.32 18.63 8.27 10.80 11.33

40.16 43.44 45.90 48.28 48.77 50.84 51.72 42.80 43.68 45.97 49.60 51.10 52.07 52.96 41.28 46.60 41.62

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and then will recoalesce into the oil bank.12−15 Recent research showed that the waterflood recovery of heavy oils could be improved greatly by alkaline flooding through waterin-oil (W/O) emulsions.16−18 These emulsions should be more viscous than oil itself, thereby leading to improvements in the mobility ratio and sweep efficiency of the flood. More recently, Ding et al.19 and Pei et al.20 proposed that the penetration of alkaline solutions in crude oil and the formation of water drops inside the oil phase were the main mechanisms to improve sweep efficiency during alkaline flooding. They found that the viscous fingering could be reduced significantly by water drops inside the oil phase through the Jamin effect, while the W/O emulsion was just

the byproduct of alkaline penetration other than the basic reason for EOR by alkaline flooding. This study presents results of a laboratory investigation, including sandpack flood experiments and micromodel flood studies, for assessing the suitability and effectiveness of alkaline flooding and AS flooding for enhanced heavy-oil recovery. The findings of this investigation can be used as guidance in the formula design and mechanism studies of chemical flooding to maximize oil recovery from the heavy-oil reservoirs.

2. EXPERIMENTAL SECTION 2.1. Fluids and Chemicals. Oil and formation brine samples were collected from the Binnan heavy-oil reservoirs in the Shengli oilfield in China. To remove the solids and water, the heavy oil was centrifuged at 10 000 rpm at the reservoir temperature (55 °C) for 4 h. The viscosity, density, and acid number of the oil were analyzed and are listed in Table 1. The formation brine has a salinity of 0.5 wt %, and the concentrations of Ca2+ and Mg2+ in the brine are relatively low. Thus, all of the solutions used in this study were prepared with NaCl solutions at concentrations of 5000 mg/L. The chemical agents used in this study included alkali and surfactant. The alkaline agent used in this study was sodium hydroxide (NaOH). On the basis of the results from numerous screening tests, the surfactants used in this study were surfactant SLPS (provided by the Shengli oilfield, with a purity of 33.3%) and surfactant ORS (provided by the Daqing oilfield, with a purity of 33.5%). 2.2. Measurements of Interfacial Tension (IFT). The IFTs between the oil and the different chemical solution systems were measured using a Texas model 500 spinning drop interfacial tensiometer at 55 °C. Equipped with an image-capture device and image-acquisition software, this instrument could automatically measure and record the dynamic IFT. It usually took from 15 min

Figure 5. Tertiary oil recovery of alkaline flooding and AS flooding.

Figure 6. Pressure drops of alkaline flooding and AS flooding tests. 2913

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2.4. Micromodel Flood Studies. A glass-etched micromodel was used to investigate the displacement mechanisms of alkaline flooding and AS flooding. The micromodel was constructed by etching a twodimensional network of pores and throats on glass plates using a photochemical method. The pore network used in this study was patterned on the basis of the pore structure of a core obtained from the reservoir. The transparent nature of the micromodel allowed porescale multiphase displacements to be visually observed. To facilitate the visual observation of the phenomena easily during the flooding, 0.05 wt % eosin was added to color the injected brine in the micromodel flood tests. The sweep efficiency and the recovery efficiency of the microscopic displacement test are determined using the image analysis technique.20

3. RESULTS AND DISCUSSION 3.1. IFT Behavior of Binnan Oil/Brine/Chemical Systems. 3.1.1. IFT Behavior of Binnan Oil/Brine/Alkaline Systems. To investigate the effectiveness of the alkaline solution in reducing the oil−water IFT, the IFT behavior of the Binnan oil/brine was studied with different concentrations of NaOH ranging from 0.1 to 1.0 wt %. Figure 1 shows the dynamic IFT curves between the oil and brine with different alkaline concentrations at T = 55 °C. The results indicate that the IFT between the oil and NaOH systems is 0.03−0.12 mN/m. The equilibrium value of the dynamic IFT decreases first and subsequently increases with an increasing alkaline concentration in the brine. The minimum IFT value occurs with an alkaline concentration of 0.2 wt %. On the basis of the amount of NaOH addition (0.1−1.0 wt %), the calculated water pH would be in the range of 12.2−13.2, assuming that added 5000 mg/L NaCl does not exert a strong buffering effect on the changes in water pH. For a large number of conventional oils, an IFT minimum with NaOH addition was found at pH 12− 12.5. Therefore, the observed trend of reduced IFT with increasing NaOH in Figure 1 was consistent with the reported results in the literature.21−23 3.1.2. IFT Behavior of Binnan Oil/Brine/AS Systems. To examine the effectiveness of the addition of the surfactant on alkaline flooding in reducing the oil−water IFT, the dynamic IFT between 0.1 wt % surfactant and NaOH with different concentrations was measured, as shown in Figure 2. It can be observed that the IFT between the compound system, which consists of 0.1 wt % ORS or 0.1 wt % SLPS, and NaOH with different concentrations can be reduced greatly. For the compound system with the addition of 0.1 wt % SLPS, the IFT can all be reduced lower than 10−3 mN/m and the concentration of alkali has only a marginal effect on the IFT behavior. However, for the compound system with the addition of 0.1 wt % ORS, the IFT decreases with the NaOH concentration and the ultralow IFT values are obtained when the NaOH concentration is larger than 0.1 wt %. It is indicated that there is a good synergy effect between alkali and surfactant in reducing oil−water IFT. 3.2. Sandpack Flooding Study. To evaluate the effectiveness of alkaline flooding and AS flooding for improved heavy-oil recovery, 17 flood tests were conducted in sandpacks. With these tests, the incremental oil recoveries of different chemical injections were obtained and the effects of surfactant and alkali on oil recovery were examined. The parameters of the sandpacks, chemical slug compositions, and flood results are summarized in Table 2. For each sandpack flood test, the oil recovery behavior, water cut, and pressure drop were monitored and analyzed. It should be noted that an extensive

Figure 7. Pictures of the produced solution by alkaline flooding and AS flooding.

to 2 h for the IFT between each oil drop and chemical solution to reach the equilibrium IFT. 2.3. Sandpack Flood Studies. All chemical flooding tests for heavy-oil recovery were carried out using sandpacks. The sandpack used in this study was 2.35 cm in diameter and 19.4 cm in length. For each sandpack test, fresh quartz sand was wet-packed to ensure the same wettability for all of the tests. The sandpack was packed as follows: fresh quartz sands with the size fractions of 80−100 and 100− 200 meshes obtained from sieve screening were blended at a fixed weight ratio of 3:1. A coreholder filled with formation brine was positioned vertically, and the sand was added in several increments to fill the coreholder. In each step, the sand was shaken slightly after being poured. During this process, the water surface was kept above the top of the sand to ensure that air was not introduced into the sample. The sandpack flooding test was conducted horizontally. The experimental procedure was briefly described as follows. After the permeability of the sandpack in the presence of the formation brine was measured, the sandpack was subsequently saturated with the heavy oil. The oil injection was continued at a temperature of 55 °C until water production almost ceased (water cut was less than 1%). The amount of oil injected was estimated from the amount of water production. After the oil injection, the sandpack was waterflooded with the water temperature of 55 °C until the oil production became negligible (oil cut was less than 1%). After the initial water flooding, a fixed slug size of 0.5 pore volume (PV) chemical solutions was injected at the rate of 0.5 mL/min. The chemical injection was followed by extended water flooding until the oil production became negligible. During the flooding test, the differential pressure and volumes of produced oil and brine were measured as a function of time. Each produced effluent sample was centrifuged to separate oil and water, resulting in an accurate measurement of oil and brine production. The oil production was determined on a mass basis.12,15 2914

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Figure 8. Micromodel images during alkaline flooding with the addition of 1.0 wt % NaOH.

The tertiary oil recovery and pressure drop peak value during the alkaline injection are plotted as a function of the alkaline concentration in Figure 4. The tertiary oil recovery increases with the alkaline concentration and exhibits a significant change when the alkaline concentration ranges from 0.1 to 0.4 wt %. Above 0.4 wt % NaOH addition, the oil recovery only increases slightly. It is also noted that the pressure drop peak value as a function of the alkaline concentration follows the same trend as the tertiary oil recovery. As shown in Figure 4, there is a minor peak value in the pressure drop at the alkaline concentration of 0.1 wt %. This is because the interaction between the oil and alkaline solution is not strong enough to create the in situ emulsion. After the alkaline concentration exceeds 0.2 wt %, there exists a significant increase in the pressure drop. From these two values, it can be concluded that the increase in oil recovery shows a good correspondence with the increase of the pressure drop during alkaline flooding and a test with a higher pressure drop gives a higher tertiary oil recovery. 3.2.2. AS Flooding Tests. To study the effect of AS flooding with ultralow IFT on enhanced heavy-oil recovery, 10 sandpack flooding tests (runs 8−17) were conducted to compare the effectiveness of alkaline flooding and that of AS flooding for Binnan heavy oil. The results of the tertiary oil recoveries are plotted as a function of the NaOH concentration in Figure 5. It is observed that the tertiary oil recovery of AS flooding with the

de-emulsification process was needed to accurately measure the volume of oil and water when the emulsions were produced. 3.2.1. Alkaline Flooding Tests. A series of alkaline flooding tests (runs 1−7) were conducted to investigate effects of the alkaline concentration on the alkaline flooding for Binnan heavy oil. The concentration of NaOH was increased gradually from 0.1 to 1.0 wt %. Figure 3 shows the pressure drop responses as a function of fluid injected during the alkaline flooding test. It was observed that, during the primary water flooding, the pressure drop increased to build up a peak quickly right from the start. After, the pressure drop fell sharply, indicating that the brine breakthrough occurred in the sandpack. The breakthrough occurred at about 0.05 PV of brine injection. The low value of the breakthrough PV gives an indication that the displacement process is unstable and that viscous fingering dominates the flow behavior. With 0.5 PV injection of alkaline solution, the pressure drops started to rise and a high-pressure drop peak value was observed in Figure 3. The built-up pressure drop suggests that the penetration of alkaline solution into residual oil drops to form high-viscosity W/O emulsions, which can block the high-permeability water channels and reduce the mobility of the water phase. As a result, the subsequent injected water is diverted to the unswept areas, thereby resulting in improved sweep efficiency and increased heavy-oil recovery. 2915

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Figure 9. Micromodel images during AS flooding with 1.0 wt % NaOH + 0.1 wt % SLPS.

improvement in the oil recovery in sandpack flooding tests. However, the increase in the pressure drop in this process is not as large as in the W/O emulsion process. The above experimental results show that heavy-oil recovery can be more effectively improved by injecting an alkaline slug rather than an AS slug. 3.3. Micromodel Flooding Study. 3.3.1. Microscopic Displacement Mechanisms of Alkaline Flooding. To investigate the microscopic mechanisms of alkaline flooding for enhanced heavy-oil recovery, a micromodel flood test was conducted with the chemical addition of 1.0 wt % NaOH. Figure 8 shows the pore-level images of oil distribution during the alkaline flooding process in the micromodel flood test. It was observed that alkaline solution could penetrate into the heavy oil (see 1 and 2 in Figure 8a) and created some big water drops coated with thin oil film (brown color in Figure 8a). After entering into pore space, these big water drops were divided into small discontinuous water droplets inside the oil phase, as shown in Figure 8b. With the increase of the water droplets inside the oil phase (see 1−3 in Figure 8b), the W/O droplet flow was eventually formed. Figure 8c shows the oil distribution of the whole micromodel when the alkaline solution reached the outlet of the micromodel. It was observed that a relatively uniform oil saturation distribution over the entire model was displayed. This is ascribed to the fact that the resistance of the W/O droplet flow is much higher than that of the crude oil.

ultralow oil−water IFT is lower than that of alkaline-only flooding, especially when the surfactant ORS is added to the alkaline solution. Figure 6 illustrates the pressure drop curve of alkaline flooding and AS flooding. It can be observed that, during the process of chemical agent injection, the increment of oil recovery is accompanied by the increment of the pressure drop. For alkaline flooding with the highest tertiary oil recovery, the highest pressure drop and broadest pressure drop usually appear after the alkaline agent is injected, while for AS flooding with a lower pressure drop after the injection of the chemical agent, the recovery increment is obviously lower than that of alkaline-only flooding. Panels a and b of Figure 7 show pictures of produced solution by alkaline flooding with 0.4 wt % NaOH and AS flooding with 0.4 wt % NaOH + 0.1 wt % ORS, respectively. It can be been observed that the interface of the produced solution by pure 0.4 wt % NaOH solution is clear (see Figure 7a), which indicates that the upper phase of the produced solution is mainly water drops inside the oil phase. However, with the addition of 0.1 wt % ORS, the produced solution by AS flooding is fulvous O/W emulsion (see Figure 7b). This is due to the good synergy effect between alkali and surfactant; as a result, the heavy oil is easily emulsified into the water phase to form O/W emulsions and then entrains along with the flowing aqueous phase. The O/W emulsion flow in the porous media also led to an increase in the pressure drop and an 2916

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Figure 10. Micromodel images during AS flooding with 1.0 wt % NaOH + 0.1 wt % ORS.

As a result, the resistance to alkaline solution flow in the porous media is increased. The oil is displaced in the form of W/O droplet flow with little fingering effect, and the displacement front became relatively uniform. Therefore, it is the W/O droplet flow that reduced the mobility of the water phase and diverted the injected alkaline solution to the unswept region of the micromodel to improve the sweep efficiency. 3.3.2. Microscopic Displacement Mechanisms of AS Flooding. To further study the microscopic mechanism of AS flooding for improving heavy-oil recovery, in which the IFT can be reduced to ultralow by the AS system, two microscopic oil displacement experiments were conducted using the compound system of 1.0 wt % NaOH + 0.1 wt % SLPS and 1.0 wt % NaOH + 0.1 wt % ORS. The results are shown in Figures 9 and 10, respectively. It can be seen from Figures 9 and 10 that, when the AS system comes into contacting with oil, the displacement fluid can also penetrate into the oil and form a continuous water column (see 1 in Figures 9a and 10a), but this water column cannot be divided into small discontinuous water droplets moving forward (see 1 in Figures 9b and 10b). The phenomenon can be explained according to the mechanism of alkaline flooding proposed by Pei et al.20 On one hand, the ultralow IFT promotes the penetration of AS solution in the crude oil to form the water column. On the other hand, the high concentration of preformed surfactant in the water phase

weakens the non-uniform distribution of the in situ surfactant; therefore, the water column cannot be divided into small discontinuous water droplets. It is also observed from Figures 9 and 10 that the coated oil film around the water columns in the formula of 1.0 wt % NaOH + 0.1 wt % SLPS (see 2 in Figure 9a) is thicker and more stable than that of 1.0 wt % NaOH + 0.1 wt % ORS (see 1 in Figure 10a). As seen in Figure 10b, the thin-coated oil film makes these water columns and water drops instable. When the displacement fluid breaks through, the water columns and water droplets will rupture under the disturbance of flow and a continuous water channel will be formed (see 1 in Figure 10b), which would dramatically reduce the blocking capability. Then, the injected fluid begins to break through along the main diagonal line (see Figure 10c). After the breakthrough, the crude oil in contact with the displacement fluid has been dispersed into small droplets under the disturbance of flow (see 1 and 2 in Figure 11), then is carried out by the continuous water phase, and finally, produced in the form of O/W emulsion (see 3 and 4 in Figure 11). As a result, viscous fingering phenomena occur during the AS flooding, resulting in a relatively lower sweep efficiency. The results indicate that the addition of surfactant ORS has a more adverse effect on the formation of the W/O droplet flow than that of surfactant SLPS, which is the main cause of the lower tertiary oil recovery by AS flooding with surfactant ORS. 2917

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Figure 11. Pore-level images of the formation of O/W emulsions during the AS flooding process with the formula of 1.0 wt % NaOH + 0.1 wt % ORS.

3.3.3. Comparison of the Displacement Mechanisms of Alkaline Flooding and AS Flooding. Quantitative evaluation of the micromodel flooding tests was performed to compare the displacement mechanism of alkaline flooding and AS flooding for enhanced heavy-oil recovery. The sweep efficiency at the moment of chemical solution breakthrough (Figures 8c, 9c, and 10c) was calculated using the image analysis technique, as shown in Figure 12a. It can be observed that the sweep efficiency of the alkaline flooding is greatly higher than those of AS flooding. This is because the viscosity of a W/O emulsion is much higher than the viscosity of the water phase and even higher than the viscosity of the oil phase. Therefore, the oil can be displaced in the form of a W/ O droplet flow with minimal water fingering effects. While for AS flooding, because of the synergy of the surfactant and alkali, the IFT between the oil and water can be reduced to lower than 10−3 mN/m. With a minor disturbance at the oil and water interface, an O/W emulsion can be created and entrained in the water phase. An O/W emulsion has a much lower viscosity than a W/O emulsion because it tends to have the viscosity of the water phase. As a result, the water channels cannot be effectively blocked and serious fingering phenomenon will still occur, which leads to a lower sweep efficiency. Thus, it is concluded that alkaline flooding was more effective than AS flooding because of the formation of W/O droplet flow in the heavy oil. In the case of AS flooding with the addition of surfactant ORS, the displacement efficiency is relatively high because of the lower residual oil saturation in the swept area (see Figure 10d). However, the sweep efficiency of 1.0 wt % NaOH + 0.1 wt % ORS is much lower than that of 1.0 wt % NaOH + 0.1 wt % SLPS (see Figure 12a). As a result, the ultimate oil

recovery value of 1.0 wt % NaOH + 0.1 wt % ORS is lower than that of 1.0 wt % NaOH + 0.1 wt % SLPS, as shown in Figure 12b. This is because the addition of surfactant ORS has a more adverse effect on the formation of W/O droplet flow than that of surfactant SLPS. Thus, the sweep efficiency of AS flooding with the ORS is lower than that of SLPS, which is the main cause of the lower oil recovery by AS flooding with the ORS. Thus, in comparison to alkaline-only flooding, the AS flooding has a better displacement efficiency but a lower sweep efficiency. This is mainly because the formation of W/O droplet flow is influenced by the addition of the surfactant. Therefore, when selecting a surfactant in chemical flooding for enhanced heavy-oil recovery, the primary condition is that the surfactant cannot inhibit the formation of the W/O droplet flow. This conclusion is instructive for the design of the surfactant in chemical flooding for heavy oil.

4. CONCLUSION (1) The sandpack flooding results show that the tertiary oil recovery of AS flooding is lower than that of alkaline-only flooding, despite the coexistence of the surfactant and alkali, which can reduce the IFT between the heavy oil and aqueous phase to an ultralow level. (2) The micromodel tests indicate that the alkaline solution can penetrate into the oil phase to form W/O droplet flow to improve sweep efficiency. While for AS flooding, although the displacement efficiency is higher in the swept area, the AS flooding of the low IFT displacement system will affect the formation of W/O droplet flow, leading to a lower sweep efficiency than that of alkalineonly flooding. 2918

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(6) Mai, A.; Bryan, J.; Goodarzi, N.; Kantzas, A. J. Can. Pet. Technol. 2009, 48, 27−35. (7) Mai, A.; Kantzas, A. J. Can. Pet. Technol. 2009, 48, 42−51. (8) Jennings, H. Y.; Jojnson, C. E.; McAuliffe, C. D. J. Pet. Technol. 1974, 26, 1344−1352. (9) Bryan, J.; Kantzas, A. Proceedings of the 2007 Society of Petroleum Engineers (SPE) Annual Technical Conference and Exhibition; Anaheim, CA, Nov 11−14, 2007; SPE Paper 110738. (10) Bryan, J.; Kantzas, A. Proceedings of the Society of Petroleum Engineers (SPE)/Department of Energy (DOE) 16th Symposium on Improved Oil Recovery; Tulsa, OK, April 20−23, 2008; SPE/DOE Paper 113993. (11) Bryan, J.; Kantzas, A. Proceedings of the 2008 Society of Petroleum Engineers (SPE) International Thermal Operations and Heavy Oil Symposium; Calgary, Alberta, Canada, Oct 20−23, 2008; SPE Paper 117649. (12) Liu, Q.; Dong, M.; Yue, X.; Hou, J. Colloids Surf., A 2006, 273, 219−228. (13) Liu, Q.; Dong, M.; Ma, S.; Tu, Y. Colloids Surf., A 2007, 293, 63−71. (14) Liu, Q.; Dong, M.; Ma, S. Proceedings of the Society of Petroleum Engineers (SPE)/Department of Energy (DOE) 14th Symposium on Improved Oil Recovery; Tulsa, OK, April 17−21, 2004; SPE/DOE Paper 99791. (15) Dong, M.; Ma, S.; Liu, Q. Fuel 2009, 88, 1049−1056. (16) Cooke, C. E.; Williams, R. E.; Kolodzie, P. A. J. Pet. Technol. 1974, 26, 1365−1374. (17) Wang, J.; Dong, M.; Arhuoma, M. J. Can. Pet. Technol. 2010, 49, 51−58. (18) Dong, M.; Liu, Q.; Li, A. Proceedings of the International Symposium of the Society of Core Analysts; Calgary, Alberta, Canada, Sept 10−12, 2007; SCA Paper 2007-47. (19) Ding, B.; Zhang, G.; Ge, J. Energy Fuels 2010, 24, 6346−6352. (20) Pei, H.; Zhang, G.; Ge, J. Energy Fuels 2011, 25, 4423−4429. (21) Rudin, J.; Wasan, D. T. Colloids Surf., A 1992, 68, 67−79. (22) Rudin, J.; Wasan, D. T. Colloids Surf., A 1992, 68, 81−94. (23) Rudin, J.; Wasan, D. T. SPE Reservoir Eval. Eng. 1993, 18, 275− 280. Figure 12. Sweep efficiency and the ultimate oil recovery of alkaline flooding and AS flooding in the micromodel tests.

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AUTHOR INFORMATION

Corresponding Author

*Telephone: +8653286981178. E-mail: 13706368080@vip. 163.com (G.Z.); [email protected] (J.G.). Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This work was financially supported by the National Natural Science Foundation of China (51104170), the Fundamental Research Funds for the Central Universities (Grant 12CX06024A), the Outstanding Doctoral Dissertation Training Program of the China University of Petroleum (Grant LW110203A), the Taishan Scholars Construction Engineering Project (Grant ts20070704), and the Fok Ying Tung Education Foundation for Young Teachers in the Higher Education Institutions of China (Grant 114016).

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