Study of the Factors Influencing Alkaline Flooding in Heavy-Oil

Apr 18, 2012 - flooding for heavy oil are investigated in this study. The results ... oil acid number, which is a prominent factor in alkaline floodin...
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Study of the Factors Influencing Alkaline Flooding in Heavy-Oil Reservoirs Jijiang Ge,† Anzhou Feng,† Guicai Zhang,*,†,‡ Ping Jiang,†,‡ Haihua Pei,† Ruidong Li,† and Xin Fu† †

College of Petroleum Engineering, and ‡State Key Laboratory of Heavy Oil Processing, China University of Petroleum, Qingdao 266555, People’s Republic of China ABSTRACT: The effects of the oil acid number, alkaline concentration and type, brine salinity, and test temperature on alkaline flooding for heavy oil are investigated in this study. The results indicate that the tertiary oil recovery is positively affected by the oil acid number, which is a prominent factor in alkaline flooding. Another important factor is alkaline fluid. The best displacement efficiency can be achieved only when the alkaline concentration reaches a certain value. However, honeycomb oil blocks with a poor mobility may form when the alkaline concentration is too high. In comparison to Na2CO3, NaOH performs better in alkaline flooding for Zhuangxi 106 heavy oil. In addition, the performance of alkaline flooding is also affected by the brine salinity and test temperature. There is an optimum brine salinity for alkaline flooding, and the relatively low temperature is beneficial to alkaline flooding. When the temperature increases to a certain value, the displacement efficiency declines intensively. All of these results can be explained on the basis of the special flow mechanism of alkaline solution in the heavy-oil phase during flooding.

1. INTRODUCTION With the depletion of conventional oil and gas reserves, developing the massive amount of available heavy oil becomes more and more important. Because severe heat losses invariably reduce the effectiveness of thermal processes in deep or thin heavy-oil reservoirs, chemical flooding methods are proposed for their successful laboratory tests. Among various chemical methods available, alkaline flooding appears to be most attractive. The low-price alkaline reagents can react with heavy oil, which contains a high content of organic acids, and form a massive volume of in situ surfactants at the oil/water interface. These behaviors are favorable for the development of heavy oil.1 The great effectiveness of alkaline flooding was first reported in 1927 by Nutting2 and Atkinson.1 Meanwhile, different mechanisms for the alkaline flooding process have been proposed. Jennings et al.3 examined the effectiveness of primary alkaline flooding for a heavy oil from South America by core flooding tests and found that an optimum oil recovery was obtained when 0.1% NaOH was used. A possible mechanism for this process is the in situ formation of oil-in-water (O/W) emulsions that tend to dampen viscous fingering and improve sweep efficiency. Symonds et al.4 also observed the formation of O/W emulsions in the process of alkaline flooding for the Wainwright oil (408.3 mPa s at 23 °C). Two different mechanisms for 0.01 and 0.1% NaOH to improve oil recovery were proposed. In the case of 0.1% NaOH, emulsification and entrainment are the dominant mechanisms. The low interfacial tension (IFT) causes emulsification of the in-place oil and its transport by the flowing solution. The emulsified oil in the entrainment mechanism does not block off the pore throat, and the oil cut drops off rapidly after breakthrough. In the case of 0.01% NaOH, on the other hand, the dominant mechanisms appear to be emulsification and entrapment. The IFT in this system is higher than that in the 0.1% case, and as a result, the emulsified oil cannot be pushed through the pore constrictions. © 2012 American Chemical Society

However, many researchers do not regard the formation of O/W as the main mechanism for heavy-oil recovery. Cooke et al.5 observed that a bank of vicious water-in-oil (W/O) emulsion formed when an acidic oil was displaced by an alkaline solution prepared with a high salinity brine (more than 5% NaCl) in a porous medium. This emulsion tended to plug growing water fingers and channels, diverting flow to an initial unswept area, and a dramatic rise of the displacement pressure was simultaneously observed in the flooding process. Bryan et al.6 investigated the formation of emulsions during chemical flooding using low-field nuclear magnetic resonance (NMR), in which the main peaks of oil, water, and W/O emulsions were under 10 ms, in the range of 10−100 ms, and above 200 ms, respectively. The results showed that no matter which type of emulsion appeared in the effluent, W/O emulsions occurred in the inlet of the core, judging from its special slow relaxation rate. Dong et al.7 investigated the mechanism of alkaline flooding through a micromodel study and found that the injected alkaline solution would penetrate into the oil phase, forming many discontinuous water drops, which were regarded as W/O emulsions. However, the penetration of alkaline solution in the oil phase could occur without a high concentration of salt in the solution, which was significantly different from what Cooke et al. had mentioned previously.5 This phenomenon attracted the attention of Ding et al. and Pei et al. at the China University of Petroleum. Ding et al.8 proposed that the penetration of alkaline solution into the oil phase and the subsequent formation of water drops inside the oil phase represented the primary mechanism for alkaline flooding through micromodel tests. They assumed that the viscous fingering effect could be reduced significantly by the Received: January 28, 2012 Revised: April 17, 2012 Published: April 18, 2012 2875

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formation of water drops inside the oil phase through the Jamin effect, while the W/O emulsion was merely the byproduct of alkali penetration and not the main reason for alkaline flooding to improve oil recovery. Pei et al.9 conducted a further test that confirmed the formation of water drops inside the oil phase in alkaline flooding. Two stages related to the reaction between an alkaline solution and crude oil were described during the alkaline flooding process in their study. The first stage was the occurrence of water columns resulting from the penetration of the alkaline solution into the crude oil. The second stage was the division of these water columns into small discontinuous water droplets when moving forward because of the nonuniform enrichment of surfactants at the oil/water interface. On the basis of these mechanisms, these authors successfully explained the phenomena presented in the study by Bryan et al. The W/O emulsions mentioned above might be water drops inside the oil phase generated by alkaline solution penetrating into the crude oil. Because there were oil films coating the water drops, these drops might be considered as W/O emulsions according to the NMR analysis. The study above illustrates that, because of the high content of asphaltene and resin, the flow behavior seen for alkaline flooding in heavy oil is totally different from that seen for lowviscosity crude oil with a high acid number. In this paper, the effects of oil properties, alkaline fluids, and test temperature on alkaline flooding for heavy oil are investigated by sandpack flooding experiments, emulsification tests, and oil/water IFT measurements. The results are interpreted according to the formation of water drops inside the oil phase.

Table 1. Basic Properties of Heavy Oil heavy oil Zhuangxi 106 Chenzhuang Binnan Xia-8

density at viscosity at acid number 50 °C (g/cm3) 50 °C (mPa s) (mg of KOH/g of sample) 0.9302 0.9778 0.9632 0.9712

390 3450 2500 3950

1.846 2.018 3.852 4.660

allowed to rest for 30 min at 50 °C. After that, the tubes were quickly shaken up and down 100 times, and the emulsion type was identified by its photomicrograph. 2.3. IFT Measurement. The oil/water IFT between the surfactant solutions and the heavy oil is determined with the Texas-500 spinning drop tensiometer according to the following equation:

⎛ D ⎞3 σ = 1.2336(ρw − ρo )ω2⎜ ⎟ , ⎝n⎠

L ≥4 D

(1)

where σ is the IFT (mN/m), ρw is the density of the water phase (g/cm3), ρo is the density of the oil phase (g/cm3), ω is the rotational velocity (rpm), D is the measured drop width (mm), L is the length of the oil drop (mm), and n is the refractive index of the water phase. 2.4. Microscopic Flooding Test. The glass-etched micromodel was used to investigate the displacement mechanisms of alkaline flooding. The procedure for the microscopic flooding test can be described as follows: the micromodel was first saturated with brine after being vacuumed, and it was subsequently displaced by heavy oil until no more brine was produced. Next, the alkaline solution was injected at a constant flow rate of 0.003 mL/min. The process of the flooding test can be visualized by a video recorder and camera apparatus. 2.5. Sandpack Flooding Test. All of the tests were carried out in a sandpack that was 2.45 cm in diameter and 30 cm in length. The sandpack was wet-packed as follows: two batches of fresh quartz sand sieved through 80−100 and 100−200 meshes were blended at a fixed weight ratio of 3:1. A core holder filled with formation brine was positioned vertically, then the blended sand was added in increments until it filled the core holder. In each step, the sand in the core holder was shaken slightly. During this process, the water surface was kept above the top of the sand to avoid the entrance of air. The experimental procedure was as follows: first, the permeability of the sandpack was measured in the presence of the formation brine, and the wet-packed sandpack was subsequently saturated with the heavy oil until no more water was produced (the water cut was less than 1%). After oil injection, the sandpack was water-flooded until the oil production became negligible (when the oil cut was less than 1%). For the tertiary chemical flood tests, 0.3 pore volume (PV) chemical slugs were injected. The chemical injection was followed by an extended water flooding until no more oil was produced. All of these tests were conducted at 50 °C, and flow rate was 0.5 mL/min, except where otherwise specified. The equipment for the sandpack flooding is shown in Figure 2.

2. EXPERIMENTAL SECTION 2.1. Fluids and Chemicals. Oil was collected from the heavy-oil reservoirs of Xia-8, Zhuangxi 106, Binnan, and Chenzhuang in the Shengli oil field. Figure 1 shows their viscosity−temperature curves.

3. RESULTS AND DISCUSSION A number of tests were designed to investigate the effect of oil acid number, alkaline concentration and type, brine salinity, and temperature on alkaline flooding. A total of 25 sandpack flooding tests were conducted with four types of heavy oils. The injected volume of chemical solution was maintained at a PV of 0.3, and the other parameters of the sandpacks, chemical formulas, and flood results are summarized in Table 2. 3.1. Effect of the Oil Acid Number. The acid number of an oil sample is defined as the mass of potassium hydroxide that can neutralize 1 g of crude oil and cause an abrupt change in the pH. The reaction between the alkaline reagent and the crude oil is the main mechanism for alkaline flooding to improve oil recovery; therefore, the oil acid number may be an

Figure 1. Viscosity−temperature curves for four types of heavy oil. The density and acid number of the oil are analyzed and listed in Table 1. All of the solutions used in the experiments were prepared with NaCl solutions in different concentrations. The alkaline reagents used in this study are sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) supplied by Sinopharm. 2.2. Emulsification Test. This test was performed in a 20 mL glass test tube: 10 mL of aqueous phase with a specific concentration of alkali prepared with different concentrations of NaCl and 10 mL of heavy oil were added to the tubes successively. Next, the tubes were 2876

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Figure 2. Equipment for sandpack flooding: 1, distilled water; 2, pump; 3, pressure meter; 4, brine container; 5, crude oil container; 6, alkaline solution container; 7, pressure collection system; and 8, sandpack model.

Table 2. Summary of Sandpack Flooding Tests oil recovery (%) run number

heavy oil

permeability (mD)

initial oil saturation (%)

chemical formula

water flooding

alkaline flooding

total

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

Zhuangxi 106 Chenzhuang Binnan Xia-8 Zhuangxi 106 Zhuangxi 106 Zhuangxi 106 Zhuangxi 106 Chenzhuang Chenzhuang Chenzhuang Chenzhuang Xia-8 Xia-8 Binnan Binnan Zhuangxi 106 Zhuangxi 106 Zhuangxi 106 Zhuangxi 106 Zhuangxi 106 Zhuangxi 106 Zhuangxi 106 Zhuangxi 106 Zhuangxi 106

1580 1580 1425 1380 1440 1380 1545 1425 1380 1440 1380 1545 1425 1580 1380 1380 1225 1265 1380 1225 1380 1420 1260 1380 1225

83.5 85.2 83.7 82.7 85.3 84.6 86.5 86.4 82.5 84.7 83.3 87.1 83.4 85.9 82.9 87.1 85.0 87.5 84.5 86.1 85.0 83.9 84.1 86.1 85.4

0.5% NaOH + 0.5% NaCl 0.5% NaOH + 0.5% NaCl 0.5% NaOH + 0.5% NaCl 0.5% NaOH + 0.5% NaCl 0.5% NaOH + 1% NaCl 0.5% NaOH + 1.25% NaCl 0.5% NaOH + 1.5% NaCl 0.5% NaOH + 2% NaCl 0.5% NaOH + 1% NaCl 0.5% NaOH + 1.25% NaCl 0.5% NaOH + 1.5% NaCl 0.5% NaOH + 2% NaCl 0.5% NaOH + 0.5% NaCl 0.5% NaOH + 0.5% NaCl 0.5% NaOH + 0.5% NaCl 0.5% NaOH + 0.5% NaCl 0.25% NaOH + 0.5% NaCl 1% NaOH + 0.5% NaCl 1.25% NaOH + 0.5% NaCl 1.5% NaOH + 0.5% NaCl 0.5% Na2CO3 + 0.5% NaCl 0.75% Na2CO3 + 0.5% NaCl 1% Na2CO3 + 0.5% NaCl 1.5% Na2CO3 + 0.5% NaCl 2% Na2CO3 + 0.5% NaCl

38.6 33.7 39.0 37.6 37.5 38.2 38.4 36.9 37.6 37.8 38.1 38.3 34.7 43.3 37.8 42.9 39.8 38.7 37.6 38.5 39.8 37.2 38.4 39.2 37.9

12.4 12.9 16.9 20.4 11.9 13.3 11.8 10.2 14.4 13.8 16.5 15.4 20.1 8.9 16.1 3.9 7.2 15.6 16.2 15.4 5.4 7.6 13.2 12.6 12.9

51.0 46.6 55.9 58.0 49.4 51.5 50.2 47.11 52.0 51.6 54.6 53.8 54.8 52.2 53.9 46.8 47.0 54.3 53.8 53.9 45.1 46.8 51.6 51.8 50.8

become more in situ surfactants. With the presence of these surfactants, the instantaneous IFT can be reduced greatly and quickly, and thereby, the penetration of alkaline solution into the crude oil is initiated. In addition, the interfacial reaction may result in a stronger non-uniform enrichment of in situ surfactants at the water/oil interface; thus, the oil film coating water columns is unstable, which makes water columns divide into more discontinuous water droplets continuously during

important factor dominating the performance of alkaline flooding. A series of sandpack flooding tests (runs 1−4) were conducted to investigate the effect of the oil acid number on alkaline flooding. The results indicate that the tertiary oil recovery increases with the oil acid number, as shown in Figure 3. The heavy oil with a high acid number contains more organic acids, which can react with the injected alkaline solution and 2877

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the heavy oil with a high acid number. Therefore, the oil acid number is a prominent factor for alkaline flooding. 3.2. Effect of the Alkaline Concentration and Type. Researchers have found that alkaline flooding behaves differently when different alkaline reagents are used in the experiments. Campbell et al.10 compared the displacement effectiveness of sodium silicate and sodium hydroxide for Huntington Beach heavy oil. The results showed that the tertiary oil recovery of sodium silicate was always higher than that of sodium hydroxide under the same conditions. In addition, the alkaline concentration plays an important role in alkaline flooding according to the previous studies. Dong et al.11 conducted alkaline flooding tests for Brintnell heavy oil to investigate the influence of the alkaline concentration on the displacement efficiency and found that there was an optimum concentration at which the tertiary oil recovery was highest. Arhuoma et al.12 also found similar results for Alberta heavy oil through displacement experiments. To investigate the effectiveness of the alkaline concentration and type on alkaline flooding, 10 sandpack flooding tests (runs 1 and 17−25) were conducted with different chemical compositions, among which NaOH or Na2CO3 were used as the alkaline reagents. Figure 4 illustrates the incremental oil recovery as a function of the alkaline concentration. It can be observed that the recovery increases first with the alkaline concentration. Afterward, the increase in oil recovery as a function of the alkaline concentration becomes notably slight or the oil recovery even decreases to a certain extent, suggesting that there is an optimum concentration for both Na2CO3 and NaOH. The results are consistent with the conclusions by Dong and Arhuoma. To investigate the influencing mechanism of the alkaline concentration, microscopic displacement tests with different concentrations of NaOH were conducted. Figure 5 shows the microscopic images of the whole micromodel when the alkaline solution breaks through. It can be observed that the sweep efficiency of the displacing system containing 1.25% NaOH and 0.5% NaCl is significantly higher than that of the system containing 0.25% NaOH and 0.5% NaCl and more water drops appear in the oil phase when the alkaline concentration is high. However, when the alkaline concentration is too high, a large number of honeycomb oil blocks appear in the model. These oil blocks are easily retained and, thereby, become residual oil for their poor mobility.

Figure 3. Influence of the oil acid number on the displacement efficiency.

flooding. These interfacial phenomena are favorable for the formation of water drops inside the oil phase and the following occurrence of W/O emulsions. These dispersions can produce the Jamin effect and increase the viscosity of the front of the displacing phase, thereby dampening the viscous fingering, slowing water channeling, and improving sweep efficiency for

Figure 4. Influence of the alkaline concentration on the displacement efficiency.

Figure 5. Microscopic images (magnification of 1.5 times) of alkaline flooding when the alkaline solution breaks through. 2878

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same injection conditions; therefore, the alkaline type is also an important factor for alkaline flooding. 3.3. Effect of the Brine Salinity. To evaluate the influence of brine salinity on alkaline flooding, emulsification tests were first conducted for Zhuangxi 106 and Chenzhuang heavy oil, and the emulsion type at different brine salinities was identified by photomicrographs. Figure 8 shows the microimages of emulsions for Zhuangxi 106 heavy oil at different salinities. It can be observed that the brine salinity has a significant impact on the emulsion types. O/W emulsions tend to be formed when the salinity is low. In contrast, W/O emulsions mostly occur when the mass concentration of NaCl is above 0.7%. However, two types of emulsions appear at the same time when the mass concentration of NaCl is 0.6%, as shown in Figure 8(4). The emulsion photomicrographs of Chenzhuang heavy oil exhibit similar results, as shown in Figure 9. Displacement experiments were performed in sandpacks (runs 1, 2, and 5−12) to examine the effect of the brine salinity on alkaline flooding. The results of the tertiary oil recovery are plotted as a function of the brine salinity, as shown in Figure 10. It can be observed that the brine salinity indeed has an effect on the displacement efficiency. The incremental oil recovery first increases and subsequently decreases with the brine salinity, suggesting an optimum salinity of 1.25% for Zhuangxi 106 and 1.5% for Chenzhuang heavy oil. These results are consistent with the results by Ding et al.8 Figure 11 presents the images of the effluents in the sandpack flooding tests for Zhuangxi 106 heavy oil. It can be observed that the effluent is a muddy O/W emulsion with a yellow−brown color at a low brine salinity (0.5% NaCl). When the salinity gradually increases, oil containing some water drops appears in the upper phase of the effluent. When brine salinity is low, the in situ surfactants formed by the reaction of the alkaline solution and the crude oil are mainly dispersed in the aqueous phase, which tend to facilitate the formation of O/W emulsion in the phase behavior test. Therefore, the penetration of the alkaline solution into the crude oil may be weakened to some degree. According to the results by Bryan et al.,6 water drops may appear in the entrance of the sandpack, but emulsification and entrainment are the dominant mechanisms under this condition. With the increase of the brine salinity, the diffusion of the in situ surfactants into the aqueous phase declines and more surfactants remain at the oil/water interface, which is favorable for the formation of water drops inside the oil phase. However, when the brine

The dynamic IFT curves for different alkaline solutions are shown in Figures 6 and 7. It can be seen that the IFT changes

Figure 6. Dynamic IFT of Na2CO3 solution/Zhuangxi 106 heavy oil.

Figure 7. Dynamic IFT of NaOH solution/Zhuangxi 106 heavy oil.

little with the alkaline concentration and cannot decrease to an ultralow value. These results indicate that the IFT is not the main indictor for alkaline flooding. In comparison to Na2CO3, the incremental oil recovery of NaOH for Zhuangxi 106 heavy oil is always higher under the

Figure 8. Photomicrographs of emulsions for Zhuangxi 106 heavy oil (the aqueous phase contains 0.5% NaOH and different concentrations of NaCl). 2879

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Figure 9. Photomicrographs of emulsions for Chenzhuang heavy oil (the aqueous phase contains 0.5% NaOH and different concentrations of NaCl).

Figure 10. Performance of alkaline flooding at different NaCl concentrations.

Figure 12. Influence of the temperature on alkaline flooding.

Figure 11. Photographs of the effluent for the displacement test at different NaCl concentrations (effluents during alkali injection and the extended waterflooding were collected in the tubes from left to right in turn; the pictures show their appearances at the end of flooding, without demulsification).

Figure 13. Dynamic IFT curves of Binnan heavy oil/alkaline solution containing 0.5% NaOH and 0.5% NaCl.

3.4. Effect of the Temperature. Both the oil viscosity and the reaction velocity between alkaline solution and crude oil can be changed with the temperature. To investigate the effect of the temperature on alkaline flooding, a series of sandpack flooding tests (runs 13 and 15, runs 3 and 4, and runs 14 and 16) were conducted at 30, 50, and 70 °C, respectively. The

salinity is too high, some honeycomb oil blocks appear and the improvement in oil recovery is limited. Therefore, there is an optimum brine salinity for alkaline flooding. 2880

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Figure 14. Dynamic IFT curves of Xia-8 heavy oil/alkaline solution containing 0.5% NaOH and 0.5% NaCl.

Figure 16. Pictures of the effluent during alkali injection and the extended waterflooding (effluents during alkali injection and the extended waterflooding were collected in the tubes from left to right in turn; the pictures show their appearances at the end of flooding, without demulsification).

that the peak pressure drop for alkaline flooding is higher than that for water flooding for Xia-8 heavy oil, except at the condition of 70 °C, which is consistent with the results of the sandpack flooding tests. Although the oil viscosity decreases and, thereby, a favorable water/oil mobility ratio may appear when the temperature increases, the displacement efficiency at the high temperature is still poor. These results can be understood according to the mechanism of alkaline flooding proposed by Ding et al. and Pei et al. The reaction between the alkaline solution and crude oil may be accelerated at high temperature. Thus, the sudden drop in instantaneous IFT and the non-uniform enrichment of the in situ surfactants are weakened. These changes are adverse to the formation of water drops inside the oil phase, which is the main mechanism for alkaline flooding for heavy oil. Pictures of the effluent in the sandpack flooding tests are shown in Figure 16. It can be seen that the interface of the effluent is clear and the upper phase is the oil containing some water drops at the conditions of 30 and 50 °C. However, because the formation of water drops inside the oil phase cannot be implemented easily at 70 °C, the alkaline solution injected into the sandpack mainly streams forward along the water channels, forming a muddy O/W emulsion with the residual oil, as shown in Figure 16c. This phenomenon is consistent with the previous prediction.

Figure 15. Pressure changes during alkaline flooding for Xia-8 heavy oil at different temperatures.

results of the sandpack flooding tests are shown in Figure 12. It can be concluded that the changes in the tertiary oil recovery for two oil samples are similar with the variation of the temperature. When the temperature is low (30 and 50 °C), the incremental oil recovery changes little; however, it declines intensively at 70 °C with a minimum value of only 3.88%. The dynamic IFT between alkaline solution and crude oil shows little change with the variation of the temperature, and the equilibrium value is approximately 0.06−0.2 mN/m, as shown in Figures 13 and 14, which is inconsistent with the conclusions by Chiwetelu et al.13 and Trujillo.14 The displacement pressure drop is plotted as a function of the injected volume, as shown in Figure 15. It can be observed

4. CONCLUSION (1) The results of the sandpack flooding tests for heavy oil demonstrate that incremental oil recovery increases with the oil acid number, which is a prominent factor for alkaline flooding. (2) The best displacement efficiency can be achieved only when the alkaline concentration reaches a certain value. A poor sweep efficiency is also demonstrated through microscopic displacement tests when the alkaline concentration is low. 2881

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However, the honeycomb oil blocks with a poor mobility will be formed when the alkaline concentration is too high, which is unfavorable for increased tertiary oil recovery. In comparison to Na2CO3, NaOH performs better in alkaline flooding for Zhuangxi 106 heavy oil. (3) The brine salinity can change the created emulsion type and influence its properties, which is related to the displacement efficiency. There is an optimum salinity for alkaline flooding. (4) The relatively low temperature is beneficial to alkaline flooding. When the temperature increases to a certain value, the displacement efficiency declines intensively.

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AUTHOR INFORMATION

Corresponding Author

*Telephone: +8653286981178. E-mail: 13706368080@vip. 163.com. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS Financial support from the National Natural Science Foundation of China (51104170), the National Natural Science Foundation of Shandong Province (ZR2011EEQ001), “Taishan Scholars” Construction Engineering (ts20070704), the Fok Ying Tung Education Foundation (114016), and the research on the displacement mechanisms of chemical flooding for water flooding heavy oil from the State Key Laboratory of Heavy Oil Processing is gratefully acknowledged.

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REFERENCES

(1) Johnson, C. E. J. Pet. Technol. 1976, 28, 85−92. (2) Nutting, P. G. Oil Gas J. 1927, 25, 106. (3) Jennings, H. Y.; Johnson, C. E.; McAuliffe, C. D. J. Pet. Technol. 1974, 26, 1344−1352. (4) Symonds, R. W.; Farouq Ali, S. M.; Thomas, S. J. Can. Pet. Technol. 1991, 30, 44−49. (5) Cooke, C. E.; Williams, R. E.; Kolodzie, P. A. J. Pet. Technol. 1974, 26, 1365−1374. (6) Bryan, J.; Mai, A.; Kantzas, A. Proceedings of the Society of Petroleum Engineers (SPE)/Department of Energy (DOE) Symposium on Improved Oil Recovery; Tulsa, OK, April 20−23, 2008; SPE Paper 113993. (7) 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. (8) Ding, B.; Zhang, G.; Ge, J. Energy Fuels 2010, 24, 6346−6352. (9) Pei, H.; Zhang, G.; Ge, J. Energy Fuels 2011, 25, 4423−4429. (10) Campbell, T. C.; Krumrine, P. H. Proceedings of the 54th Annual Fall Technical Conference and Exhibition of Society of Petroleum Engineers of American Institute of Mining Engineers (AIME); Las Vegas, NV, Sept 23−26, 1979; SPE Paper 8328. (11) Dong, M.; Ma, S.; Liu, Q. Fuel 2009, 88, 1049−1056. (12) Arhuoma, M.; Yang, D.; Dong, M.; Idem, R. Proceedings of the Canadian International Petroleum Conference (CIPC); Calgary, Alberta, Canada, June 16−18, 2009; SPE Paper 2009-53. (13) Chiwetelu, C. I.; Neale, G. H.; Hornof, V.; George, A. E. J. Can. Pet. Technol. 1994, 33, 37−42. (14) Trujillo, E. M. SPE J. 1983, 23, 645−656.

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