Evaluation of Different Factors on Enhanced Oil Recovery of Heavy Oil

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Evaluation of different factors on EOR of heavy oil using different alkali solutions Haiyan Zhang, Guangying Chen, Mingzhe Dong, Suoqi Zhao, and Zhiwu Liang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b00196 • Publication Date (Web): 08 Apr 2016 Downloaded from http://pubs.acs.org on April 9, 2016

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Evaluation of different factors on EOR of heavy oil using different alkali solutions Haiyan Zhang* †, ‡, Guangying Chen†, Mingzhe Dong§, Suoqi Zhao‖ and Zhiwu Liang*,† †

Provincial Hunan Key Laboratory for Cost-effective Utilization of Fossil Fuel Aimed at Reducing Carbon-dioxide

Emissions, College of Chemistry and Chemical Engineering, Hunan University, Changsha, Hunan, 410082, P.R. China ‡

Guangxi Colleges and Universities Key Laboratory of Beibu Gulf oil and Natural Gas Resource Effective

Utilization, College of Petroleum and Chemical Engineering, Qinzhou University, Qinzhou, Guangxi, 535000, P.R.China §

Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, Alberta T2N 1N4, Canada

‖

State Key Laboratory of Heavy Oil Processing, China University of Petroleum, Beijing 102249, P.R.China

*Corresponding Authors: Telephone: +86-777-2696801. E-mail: [email protected] (Dr.Zhang); [email protected] (Dr.Liang) The authors declare no competing financial interest.

Abstract A series of sand pack flood tests are carried out on Court heavy oil by using different alkali solutions to evaluate the influence of different factors on EOR of heavy oil, such as interfacial tension (IFT), emulsification effect, and pressure drop. These alkali solutions include NaOH, Na2CO3, NaOH-surfactant, Na2CO3-surfactant, and the mixtures of NaOH and Na2CO3 at different ratios. The results demonstrated that using NaOH solution to displacing heavy oil obtained the best oil recovery efficiency but without the lowest IFT and the most effective emulsification. By correlating the enhanced oil recovery efficiencies with interfacial tensions (IFT), emulsification effects, and pressure drops, it was found that the oil recovery efficiency corresponded better with the increments in pressure drop than other factors after chemical slug injection. Combined with the discovery of micromodel tests, it was deduced that the improvement on the heavy oil recovery efficiency was mainly due to the formation of an oil bank which plugged the water channel. The formation of oil bank for NaOH displacing process is due to the accumulation of oil droplets. While for NaOH-S flooding process, the formation of oil bank is mainly because of the emulsification. OH- exerts a special influence on the separation of trapped oil into oil droplets and the accumulation of oil droplets. A certain amount of OH- is required to reduce the IFT which is benefit to the formation of oil droplets, while excessive OH- can promote the accumulation of oil droplets which is also detrimental to the formation of oil droplets. Key words: heavy oil, chemical flooding, interfacial tension, emulsification, alkalinity 1. Introduction Chemical flooding is a promising enhanced oil recovery (EOR) technique and it has been studied by many researchers[1]. Of all the chemical flooding agents, alkali solutions are among the most widely used [2-4]. It has been found that the enhancement of oil recovery process when using these agents is affected by many factors such as ability to form emulsions [5], interfacial tension (IFT)[6], viscosity[7] and wettability[8]. Many researchers have reported that the improved oil recovery is mainly due to the emulsification and entrainment of oil into the displacing water phase [9,

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10]. Liu et al.[11] used surfactant and alkali to displace a Western Canada heavy oil and believed that the formation of the oil/water emulsion and an oil bank was important in the improvement of EOR of heavy oil. Dong et al.[12] used different alkalis and surfactants to form unstable oil/water emulsions to enhance oil recovery, and found that the final oil recoveries increased by 11.2%-29.9% IOIP (initial oil in place). It has been widely accepted that interfacial tension has a significant influence on enhancing oil recovery [13, 14]. Lower interfacial tension has been taken as the criteria to select the proper displacing fluid for chemical flooding[15, 16] Khan et al.[16] designed a chemical formula relating to NaOH, surfactants (sodium dodecyl sulfate and sodium dodecyl benzene sulfonate) and polymer based on the ultralow IFT rule, which increased the oil recovery by about 25% OOIP. While for heavy oils, there are some different opinions. Babu et al.[17] found that the interfacial behavior of different heavy oils was different although the water phase composition remained unchanged. Some researchers found that lower interfacial tension was not always responsible for higher oil recovery. Jennings et al.[18] found that lowering IFT to less than 0.01dynes/cm with alkalis would enhance the oil recovery dramatically. Zhang et al .[19] found that ultralow interfacial tension is not necessary to improve oil recovery, but the IFT has to be reduced to a certain level so that the oil can be separated into oil droplets that will block the short cut of the water phase. Tang et al[20].using NaBO3 to displace heavy oil and enhance the oil recovery by 27.1%. They also found that alkali contributed more than surfactant in the recovery of heavy oil. Their study also illustrated that the mechanism of enhancing heavy oil recovery is not by forming emulsion, but the alkaline solution penetrated into the crude oil and formed water droplets inside the oil to block the water channel. Mehranfar et al[21] investigated the displacement mechanism of heavy oil and they thought that alkaline solution improve the sweep efficiency by forming W/O emulsion at the front and then modifying the fingering pattern. Gong et al [22] reported that it is the wettability alteration caused by alkali that mobilizes the heavy oil adsorbed at the rock surface and blocks the water channel thereby enhancing oil recovery. Pei et al[5] suggested that heavy oil recovery can be increased through the formation of water-in-oil emulsification brought about by alkali flooding. By comparing the effectiveness of alkali flooding and alkali-surfactant flooding on improving heavy oil recovery, Pei et al. [23] also found that injecting alkali in slugs is more effective than injecting alkali-surfactant in slugs. Since alkalis can penetrate into heavy oil and form water/oil (W/O) droplets that have a much higher resistance to flowing than heavy oil, they can therefore reduce the mobility of the water phase. With alkali-surfactant slug injection, water columns rather than droplets were formed and resulted in enhanced oil recovery. From the previous reports, it is clear that there is still no agreement on which factor is the key that has crucial influence on the EOR of heavy oil. A widely accepted requirement for enhancing heavy oil recovery is to increase the sweep efficiency [24], but there is still no agreement on how to improve the sweep efficiency and researches still need to be carried out in this area. In this paper, chemical flooding with different chemical solutions including NaOH, Na2CO3, NaOH-surfactant, Na2CO3-surfactant and the mixture of NaOH and Na2CO3was conducted on Court heavy oil using sand pack flood tests. The relationships between tertiary oil recovery efficiency and interfacial tension, emulsification effects as well as pressure drop increments were analyzed. Micromodel tests were also carried out to reveal the reason for the enhancement of Court heavy oil recovery by the alkali solutions.

2. Experimental section 2.1 Fluids and chemicals The formation brine and heavy oil sample were collected from the Court reservoir


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(Saskatchewan, Canada). The heavy oil was cleaned by centrifuging at 10,000 rpm and elevated temperature (35oC) for 2 hours to remove water and sands. All aqueous solutions used for displacing oil in this study were prepared with formation brine. The characteristics of the heavy oil and the formation brine are shown in Table 1 and Table 2, respectively. After a series of screening tests, an anionic surfactant CS-460 (Stepan, Canada), NaOH and Na2CO3 were selected as the surfactant and alkali solutions, respectively. The pH values of different alkali solutions are in the range of 10.86-12.93. 2.2 Interfacial tension measurement Model 510 spinning drop interfacial tensiometer（Temoco Inc, Tulsa, OK）was used to measure the interfacial tensions between oil and different alkali solutions. Aqueous solutions and heavy oil were injected into the capillary tube in turn. Then the tube was rotated along its longitudinal axis at a sufficiently high speed to make sure the length of the oil drop was longer than four times its diameter. The interfacial tension was calculated by built-in software according to the length and the diameter of the oil droplet. DIFmin was adopted here to compare the interfacial tension between oil and different aqueous solutions. All the interfacial tensions were measured at 30℃. 2.3 Emulsification tests Bottle tests were carried out to compare the emulsification effects of different chemical solutions on Court oil. At ambient temperature, 5mL of different alkali solutions were injected into a set of little bottles, and then 1mL oil was carefully added into each little bottle. Each set of bottles was gently shaken several times to emulsify the oil/alkali systems. 2.4 Sandpack flood tests The cores used for flood tests were packed with fresh sands under the same conditions: the core holder with the dimension of 5cm×15cm was filled with formation brine, and then was positioned vertically on a vibrator. After the vibrator was turned on, fresh silica sand of 60-100 mesh was added to the core holder in five steps. The pore volume of sand pack was around 72mL and the porosity of the sand pack was approximately 35%. The absolute permeability of the sand pack was in the range of 3.0-3.8 Darcy. After the water-wetted core was packed, oil was pumped in to saturate the core until water production ceased (water cut was less than 1%). Then water flood was carried out on the core; about 1.1 PV formation brine was injected to displace the oil and about 36-40% IOIP was produced. After the water flood, 0.5 PV of chemical solution was injected, followed by an extended water flood until oil production became negligible. The tertiary oil recovery mentioned in this paper refers to the ratio of the oil produced after the chemical solution was injected (including chemical flooding and extended water flooding) to the original oil injected into core. For the entire oil displacement process, the injection rate of the aqueous phase was controlled at 10mL/h, and the pressure drop was monitored by a digital pressure gauge (HEISE PPM-2, Ashcroft). All the sand pack flood tests were conducted at ambient temperature. 2.5 Micromodel tests Micromodel tests were conducted at ambient temperature to verify the mechanism of chemical flooding. The micromodel was made of two tight coupled glass plates, and a two-dimensional network with pores and throats of different sizes was etched into one of the plates. The porous area is 8.0 cm × 4.5 cm and the pore volume (PV) is 0.15 mL. The micromodel was cleaned first with varsol and ethanol to remove any oil left in it, then it was blown by air to remove the residual solvent, and heated in a muffle furnace to make sure no


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trace organic compounds were left. The micromodel was laid horizontally, and the fluid was injected through a hole in the middle of the left side and exited from the other hole in the right side. 3. Results and discussions 3.1 IFTs between oil and different aqueous solutions The IFT of oil/DI water without any additional chemicals was measured as 37mN/m. To determine the proper concentration of surfactant (CS460) for the displacing process, the IFTs of oil/surfactant systems were also measured, as shown in Figure 1. After different concentrations of the surfactant were added, the IFTs of the oil/aqueous solution were dramatically reduced to 0.8-1.4mN/m when the concentrations of CS460 were higher than 100 μg/g. Further increasing the surfactant concentration won’t bring down the IFT apparently. In order to find the proper composition of alkali/surfactant system, different amount of surfactant was added to alkaline solution with alkali concentration varying in the range of 0.1-0.8 wt%. Their interfacial tensions are shown in Figure 2 and Figure 3. The curves in Figure 2 demonstrate that, for oil/Na2CO3-surfactant system, the reduction on IFTs changes with the variation of chemicals concentration. When Na2CO3 concentration is 0.3-0.5 wt%, the IFTs of AS with surfactant 50 μg/g and 100 μg/g are lower than those of with surfactant 300-800 μg/g. While at higher or lower Na2CO3 concentration, the trends are different. The interfacial tension with surfactant concentration 800μg/g is even higher than that with lower Na2CO3 concentration. For NaOH-S system, the IFTs of oil/NaOH-S with surfactant concentrations varying from 100 μg/g to 500 μg/g were also measured. The results in Figure 3 depict clearly that the IFT of oil/NaOH-S with surfactant concentration 300 μg/g is lower than that with surfactant 100 or 500μg/g. This phenomenon also reveals that for different alkali and different alkali composition, the proper surfactant concentration varies too. This phenomenon can be simply explained as: the alkalinity has to be strong enough to react with the interfacial species in oil to produce in situ surfactant therefore to effectively reduce IFT. While due to the competitive adsorption between alkali and surfactant at oil/water interface, the optimal compositions of AS systems change with the variation of alkali concentration and surfactant concentration. Based on the above experimental results, and given to the convenience of comparison, 300μg/g is selected as the surfactant concentration for the following experiments. The IFTs of oil/NaOH and oil/Na2CO3 with and without surfactant (CS460, 300 µg/g) were measured (see Figure 4). From the IFT curves of oil/NaOH systems, it can be observed that: the interfacial tension decreases sharply when NaOH concentration changes in the range of 0.1wt%- 0.2 wt%; further increases of the NaOH concentration, the IFT value levels off at about 0.22 mN/m; and there is a slight increase in IFT when alkali concentration changes from 0.5wt% to 0.8 wt%. Under the same alkali concentration (as shown in Figure 4), the IFT of oil/Na2CO3 system is much higher than that of oil/NaOH system. Na2CO3 alone cannot remarkably reduce the interfacial tension until its concentration reaches 0.3 wt%, which is twice the effective concentration of NaOH (about 0.15 wt%). While continually increasing Na2CO3 concentration, the differences of IFTs between the two O/A systems are reduced. This can be explained as that increasing Na2CO3concentration brought up the alkalinity which has to reach a certain level to reduce oil/water interfacial tension [6]. Adding 300μg/g surfactant to the above oil/alkali systems, the IFT of both oil/NaOH-S and oil/Na2CO3-S are reduced dramatically, and NaOH-surfactant is more effective in bringing down


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the IFT than Na2CO3-surfactant. The results also verified that there is a synergy between alkali and surfactant CS460, and it can reduce the interfacial tension more dramatically than alkali or surfactant alone. It also can be found that more alkali is needed to effectively reduce IFT after surfactant added, and NaOH is more effective than Na2CO3 on reducing IFT and lower concentration of it is able to reduce the IFT to an ultralow level. The synergy between alkali and surfactant can be ascribed to the formation of in situ surfactants which can reduce the oil/water interfacial tension more effectively[25] than the prepared surfactant alone. In order to form in situ surfactant, the alkalinity at oil/water interface has to be strong enough to reach the ionization onset of the acids[26, 27]. Therefore interfacial tension only can be reduced effectively after reaching a certain alkali concentration. At the same alkali concentration, the pH value of Na2CO3 is lower than NaOH and less OH- can be supplied, so the IFT of Na2CO3/oil is always higher than that of NaOH/oil (as shown in Figure 4). Therefore, the optimum concentration of Na2CO3 to effectively reduce the interfacial tension is higher (0.3 wt%) than that of NaOH (0.15 wt%). Also, due to the competitive adsorption between OH- and surfactant at the interface, more alkali is needed after the surfactant is added. 3.2 Emulsification of oil and different alkali solutions. From the discussion above, it can be known that NaOH and Na2CO3 combined with surfactant can reduce the IFT to ultra low levels. Since it has been [28] reported that it was the formation of an emulsion of oil and alkali solution (W/O or O/W) that enhanced oil recovery, the emulsification effect of the alkali solutions mentioned above were compared in this study. Considering that the ratio of water to oil during the oil displacement process is high for tertiary oil recovery, the emulsification tests of the alkali systems mentioned above were conducted by bottle tests with a volume ratio of oil to water at 1:5. From Figure 5, it is found that only Na2CO3/surfactant (shown in Figure 5b) can emulsify the oil effectively. By observing the emulsification process (shown in Figure 5a and 5c), it is noticed that, no matter how high the alkali concentration is, NaOH or Na2CO3 can only make oil disperse coarsely into the water solution after shaking the bottle several times, and the oil droplets separate from the water phase very quickly and accumulate together as soon as the shaking is stopped. For NaOH-surfactant system (shown in Figure 5d), the oil can disperse into the aqueous solution in the form of small oil droplets and some components of the oil can be emulsified into the water phase, but the oil droplets still tend to accumulate quickly after shaking is stopped. Separating the oil into droplets again becomes more difficult if it remains in contact with the alkali solution for some time after the emulsification tests. It was also noticed during the emulsification step that separating the oil into oil droplets became a little more difficult and the tendency for the aggregation of dispersed oil droplets is strengthened with the increase of alkali concentration especially when NaOH concentration is higher than 0.6wt%, and NaOH exerts a more prominent influence on this than Na2CO3. This observation proves that a suitable alkaline concentration is needed and too much OH- will difficult the dispersion of oil into oil droplets and will strengthen the aggregation of oil droplets. 3.3 Sandpack flood tests with different alkali solutions The cumulative oil recovery efficiencies (defined as the volume of oil recovered vs the volume of oil initially injected, IOIP%) of Na2CO3 and Na2CO3-S displacing processes are shown in Figure 6 and Figure 7, respectively. It can be observed from Figure 6 that the accumulative oil recoveries reach around 35% IOIP after first water displacement. Further injecting slugs of Na2CO3 solution with the concentration of 0.1wt%-0.8wt% brings no apparent increment in oil


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recovery. After the chemical slug of surfactant (300μg/g) and Na2CO3 was injected, as shown in Figure 7, the oil recoveries after first water flooding are enhanced to a different extent: when Na2CO3 concentration changes from 0.1 to 0.3wt%, there is no apparent increment after chemical slug injected, however, if Na2CO3 concentration is higher (i.e. 0.5, 0.6 and 0.8 wt%, respectively), the oil recoveries after chemical slug injected increase noticeably (from 35%IOIP to 54%IOIP). The results indicate that Na2CO3 alone cannot improve the tertiary oil recovery of Court oil, while Na2CO3 and surfactant together can improve oil recovery and have a remarkable effect when their solution has the proper composition. In this research, with Na2CO3-surfactant (300μg/g), the oil recovery efficiency can be increased apparently only when Na2CO3 concentration is higher than 0.3wt%. The influence of NaOH solutions on the EOR of Court heavy oil was also investigated. The curves in Figure 8 show clearly that there is no apparent increment in oil recovery when NaOH concentration is 0.1wt% and 0.3wt%, while there is a remarkable increase when NaOH concentration is 0.5wt%, 0.6wt%, and 0.8wt%. Comparing with the results of Na2CO3 displacing processes, it can be found that NaOH is more effective in enhancing oil recovery than Na2CO3. After the NaOH-surfactant (300μg/g) slug was injected, as shown in Figure 9, the oil recovery was enhanced to a different extent when NaOH concentration varies from 0.1wt% to 0.8wt%. When NaOH concentration is 0.1wt%, oil recovery after chemical slug injection increases slightly. At the concentration of 0.3wt%, the oil recovery increases remarkably from 36%IOIP to 56%IOIP. The increment in oil recovery reaches the highest value at 0.5wt% and there is no apparent further increment even as NaOH concentration increases to 0.6wt%. There is a slight decrement in oil recovery when NaOH concentration is at 0.8wt%. Considering the experimental phenomenon observed during emulsification, it can be deduced that it is the excessive alkali which makes the dispersed oil droplets aggregate and jeopardize the EOR. For the convenience of comparing the effects of different chemical slugs on enhancing oil recovery, the increment in oil recoveries after chemical slug injection are shown in Figure 10. The results demonstrate very clearly that NaOH is more effective in enhancing oil recovery efficiency than Na2CO3 no matter if it is with or without surfactant. Comparing the curves of NaOH and NaOH-surfactant in Figure 10, it is evident that when NaOH concentration is lower than 0.4 wt%, injecting NaOH alone cannot enhance oil recovery dramatically, and the tertiary oil recovery efficiency of NaOH-surfactant is higher than that of NaOH. Beyond this range, the trend is reversed and the tertiary oil recovery with NaOH solution alone is much higher. Comparing the curves of Na2CO3 and Na2CO3-surfactant, it can be found that using Na2CO3 alone can barely enhance oil recovery. Adding surfactant to Na2CO3 solution can improve oil recovery, but the increments are not as dramatic as those of using NaOH and NaOH-surfactant. The results in Figure 10 reveal that the alkalinity of the chemical solution has to be strong enough to enhance oil recovery effectively. When alkalinity is not strong enough, such as Na2CO3 and NaOH at lower concentration, combining alkali with surfactant will enhance oil recovery. Contrarily, when the alkali solution is strong enough to improve oil recovery effectively, such as NaOH at higher concentration, adding surfactant to the alkali will jeopardize oil recovery. 3.4 Pressure drop of sandpack flood tests Considering all the above experimental results, it can be found that alkalinity, or NaOH concentration is crucial to improve oil recovery, but lower IFT and good emulsification effects are not directly correlative with higher EOR. In order to find the factor that does correlate with EOR,


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the change in the pressure drop was monitored during the whole displacement process (including three steps: displacing with water, chemical slug and extended water, respectively). The pressure drops of NaOH displacing processes under different alkali concentrations are shown in Figure 11. It can be observed during the tests that, after formation brine was injected into the oil saturated cores, the pressure drops increased to higher than 200cmH2O immediately and then quickly started going down, indicating that the displacing fluid started to drive oil out of the core. With the continuous injection of formation brine, the pressure drop keeps going down and finally reaches to 5 to 6cmH2O (as shown in Figure 11), indicating that the shortcut has been formed and water cannot effectively displace oil anymore. When NaOH slugs with different concentration were injected, the variations of pressure drop with time become apparently different. For the concentration of 0.5 wt%, 0.6wt% and 0.8 wt%, the pressure drops increase gradually to their maximum and then slowly go down until near zero, with the whole process lasting for 5-6 hours. However, when NaOH concentration is 0.1wt% or 0.3 wt%, the increment in the pressure is very small. The increments in pressure drop demonstrate that the shortcut in core was blocked by NaOH slugs, and the blocks are more effective at higher NaOH concentrations. Further introducing surfactant to the NaOH solution, the varying trends of pressure drops (see Figure 12) are similar to that of NaOH displacing processes. For NaOH-S displacing processes, the pressure drops also increase obviously after chemical slug injected, but the increments in pressure drop are smaller and their values tend to fluctuate with time and the durations of the increases are shorter comparing to NaOH displacing processes (see Figure 11). Correspondingly, they brought up to lower increments of oil recovery (as shown in Figure 10). Injecting Na2CO3 to displace oil, the increments in pressure drop cannot be observed (as shown in Figure 13). While using Na2CO3-S to displace oil (as shown in Figure 14), the increments of pressure drop are higher than that of using Na2CO3, but they are much lower than using NaOH or NaOH-S as displacing agents. It is also noticed that higher Na2CO3 concentration is an aid in increasing the pressure drop. The relationship between the maximum increments in pressure drop after chemical slug injection and alkali concentrations of different chemical flooding processes are shown in Figure 15. The curves indicate that NaOH is more effective in increasing the pressure drop only when its concentration is high enough (in this case, when NaOH concentration is higher than 0.3 wt %). Adding surfactant to NaOH will bring down the increment in pressure drop at higher alkali concentration, but it does not change the varying trend of increment in pressure drop with NaOH concentration. When using Na2CO3 as displacement agent, it cannot increase the pressure drop; even after surfactant added, the increment is still very small. Comparing Figure 15 with Figure 10, it can be found that the shape of the curves are very similar to each other, which indicates that the increment in pressure drop and oil recovery are correlated very well with each other, and the higher the increment in pressure drop, the more oil can be recovered. The increment in pressure drop means the shortcut of displacing fluid is blocked. The higher the increment in pressure drop is, the longer the increment lasts, and the more completely the shortcut is blocked. Thus, it can be deduced that the increment in oil recovery is owing to the blocking of the shortcut, and NaOH is more effective in blocking the shortcut than the other three alkali solutions. As for the reason that alkali solutions are effective for enhanced oil recovery, previous research thought it was because of the formation of an oil bank or the increase in the viscosity of the displacing fluid to plug water channels [29]. Therefore, the results above can be explained as


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following: alkali, especially with higher alkali concentration, can help to form an oil bank thereby blocking the shortcut of displacing fluid, so that the displacing fluid goes to the area which has not been displaced to drive the oil there out. As for the reason that adding surfactant at higher alkali concentration will jeopardize oil recovery but enhance the oil recovery at lower alkali concentration, it may be ascribed to the strength of the oil bank. It can be deduced that, for alkali/S system, the oil bank is formed by O/W emulsion; while for alkali system, the oil bank is formed by the accumulation of oil droplets. The strength of the former is much weaker than the latter because of the high viscosity of heavy oil. So NaOH is more effective than NaOH/S to improve the EOR. When alkalinity is not strong enough, less in situ surfactants are produced, and the IFT is not low enough to split oil into droplets. That is why the EOR increment of alkali/S is better than alkali when using Na2CO3 or NaOH at lower concentration. 3.5 EOR of mixed alkali solutions It was also noticed from Figure 15 that the pressure drop increment brought up by increasing NaOH concentration is much more remarkable than that of increasing Na2CO3 concentration no matter with or without surfactant. In order to figure out the influence of NaOH on enhancing oil recovery, the mixed alkali containing NaOH and Na2CO3 was also applied to the chemical flooding process of Court heavy oil. To eliminate the influence of other ions such as Na+, the mixed alkali solutions were prepared at different ratios of Na2CO3 to NaOH under same Na+ concentration (keeping the total Na2O equals to that of Na2CO3 0.6 wt%, 0.8 wt% respectively). It can be observed from Figure 16 and Figure 17 that the oil recoveries go up with the increase of NaOH concentration in the mixed alkali. When total alkalinity equals to 0.6 wt% (where NaOH concentration is 0.36wt%), all the total oil recoveries are less than 50%IOIP even if the ratio of Na2CO3 to NaOH reaches 1:4. When total alkalinity equals 0.8wt% (as shown in Figure 20), the increments of total oil recovery are more apparent especially when the ratio of Na2CO3 to NaOH is lower than 1:1 (with the ratio of Na2CO3 to NaOH at 1:1, 2:3 and 1:4, NaOH concentration is 0.3 wt%,0.36 wt% and 0.48wt%, respectively). The results of mixed alkali solutions enhancing oil recovery are consistent with those of NaOH flooding process in that the alkalinity has to be strong enough to enhance oil recovery. The increments in oil recoveries after mixed alkali slugs injected (Figure 18) clearly show that the alkalinity has a remarkable influence on the tertiary oil recovery efficiency. At higher total alkali concentration (0.8wt%), the alkalinity is stronger, so the third oil recovery is always higher. Under the same total alkali concentration, since the concentrations of Na+ at different Na2CO3 to NaOH ratios are equal to each other, the only difference is the ratio of CO32- to OH-. Lowering the ratio of Na2CO3 to NaOH (that is, more OH- exists in the mixed alkali solution), the tertiary oil recoveries increase noticeably. This phenomenon demonstrates clearly that OH- plays an important role in the enhancement of oil recovery. Aksulu[30] et al also testified the importance of OH- (pH value) on EOR, and they ascribed it to its influence on the adsorption and desorption. The changes of pressure drop of mixed alkali solutions (see Figures 19 and 20) demonstrate that higher total alkali concentration is helpful to bring up the pressure drop. At same total alkali concentration and same sodium ion concentration, with the increase of OH- (namely the decrease of the ratio of Na2CO3 to NaOH), the increment in pressure is increased. It can thus be deduced that it is OH- not Na+ that is crucial in the formation of the oil bank and the blocking of the


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shortcut, thus further enhancing oil recovery. It was also noticed that the starting time of pressure drop increasing was different when the ratio of Na2CO3 to NaOH varied from 1:1 to 1:4. The difference among the packed cores may influence a little bit. The main reason can be ascribed to the influence of OH- concentration on the dispersion and aggregation of oil droplets. The OH- plays two roles during the displacing process: one is to react with the interfacial active components in oil to reduce the IFT, so the trapped oil can be separated into oil droplets; the other one is to strengthen the accumulation of oil droplets. With the increase of OH- concentration, the accumulation of oil droplets is strengthened and the formation of oil droplets is delayed, so the starting time of pressure drop is different with the increase of OH- concentration. 3.6 Micromodel tests In order to figure out the reason of the formation of an oil bank, micromodel tests were conducted to visualize the displacing process. It can be observed that there was no emulsion appeared when NaOH (0.5wt%) was injected. After the oil contacted with alkali for some time to reduce the oil/water interfacial tension, the trapped oil started to be separated into small oil droplets due to the reduced IFT, then the oil droplets are entrained by the displacing fluent. During this process, the water maybe penetrates into the oil droplets [31]. When the entrained oil droplets flowed forward and encountered the oil trapped at another narrow throat or when the oil droplets accumulated together, an oil bank was formed to clog up the pore therefore to block the water channel. It also can be observed from the picture captured from the video taken for the displacing process (see Figure 21) that the oil bank is formed mainly by the heavy oil itself. It was observed for NaOH-surfactant (NaOH 0.5 wt%, surfactant 300μg/g) displacing process (as shown in Figure 22) that the oil started to disperse into displacing fluent to emulsion at a certain extent after oil contacted with NaOH-S system for a while. Then the emulsion flowed around and to form an obstacle (“oil bank”) at other channels to block the water channel. The formation of the oil bank formed by emulsion can be seen from Figure 22. This conclusion is consistent with the former reports [23, 29]. Combining the above findings with the influence of NaOH concentration on emulsion process, increments on pressure drop and the oil recovery, it can be deduced that the Court heavy oil recovery enhancement by alkali flooding is achieved mainly by blocking the water channel through the formation of an oil bank, The formation of the oil bank for alkali and alkali/S displacing are caused by the accumulation of oil droplets and emulsion respectively. The high viscosity of heavy oil makes the oil bank difficult to be broken through, so the water channel can be clogged effectively and improve the sweep efficiency. Even if this oil bank is broken though, the oil droplets can be formed again and clog up the pore at other place, therefore the pressure drop increase and the entire oil recovery efficiency is improved. On the contrary, the “oil bank” formed by emulsion is easier to be broken through by the displacing fluid. As its result, the oil recovery efficiency can only be enhanced a little and the value of increments in pressure drop is not as high as that of alkali displacing processes. And OH- concentration is critical to the formation and the strength of the oil bank. If OHconcentration (or alkalinity) is too low, the IFT is not reduced enough to form oil droplets. If OHconcentration is too high, the influence of excessive OH- which can strengthen the accumulation of oil droplets will also hamper the separation of trapped oil, the formation of oil droplets becomes more difficult. So an appropriate OH- is required to achieve higher oil recovery efficiency. This


Energy & Fuels

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also explained why the increment of pressure drop at higher NaOH concentration (0.8wt%) is lower than that at 0.5wt%. 4．Conclusions For Court heavy oil, by studying the relationship between the interfacial tension, emulsification effects, pressure drop and the oil recovery efficiency, it has been found that: 1) Enhancing the heavy oil recovery is not simply by forming emulsion. Forming an oil bank to effectively blocking the water channel is the main reason to the alkali flooding of heavy oil. 2) The alkalinity has to be strong enough to form an oil bank. The formation of oil bank for NaOH displacing process is due to the accumulation of oil droplets. While for NaOH-S flooding process, the formation of oil bank is mainly because of the emulsification. 3) OH- exerts an important influence on the separation of trapped oil into oil droplets and the accumulation of oil droplets. There must be enough OH- to react with the interfacial active species in oil to reduce the IFT which is benefit to the formation of oil droplets. On the contrary, excessive OH- will promote the accumulation of oil droplets which is detrimental to the formation of oil droplets, but it is very helpful to the formation of oil bank. Acknowledgments The authors gratefully acknowledge the financial supports of National Natural Science Foundation of China (201446012), Natural Science Foundation of Guangxi science and technology department (2012GXNSFBA053031) and Guangxi Colleges and Universities Key Laboratory of Beibu Gulf oil and Natural Gas Resource effective utilization (2015KLOG01)

References [1]. Olajire A. Review of ASP EOR (alkaline surfactant polymer enhanced oil recovery) technology in the petroleum industry: Prospects and challenges. Energy, 2014(77): 963-982. [2]. Wang C., Wang B., Cao X., Li H. Application and design of alkaline-surfactant-polymer system to close well spacing pilot Gudong oilfield, in SPE Western Reginal meeting,Long Beach, California,1997, SPE38321 [3]. Pitts M., Dowling P., Wyatt K., Surkalo H., Adams C. Alkaline-surfactant-polymer flood of the Tanner Field. in SPE/DOE symposium on improved oil recovery SPE, 2006: Tulsa, Oklahoma, U.S.A. SPE100004. [4]. Li G., Mu J., Li Y., Yuan S. An experimental study on alkaline:surfactant:polymer flooding systems using nature mixed carboxylate. Colloid and Surface A: Physicochemical and Engineering Aspects, 2000. 173: 219-229. [5]. Pei, H., Zhang G., Ge J. Jin L., Ma C. Potential of alkaline flooding to enhance heavy oil recovery through water-in-oil emulsification. Fuel, 2013. 104: 284-293. [6]. Pei, H., Zhang G., Ge J. Jin L., Ding L. Study on the variation of dynamic interfacial tension in the process of alkaline flooding for heavy oil. Fuel, 2013(104): 372-378. [7]. Daripa, P., Pasa G. An optimal viscosity profile in enhanced oil recovery by polymer flooding. International Journal of Engineering Science, 2004(42): 2029-2039. [8]. Austad, T., Shariatpanahi S.F., Strand S., Black C.J.J.,Webb K.J. Conditions for a Low-Salinity Enhanced Oil Recovery (EOR) Effect in Carbonate Oil Reservoirs. Energy & Fuels, 2012(26): 569-575. [9]. Türksoy, U. Bağci S. Improved oil recovery using alkaline solutions in limestone medium.


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Energy & Fuels

[10]. [11].

[12]. [13].

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[18]. [19].

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[24]. [25].

[26].

Journal of petroleum science and engineering, 2000. 26: 105-119. Nelson, R., Lawson J., Thigpen D., Stegemeier G. Cosurfactant-enhanced alkaline flooding. SPE/DOE Syposium on enhanced oil recovery Tulsa,OK. 1984. SPE/DOE 12672 Liu, Q., Dong M., Ma S.,Tu Y. Surfactant enhanced alkaline flooding for Western Canadian heavy oil recovery. Colloid and Surface A: Physicochemical and Engineering Aspects, 2007, 293: 63-71. Dong, M., Ma S., Liu Q. Enhanced heavy oil recovery through interfacial instability: A study of chemical flooding for Brintnell heavy oil. Fuel, 2009(8)8: 1049-1056. Zhao, Z., Bi C., Qiao W., Li Z., Cheng L. Dynamic interfacial tension behavior of the novel surfactant solutions and Daqing crude oil. Colloids and Surfaces A: Physicochem. Eng. Aspects, 2007(294):191-202. Dahami, M., Constant W. and Wolcott J. Alcohol-assisted alkaline flooding for enhanced oil recovery. Fuel, 1988. 67: 1242-1248. Nasr-El-Din H., Taylor.K. Dynamic interfacial tension of crude oil/alkali/surfactant systems. Colloids and surfactants,1992,66:23-37 Khan, M., Samanta A., Ojha K., Mandal A. Design of alkaline/surfactant/polymer(ASP) slug and its use in enhanced oil recovery. Petroleum Science and Technology, 2009. 27: 1926-1942 Babu D, Hornof V. Neale G. Effects of Temperature and Time on Interfacial TensionBehavior Between Heavy Oils and Alkaline Solutions. The Canadian Journal of Chemical Engineering, 1984. 62: 156-158. Jennings, H., Johnson C., McAuliffe C. A caustic waterflooding process for heavy oils. Journal of Petroleum technology, 1974:1344-1352 Zhang, H., Dong M., Zhao S. Which one is more important in chemical flooding for enhanced Court Hheavy oil recovery, lowering interfacial tension or reducing water mobility?. Energy & Fuels, 2010,(24): 1829-1836 Tang, M., Zhang G., Ge J.,Jiang P., Liu Q., Pei Ｈ .,Chen L. Investigation into the mechanisms of heavy oil recovery by novel alkaline flooding. Colloid Surface A. Physicochemical and engineering Aspects, 2013(421): 91-100 Mehranfar, A.,M.H. Ghazanfari, Investigation of the microscopic displacement mechanisms and macroscopic behavior of alkaline flooding at different wettability conditions in shaly glass micromodels. Journal of Petroleum Science and Engineering, 2014(122): 595-615 Gong, H., Li Y., Dong M., Ma S., Liu W. Effect of wettability alteration on enhanced heavy oil recovery by alkaline floodingHoujian. Colloid Surface A.Physicochemical and Engineering Aspects, 2016(488): 28-35. Pei, H., Zhang G., Ge J., Tang M., Zheng Y. Comparative Effectiveness of Alkaline Flooding and Alkaline Surfactant Flooding for Improved Heavy-Oil Recovery. Energy & Fuels, 2012. 26: 2911-2919.. Dong, M., Liu Q., Li A. Displacement mechanisms of enhanced heavy oil recovery by alkaline flooding in a micromodel. Particuology, 2012(10): 298-305. Chatterjee J. A novel mechanism of dynamic interfacial tension reduction in triglyceride-alkaline aqueous solution system. Colloids and Surfaces A: Physicochem. Eng. Aspects. 2002(204): 93-102. Chan, M. Yen T.F. A chemical equilibrium model for interfacial activity of crude oil in


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[31].

aqueous alkaline solution: the effects of pH, alkaline and salt. The Canadian Journal of Chemical Engineering, 1982. 60: 305-308. Zhang, H., Dong M., Zhao S. Experimental Study of the Interaction between NaOH, Surfactant, and Polymer in Reducing Court Heavy Oil/Brine Interfacial Tension Energy and Fuels, 2012(26): 3644-3650. Kumar, R., Dao E., Mohanty K., Heavy Oil Recovery by Insitu Emulsion Formation. SPE Journal, 2012(17): 326-334. Zhou, X. Dong M. Maini B. The dominant mechanism of enhanced heavy oil recovery by chemical flooding in a two-dimensional physical model. Fuel, 2013. 2013: 261-268. Aksulu, H., Håmsø D., Strand S., Puntervold T., Austad T. Evaluation of Low-Salinity Enhanced Oil Recovery Effects in Sandstone: Effects of the Temperature and pH Gradient. Energy and Fuels, 2012(26): 3497-3503 Pei, H, Zhang G., Ge J.,Jin L., Liu X. Analysis of Microscopic Displacement Mechanisms of Alkaline Flooding for Enhanced Heavy-Oil Recovery,Energy & Fuels,2011, 25, 4423–4429.

Table list Table 1 Physical Characteristics of Court Oil Table 2 Composition Analysis of Court Formation Brine Figure list Figure 1 IFT of oil/surfactant system Figure 2 Interfacial tensions of oil/Na2CO3-surfactant systems with different surfactant concentration Figure 3 Interfacial tensions of oil/NaOH-surfactant systems with different surfactant concentration Figure 4 The relationship between IFT and alkali concentration of different oil/alkali solutions . Figure 5 Emulsification of different alkali systems on Court oil. a. Na2CO3 without surfactant, from left to right (wt %): 0.1, 0.2, 0.3, 0.35, 0.4, 0.5, 0.6,0.8; b. Na2CO3 with surfactant, from left to right (wt %): 0.1, 0.2, 0.3, 0.35, 0.4, 0.5, 0.6,0.8; c. NaOH without surfactant, from left to right (wt %):0.02, 0.04, 0.1, 0.2, 0.3, 0.5,0.8; d. NaOH with surfactant, from left to right (wt %):0.02, 0.04, 0.1, 0.2, 0.3, 0.5,0.8. Figure 6 Relationship of oil recovery and injection volume of Na2CO3 at different alkali concentrations Figure 7 Relationship of oil recovery and injection volume of Na2CO3-surfactant (300 μg/g) at different alkali concentrations Figure 8 Relationship of oil recovery and injection volume of NaOH at different alkali concentrations Figure 9 Relationship of Oil recovery and injection volume by NaOH-surfactant (300 μg/g) at different alkali concentrations Figure 10 The relationships between tertiary oil recovery increment and alkali concentration of different chemical solutions Figure 11 Pressure drop changing during NaOH displacing processes


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Page 13 of 32

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Energy & Fuels

Figure 12 Pressure drop changing during NaOH-S displacing processes Figure 13 Pressure drop change during Na2CO3 displacing processes Figure 14 Pressure change during Na2CO3-S displacing processes Figure 15 Pressure drop increments after chemical slugs injected at different chemical flooding processes. Figure 16 Relationship of Oil recovery and injection volume by Na2CO3 and NaOH mixed solution (total alkali equals to that of Na2CO3 0.6 wt%) Figure 17 Relationship of Oil recovery and injection volume by Na2CO3 and NaOH mixed solution (total alkali equals to that of Na2CO3 0.8wt%) Figure 18 Tertiary oil recovery vs the ratios of Na2CO3 to NaOH at different total alkali concentrations. Figure 19 Pressure drop during chemical flooding process using NaOH-Na2CO3(with total alkalinity equals to 0.6%) Figure 20 Pressure drop during chemical flooding process using NaOH-Na2CO3(with total alkalinity equals to 0.8%) Figure 21 The picture of the oil bank formed when NaOH-S (NaOH 0.5 wt%, surfactant 300μg/g) displacing injected Figure 22 The picture of the oil bank formed when NaOH-S (NaOH 0.5 wt%, surfactant 300μg/g) displacing injected

Tables and Figures Table 1 Physical Characteristics of Court Oil Viscosity(22.5°C), mPa.s

Density, kg/m3

1500

Total Acid Number, mg KOH/g sample

950.4

1.4

Table 2. Composition Analysis of Court Formation Brine Components

Concentration, mg/L

Components

Concentration, mg/L

Barium

3.8

Magnesium

80

Chloride

7,870

Potassium

55

Calcium

76

Sulphate

390

Iron

0.016

Sodium

4,900

Manganese

< 0.005

Total dissolved solids

13,600


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4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 0

100

200

300 400 500 600 700 Concentration of surfactant,μg/g

800

900

Figure. 1 IFT of oil/surfactant system

10 50μg/g 100μg/g

1

300μg/g

IFT,mN/m .

500μg/g 0.1

800μg/g

0.01

0.001

0.0001 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

Concentration of Na2CO3, wt%

Figure.2 Interfacial tensions of oil/Na2CO3-surfactant systems with different surfactant concentration

1 surfactant 100μg/g surfactant 300μg/g surfactant 500μg/g

0.1 IFT, mN/m

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

IFT, mN/m

Energy & Fuels

0.01

0.001

0.0001 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

NaOH concentration, wt%

Figure3 Interfacial tensions of oil/NaOH-surfactant systems with different surfactant concentration


0.9

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10000 Na2CO3 NaOH NaOH-S Na2CO3-S

1000 100 IFT, mN/m

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

10 1 0.1 0.01 0.001

0.0001 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

Alkaline concentration, wt%

Figure 4 The relationship between IFT and alkali concentration of different oil/alkali solutions .

a

b

c

d Figure 5 Emulsification of different alkali systems on Court oil. a. Na2CO3 without surfactant, from left to right (wt %): 0.1, 0.2, 0.3, 0.35, 0.4, 0.5, 0.6,0.8; b. Na2CO3 with surfactant, from left to right (wt %): 0.1, 0.2, 0.3, 0.35, 0.4, 0.5, 0.6,0.8; c. NaOH without surfactant, from left to right (wt %):0.02, 0.04, 0.1, 0.2, 0.3, 0.5,0.8; d. NaOH with surfactant, from left to right (wt %):0.02, 0.04, 0.1, 0.2, 0.3, 0.5,0.8.


Energy & Fuels

60 start to inject chemical slug

Oil recovery, IOIP%

50 40

0.1 wt%

30

0.3 wt% 0.5 wt%

20

0.6 wt%

10

0.8 wt%

0 0

0.5

1

1.5

2

2.5

Volume of injection, PV

Relationship of oil recovery and injection volume of Na2CO3 at different alkali concentrations

Figure 6


50 Oil recovery, IOIP%

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 16 of 32

40 0.1 wt%

30

0.3 wt% 0.5 wt%

20

0.6 wt%

10

0.8 wt%

0 0

0.5

1

1.5

2

2.5

3

Volume injected, PV

Figure 7 Relationship of oil recovery and injection volume of Na2CO3-surfactant (300 μg/g) at different alkali concentrations


Page 17 of 32


80 70

start to inject chemical slug

60 50 40 NaOH NaOH NaOH NaOH NaOH

30 20 10

0.1 0.3 0.5 0.6 0.8

wt% wt% wt% wt% wt%

0 0

0.5

1

1.5 2 Volume injected,PV

2.5

3

Figure 8 Relationship of oil recovery and injection volume of NaOH at different alkali concentrations


70 60 50 40 NaOH NaOH NaOH NaOH NaOH

30 20 10 0 0

0.5

1 1.5 2 Volume of injected, PV

0.1 0.3 0.5 0.6 0.8

wt% wt% wt% wt% wt%

2.5

3

Figure 9 Relationship of Oil recovery and injection volume by NaOH-surfactant (300 μg/g) at different alkali concentrations 50 Tertiary recovery,IOIP%

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Na2CO3-S

40

NaOH-S NaOH

30

Na2CO3

20 10 0 0

0.1

0.2

0.3 0.4 0.5 0.6 Alkaline concentration, wt%

0.7

0.8

0.9

Figure 10 The relationships between tertiary oil recovery increment and alkali concentration of different chemical solutions


400 350 300 250 200 150 100 50 0

Page 18 of 32

NaOH NaOH NaOH NaOH NaOH

chemical slug injected

0

100

200

300

400

500 Time,mins

600

700

800

0.1 0.3 0.5 0.6 0.8

wt% wt% wt% wt% wt%

900

1000

Figure 11 Pressure drop changing during NaOH displacing processes

300 NaOH 0.1%

250

NaOH 0.3%

200

NaOH 0.5% NaOH 0.6%

150

NaOH 0.8%

100 50 0 0

100

200

300

400

500

600

700

800

900

1000

Time, mins

Figure 12 Pressure drop changing during NaOH-S displacing processes

350 300 Pressure drop ,cmH2O

Pressure drop cmH2O.

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Pressure,cmH2 O

Energy & Fuels

Na2CO3 0.1% Na2CO3 0.3% Na2CO3 0.5%

250

Na2CO3 0.6% Na2CO3 0.8%

200 start to inject alkaline solution

150 100 50 0 0

100

200

300

400

500 600 Time, mins

700

800

Figure 13 Pressure drop change during Na2CO3 displacing processes


900

1000

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350 Na2CO3 Na2CO3 Na2CO3 Na2CO3 Na2CO3

300

Pressure drop ,cmH2O

250

0.1% 0.3% 0.5% 0.6% 0.8%

with with with with with

surfactant surfactant surfactant surfactant surfactant

200 150

100 50

0 0

100

200

300

400

500

600

700

800

900

1000

Time, mins

Figure 14 Pressure change during Na2CO3-S displacing processes 300 Na2CO3-S NaOH-S NaOH Na2CO3

Pressure, cmH2O

250 200 150 100 50 0 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9


Figure 15 Pressure drop increments after chemical slugs injected at different chemical flooding processes.


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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels


50 40 Na2CO3:NaOH=1:4

30

Na2CO3:NaOH=2:3

20

Na2CO3:NaOH=1:1 Na2CO3:NaOH=3:2

10

Na2CO3:NaOH=4:1

0 0

0.5

1

1.5

2

2.5

3


Figure 16 Relationship of Oil recovery and injection volume by Na2CO3 and NaOH mixed solution (total alkali equals to that of Na2CO3 0.6 wt%)


Energy & Fuels


Oil recovery, IOIP%

60 50 40 Na2CO3:NaOH=2:3

30


20

Na2CO3:NqOH=1:4 Na2CO3:NaOH=1:1

10 0 0

0.5

1

1.5 2 Volume of injection, PV

2.5

3

Figure 17 Relationship of Oil recovery and injection volume by Na2CO3 and NaOH mixed solution (total alkali equals to that of Na2CO3 0.8wt%)

0.50 0.8 wt% 0.6 wt%

0.40 Tertiary recovery, IOIP

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 20 of 32

0.30

0.20

0.10

0.00

1:4

2:3

1:1

3:2

4:1

Ratio of Na2CO3 to NaOH

Figure 18 Tertiary oil recovery vs the ratios of Na2CO3 to NaOH at different total alkali concentrations.


Page 21 of 32

300 Na2CO3:NaOH=1:1


250

Na2CO3:NaOH=4:1 Na2CO3:NaOH =1:4

200


150 100 50 0 0

100

200

300

400

500

600

700

800

900

1000

Time, mins

Figure 19 Pressure drop during chemical flooding process using NaOH-Na2CO3(with total alkalinity equals to 0.6%)

300 Na2CO3:NaOH=1:1

250 Pressure drop ,cmH2O

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels


200


150 100 50 0 0

100

200

300

400

500

600

700

800

900

1000

1100

1200

Time, mins


The oil bank formed by oil droplets


Energy & Fuels

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Page 22 of 32

Figure 21 The picture of the oil bank formed when NaOH (o.5wt%) displacing injected

The oil bank formed by emulsion Figure 22 The picture of the oil bank formed when NaOH-S (NaOH 0.5 wt%, surfactant 300μg/g) displacing injected


Page 23 of 32

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Energy & Fuels

Table list Table 1 Physical Characteristics of Court Oil Table 2 Composition Analysis of Court Formation Brine Figure list Figure 1 IFT of oil/surfactant system Figure 2 Interfacial tensions of oil/Na2CO3-surfactant systems with different surfactant concentration Figure 3 Interfacial tensions of oil/NaOH-surfactant systems with different surfactant concentration Figure 4 The relationship between IFT and alkali concentration of different oil/alkali solutions . Figure 5 Emulsification of different alkali systems on Court oil. a. Na2CO3 without surfactant, from left to right (wt %): 0.1, 0.2, 0.3, 0.35, 0.4, 0.5, 0.6,0.8; b. Na2CO3 with surfactant, from left to right (wt %): 0.1, 0.2, 0.3, 0.35, 0.4, 0.5, 0.6,0.8; c. NaOH without surfactant, from left to right (wt %):0.02, 0.04, 0.1, 0.2, 0.3, 0.5,0.8; d. NaOH with surfactant, from left to right (wt %):0.02, 0.04, 0.1, 0.2, 0.3, 0.5,0.8. Figure 6 Relationship of oil recovery and injection volume of Na2CO3 at different alkali concentrations Figure 7 Relationship of oil recovery and injection volume of Na2CO3-surfactant (300 μg/g) at different alkali concentrations Figure 8 Relationship of oil recovery and injection volume of NaOH at different alkali concentrations Figure 9 Relationship of Oil recovery and injection volume by NaOH-surfactant (300 μg/g) at different alkali concentrations Figure 10 The relationships between tertiary oil recovery increment and alkali concentration of different chemical solutions Figure 11 Pressure drop changing during NaOH displacing processes Figure 12 Pressure drop changing during NaOH-S displacing processes Figure 13 Pressure drop change during Na2CO3 displacing processes Figure 14 Pressure change during Na2CO3-S displacing processes Figure 15 Pressure drop increments after chemical slugs injected at different chemical flooding processes. Figure 16 Relationship of Oil recovery and injection volume by Na2CO3 and NaOH mixed solution (total alkali equals to that of Na2CO3 0.6 wt%) Figure 17 Relationship of Oil recovery and injection volume by Na2CO3 and NaOH mixed solution (total alkali equals to that of Na2CO3 0.8wt%) Figure 18 Tertiary oil recovery vs the ratios of Na2CO3 to NaOH at different total alkali concentrations. Figure 19 Pressure drop during chemical flooding process using NaOH-Na2CO3(with total alkalinity equals to 0.6%) Figure 20 Pressure drop during chemical flooding process using NaOH-Na2CO3(with total alkalinity equals to 0.8%) Figure 21 The picture of the oil bank formed when NaOH-S (NaOH 0.5 wt%, surfactant 300μg/g) displacing injected


Energy & Fuels

Figure 22 The picture of the oil bank formed when NaOH-S (NaOH 0.5 wt%, surfactant 300μg/g) displacing injected

Tables and Figures Table 1 Physical Characteristics of Court Oil Density, kg/m3

Viscosity(22.5°C), mPa.s 1500

Total Acid Number, mg KOH/g sample

950.4

1.4

Table 2. Composition Analysis of Court Formation Brine Concentration, mg/L

Components

Concentration, mg/L

Barium

3.8

Magnesium

80

Chloride

7,870

Potassium

55

Calcium

76

Sulphate

390

Iron

0.016

Sodium

4,900

Manganese

< 0.005

Total dissolved solids

13,600

IFT, mN/m

Components

4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 0

100

200

300 400 500 600 700 Concentration of surfactant,μg/g

800

900

Figure. 1 IFT of oil/surfactant system

10 50μg/g 100μg/g

1

300μg/g 500μg/g

IFT,mN/m .

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 24 of 32

0.1

800μg/g

0.01

0.001

0.0001 0

0.1

0.2

0.3

0.4

0.5

0.6

Concentration of Na2CO3, wt%


0.7

0.8

0.9

Page 25 of 32

Figure.2 Interfacial tensions of oil/Na2CO3-surfactant systems with different surfactant concentration

1 surfactant 100μg/g surfactant 300μg/g surfactant 500μg/g

IFT, mN/m

0.1

0.01

0.001

0.0001 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

NaOH concentration, wt%

Figure3 Interfacial tensions of oil/NaOH-surfactant systems with different surfactant concentration

10000 Na2CO3 NaOH NaOH-S Na2CO3-S

1000 100 IFT, mN/m

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

10 1 0.1 0.01 0.001

0.0001 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9


Figure 4 The relationship between IFT and alkali concentration of different oil/alkali solutions .

a

b


Energy & Fuels

c

d Figure 5 Emulsification of different alkali systems on Court oil. a. Na2CO3 without surfactant, from left to right (wt %): 0.1, 0.2, 0.3, 0.35, 0.4, 0.5, 0.6,0.8; b. Na2CO3 with surfactant, from left to right (wt %): 0.1, 0.2, 0.3, 0.35, 0.4, 0.5, 0.6,0.8; c. NaOH without surfactant, from left to right (wt %):0.02, 0.04, 0.1, 0.2, 0.3, 0.5,0.8; d. NaOH with surfactant, from left to right (wt %):0.02, 0.04, 0.1, 0.2, 0.3, 0.5,0.8.


Oil recovery, IOIP%

50 40

0.1 wt%

30

0.3 wt% 0.5 wt%

20

0.6 wt%

10

0.8 wt%

0 0

0.5

1

1.5

2

2.5


Figure 6

Relationship of oil recovery and injection volume of Na2CO3 at different alkali concentrations



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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 32

40 0.1 wt%

30

0.3 wt% 0.5 wt%

20

0.6 wt%

10

0.8 wt%

0 0

0.5

1

1.5

2

2.5

3

Volume injected, PV

Figure 7 Relationship of oil recovery and injection volume of Na2CO3-surfactant (300 μg/g) at different alkali concentrations


Page 27 of 32


80 70


60 50 40 NaOH NaOH NaOH NaOH NaOH

30 20 10

0.1 0.3 0.5 0.6 0.8

wt% wt% wt% wt% wt%

0 0

0.5

1

1.5 2 Volume injected,PV

2.5

3

Figure 8 Relationship of oil recovery and injection volume of NaOH at different alkali concentrations


70 60 50 40 NaOH NaOH NaOH NaOH NaOH

30 20 10 0 0

0.5

1 1.5 2 Volume of injected, PV

0.1 0.3 0.5 0.6 0.8

wt% wt% wt% wt% wt%

2.5

3

Figure 9 Relationship of Oil recovery and injection volume by NaOH-surfactant (300 μg/g) at different alkali concentrations 50 Tertiary recovery,IOIP%

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Na2CO3-S

40

NaOH-S NaOH

30

Na2CO3

20 10 0 0

0.1

0.2

0.3 0.4 0.5 0.6 Alkaline concentration, wt%

0.7

0.8

0.9

Figure 10 The relationships between tertiary oil recovery increment and alkali concentration of different chemical solutions


400 350 300 250 200 150 100 50 0

Page 28 of 32

NaOH NaOH NaOH NaOH NaOH

chemical slug injected

0

100

200

300

400

500 Time,mins

600

700

800

0.1 0.3 0.5 0.6 0.8

wt% wt% wt% wt% wt%

900

1000

Figure 11 Pressure drop changing during NaOH displacing processes

300 NaOH 0.1%

250

NaOH 0.3%

200

NaOH 0.5% NaOH 0.6%

150

NaOH 0.8%

100 50 0 0

100

200

300

400

500

600

700

800

900

1000

Time, mins

Figure 12 Pressure drop changing during NaOH-S displacing processes

350 300 Pressure drop ,cmH2O


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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Pressure,cmH2 O

Energy & Fuels

Na2CO3 0.1% Na2CO3 0.3% Na2CO3 0.5%

250

Na2CO3 0.6% Na2CO3 0.8%

200 start to inject alkaline solution

150 100 50 0 0

100

200

300

400

500 600 Time, mins

700

800

Figure 13 Pressure drop change during Na2CO3 displacing processes


900

1000

Page 29 of 32

350 Na2CO3 Na2CO3 Na2CO3 Na2CO3 Na2CO3

300

Pressure drop ,cmH2O

250

0.1% 0.3% 0.5% 0.6% 0.8%

with with with with with

surfactant surfactant surfactant surfactant surfactant

200 150

100 50

0 0

100

200

300

400

500

600

700

800

900

1000

Time, mins

Figure 14 Pressure change during Na2CO3-S displacing processes 300 Na2CO3-S NaOH-S NaOH Na2CO3

Pressure, cmH2O

250 200 150 100 50 0 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9


Figure 15 Pressure drop increments after chemical slugs injected at different chemical flooding processes.


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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels


50 40 Na2CO3:NaOH=1:4

30

Na2CO3:NaOH=2:3

20


10

Na2CO3:NaOH=4:1

0 0

0.5

1

1.5

2

2.5

3


Figure 16 Relationship of Oil recovery and injection volume by Na2CO3 and NaOH mixed solution (total alkali equals to that of Na2CO3 0.6 wt%)


Energy & Fuels


Oil recovery, IOIP%

60 50 40 Na2CO3:NaOH=2:3

30


20

Na2CO3:NqOH=1:4 Na2CO3:NaOH=1:1

10 0 0

0.5

1

1.5 2 Volume of injection, PV

2.5

3

Figure 17 Relationship of Oil recovery and injection volume by Na2CO3 and NaOH mixed solution (total alkali equals to that of Na2CO3 0.8wt%)

0.50 0.8 wt% 0.6 wt%

0.40 Tertiary recovery, IOIP

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 30 of 32

0.30

0.20

0.10

0.00

1:4

2:3

1:1

3:2

4:1

Ratio of Na2CO3 to NaOH

Figure 18 Tertiary oil recovery vs the ratios of Na2CO3 to NaOH at different total alkali concentrations.


Page 31 of 32

300 Na2CO3:NaOH=1:1


250


200


150 100 50 0 0

100

200

300

400

500

600

700

800

900

1000

Time, mins


300 Na2CO3:NaOH=1:1

250 Pressure drop ,cmH2O

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels


200


150 100 50 0 0

100

200

300

400

500

600

700

800

900

1000

1100

1200

Time, mins


The oil bank formed by oil droplets


Energy & Fuels

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 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 32 of 32

Figure 21 The picture of the oil bank formed when NaOH (o.5wt%) displacing injected

The oil bank formed by emulsion Figure 22 The picture of the oil bank formed when NaOH-S (NaOH 0.5 wt%, surfactant 300μg/g) displacing injected


Evaluation of Different Factors on Enhanced Oil Recovery of Heavy Oil

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