Formation and Flow Behaviors of in Situ Emulsions in Heavy Oil

May 29, 2019 - 2 PV surfactant solution and 2 PV water were successively injected into ... SES solution and oil phase in a ratio of 2:3 after shrinkag...
0 downloads 0 Views 4MB Size
Download PDF
Article Cite This: Energy Fuels 2019, 33, 5961−5970

pubs.acs.org/EF

Formation and Flow Behaviors of in Situ Emulsions in Heavy Oil Reservoirs Fuwei Yu, Hanqiao Jiang, Zhen Fan, Fei Xu, Hang Su, and Junjian Li*

Downloaded via NOTTINGHAM TRENT UNIV on July 23, 2019 at 12:45:22 (UTC). See https://pubs.acs.org/sharingguidelines for options on how to legitimately share published articles.

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing), Beijing 102249, China ABSTRACT: As important intermediates generated during surfactant flooding, emulsions are widely acknowledged to be beneficial for enhanced oil recovery. Formation and flow behaviors of W/O and O/W emulsions have been reported in detail. Nevertheless, flow behaviors of W/O/W emulsions have not been sufficiently investigated, which are the most common products during chemical flooding in heavy oil reservoirs. In this study, two surfactant systems with different emulsification tendencies were evaluated by both core flooding and microfluidic experiments. Core flooding experiments with strong emulsifying surfactant (SES) resulted in W/O/W emulsions, while those with weak emulsifying surfactant (WES) produced pure oil and brine. Furthermore, microfluidic experiments indicated the emulsification process of W/O/W emulsion to be timedependent. The W/O emulsions were generally formed at the contact interface of heavy oil and SES solution under the action of convection and diffusion. In addition, the W/O/W emulsions were formed by W/O emulsions under the shear action of porous media during the later period of SES flooding. The formed W/O emulsion with high viscosity and the W/O/W emulsion could divert the following aqueous phase and displace the bypassed oil phase, which contributed to an additional oil recovery.

1. INTRODUCTION Heavy oil has been reported as one of the largest resource of fossil fuels in the world.1 However, its development has been significantly constrained by its high viscosity.2 Correspondingly, a variety of technologies are proposed and applied for its enhanced oil recovery (EOR) through flow capacity promotion, such as thermal3 and chemical flooding.4 Given the downturn that the petroleum industry is currently confronted with, thermal EOR methods are inefficient and inviable for deeply buried or thin heavy oil reservoirs.4 In this context, some other EOR technologies, such as surfactant flooding, polymer flooding, and alkali flooding, are more economically effective.5 This paper aimed to explore the surfactant flooding process in heavy oil reservoirs. As important intermediates generated during surfactant flooding, emulsions, including microemulsion, W/O emulsion, O/W emulsion, and multiple emulsion, play important roles in heavy oil EOR.6 For surfactant flooding, which aimed to form O/W emulsions, the bypassed oil after water flooding could be emulsified at the surface of the water flow path and produced at relatively low-pressure gradients.7 However, due to the low viscosity of the O/W emulsions, the surfactant solutions usually propagated rapidly through the reservoirs.8 Thus, the high-viscosity W/O emulsions were usually formed during surfactant or alkali flooding, which would block the initial water flow path and result in a high oil recovery.9 Meanwhile, it should be noted that the phase behavior of the emulsions under the flow condition was dynamic and the in situ emulsion formed during surfactant flooding was not of a single type in complex underground situations.10−12 Furthermore, the W/O/ W emulsions have been found as common products in the studies on heavy oil EOR process by Bai et al.,13 Wu et al.,14 Balsamo et al.,15 and Malkin et al.16 However, most previous studies exclusively highlighted the flow behaviors of single type of emulsions but failed to sufficiently investigate the formation © 2019 American Chemical Society

and EOR mechanisms of complex emulsions such as W/O/W emulsions.10,17,18 Correspondingly, this study aimed to explore the emulsification and flow behaviors of W/O/W emulsions during surfactant flooding and elaborate the EOR mechanism of the in situ W/O/W emulsions. Micromodels are effective tools for the visualization and investigation of the emulsion flow in porous media, and many EOR mechanisms of emulsion flooding have been reported in previous microfluidic studies.19−22 By using ideal micromodels, the formation and phase behaviors of emulsions were explored. Xu et al.23,24 visualized the formation and flow behaviors of O/ W emulsions by an ideal fracture/matrix micromodel. Unsal et al.25 observed the formation of microemulsions by a T-junction micromodel and investigated the dynamic phase behaviors of microemulsions. Broens et al.26 further coupled the flow rate and spontaneous emulsification rate by a dead-end-pore micromodel. In ideal conditions, the flow rate, salinity, surfactant concentration, and oil−water ratio were all constant, the emulsions were easily controlled, and the dynamic behavior shared good consistency with the static one. However, in the experiments that were designed and conducted in reservoir micromodels with the aim to mimic the EOR process, nonequilibrium phase behaviors were observed. Bazazi et al.27 visualized the expansion of water droplets in the microemulsion phase by a heterogeneous reservoir micromodel. Xiao et al.28 observed the coexistence of O/W and W/ O emulsions during alkali flooding in a reservoir micromodel and proposed an EOR mechanism for the transition behavior of emulsion types. Tagavifar et al.29 discussed the phase change from equilibrium to nonequilibrium microemulsion at the pore Received: January 15, 2019 Revised: May 26, 2019 Published: May 29, 2019 5961

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970

Article

Energy & Fuels Table 1. Properties of the Crude Oil property

density (25 °C)

viscosity (25 °C)

resin + asphaltene

acid value

value

0.955 g/cm3

261.83 mPa s

21.21%

2.38 mg of KOH/g

Table 2. Properties of Surfactant Solutions composition IFT viscosity (25 °C)

SES

WES

0.75 wt % AAPES-9, 0.25% AG, 2.5% n-butanol and 29 000 ppm NaCl 0.17 mN/m 1.78 mPa s

1% AAPES-9 and 29 000 ppm NaCl 2.05 mN/m 2.01 mPa s

were obtained from the Shengli Oilfield. n-Butanol was obtained from Sinopharm Chemical Reagent Co., Ltd., China. In the SES solution, AG and n-butanol were added to further lower the interfacial tension (IFT) between the surfactant solution and heavy oil so as to construct the complex emulsion phase behavior. The IFT between the surfactant solution and heavy oil was tested by the Texas-500 spinning drop interfacial tension meter with a speed of 5000 rpm at the temperature of 25 °C. Viscosities of the surfactant solutions were measured by the Brookfield DV2T rotating viscometer at 25 °C. Two sets of surfactant solutions were prepared, and their properties are shown in Table 3. 2.2. Tests on Emulsion Phase Behavior. SES and WES solutions were mixed with heavy oil at a certain volume ratio of aqueous phase/oil phase (2:3) in cylindrical glass tubes, respectively. Then, they were stirred together at low speed (8000 rpm) for 4 min. Images of glass tubes and microscopic images of emulsions were respectively captured after stirring was stopped and breaking (10 h) was observed. To quantify the aqueous/oil phase separation rate, another two sets of samples were prepared and placed in the Turbiscan Lab Expert (Formulaction, France).31 The measurements were performed at 25 °C for 10 h. The emulsion phase behavior was evaluated by monitoring the transmittance and backscattering (BS) of a pulse near-infrared LED at a wavelength of 880 nm. 2.3. Sandstone Core Flooding Experiments. The core flooding setup used in this study consisted of six parts: a Hasslertype core holder, a differential pressure transducer with a pressure range of 0−1.5 MPa for the pressure drop measurement across the core, an absolute pressure gauge with a pressure range of 0−16 MPa for the confining pressure measurement, Hastelloy pipes, an ISCO pump with piston accumulators for different fluids, and an electronic scale for the produced fluid measurements. Core flooding experiments were conducted with different surfactant solutions at room temperature, as shown in Table 3. The production pressure of the core flooding experiment was the atmospheric pressure. Both core flooding experiments conformed to the following procedure:

scale and presented the local equilibrium assumption for emulsification. Alzahid et al.30 correlated the flow regimes of surfactant flooding with the emulsion phase behavior in a node pattern PDMS micromodel. These findings directly proved the presence of complex phase behaviors of emulsions during chemical flooding in porous media. Meanwhile, they raised further questions about the formation of complex emulsions in heavy oil reservoirs and their flooding dynamics. In this study, core flooding and microfluidic experiments were conducted to shed light on the surfactant flooding process in heavy oil reservoirs. Through the visualization of the displacement process, formation and flow behaviors of microemulsion and W/O/W emulsion were elaborated.

2. EXPERIMENTAL SECTION 2.1. Materials. A heavy oil sample from Gudao Oilfield (with a density of 0.955 g/cm3 and a viscosity of 261.83 mPa·s at 25 °C) was used, and its properties are shown in Table 1. The formation and injection brine are kept the same for all the experiments, which is 29 000 ppm NaCl solution. Two sandstone cores from the Gudao Oilfield were employed for the core flooding experiments; the properties of the cores are shown in Table 2. A glass-etching micromodel mimicking a quarter five-spot pattern was utilized (micromodel B, Figure 1), with a total flow area

(1) Before core flooding experiments, sandstone cores were dried at 110 °C for 24 h to remove interstitial water, followed by measurements of core sample properties (length, diameter, and weight), filtering of heavy oil with 0.85 mm filter paper, and filtering of displacement fluids with 0.25 mm filter paper. (2) The cores were vacuumed for 24 h and then saturated by brine, accompanied by porosity calculation through recording weights of brine-saturated cores. (3) The cores were loaded in a Hassler-type core-holder with a confining pressure of 6 MPa, and permeability analysis of the brine-saturated cores was implemented based on Darcy’s law. (4) Heavy oil was injected into the cores at a constant flow rate of 0.15 mL/min until connate water saturation was reached. (5) Water flooding was performed at a constant flow rate of 0.04 mL/min, which corresponded to approximately 1.42 ft/day, until the water cut reached 99%. (6) 2 PV surfactant solution and 2 PV water were successively injected into the cores at a common flow rate of 0.04 mL/min.

Figure 1. Schematic diagram of micromodel B. of 1.2 cm × 1.2 cm and an etched depth of 15 μm. The average absolute permeability is 2560 mD (measured by recording pressure drops at numerous flow rates according to Darcy’s law), and the average porosity is 0.6197 (calculated by image analysis). Micromodels A and B were respectively soaked in 1 wt % trimethylsilyl chloride in methanol solution before packaging to change the wettability of the glass. Oil/water contact angle was around 121.4°. Sulfonate anionic−nonionic surfactant, alkyl alcohol polyoxyethylene ether sulfonate (AAPES-9), and alkyl glycosides (AG)

2.4. Porous Micromodel Flooding Experiments. To investigate the phase behavior and EOR efficiency of the surfactant solution, water and surfactant floodings were conducted in porous 5962

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970

Article

Energy & Fuels Table 3. Schedule of Core Flooding and Microfluidic Experiments no.

porous media

weight (g)

length (cm)

diameter (cm)

porosity

permeability (mD)

displacement fluids

C1 C2 M1 M2 M3

sandstone core sandstone core micromodel micromodel micromodel

84.38 83.59

10.35 10.21

2.51 2.50

0.2677 0.2787 0.6197 0.6197 0.6197

513.25 522.69 2560 2560 2560

water 2 PV SES solution 2 PV water water 2 PV WES solution 2 PV water water SES solution WES solution

Figure 2. Stability of emulsions generated by the SES solution over a time interval of 10 h.

Figure 3. Stability of emulsions generated by the WES solution over a time interval of 10 h.

Figure 4. Emulsion phase behavior of the SES solution: (a) mixture of the SES solution and the oil phase in a ratio of 2:3 as soon as the stirring stopped; (b) microscopic image of emulsions generated by the SES solution as soon as the stirring stopped; (c) microscopic image of emulsions in the upper phase of the glass tube after shrinkage for 10 h; and (d) mixture of the SES solution and oil phase in a ratio of 2:3 after shrinkage for 10 h.

5963

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970

Article

Energy & Fuels

Figure 5. Emulsion phase behavior of the WES solution: (a) mixture of the WES solution and oil phase in a ratio of 2:3 as soon as the stirring stopped; (b) microscopic image of emulsions generated by the WES solution as soon as the stirring stopped; (c) microscopic image of the oil phase in the upper phase of the glass tube after shrinkage for 10 h; and (d) mixture of the WES solution and oil phase at a ratio of 2:3 after shrinkage for 10 h. micromodels. Before experiments, micromodels were repeatedly washed with kerosene, ethanol, and deionized water. Then, they were dried and saturated with the heavy oil phase using a neMESYS syringe pump. The flow rate of the aqueous phase was controlled at a constant value of 0.02 μL/min, corresponding to around 1.22 ft/day, which is a typical flow rate used in the EOR process.29 The flooding process was observed by a Leica M165FC microscope, and recorded by a Leica CCD camera (100 fps, 1600 × 1200 pixels). Flooding inlet was in the lower left corner for all figures.

3. RESULTS AND DISCUSSION 3.1. Emulsion Phase Behavior. Emulsion phase behaviors of the two surfactant systems were examined to investigate the differences in their emulsifying tendencies. Phase separation rates of SES and WES solutions were captured by the Turbiscan Lab Expert (Figures 2 and 3). Emulsions generated by the WES solution were demonstrated to have an earlier starting time of the phase separation and less emulsion block than those generated by the SES solution. Emulsions generated by the WES solution completely broke after 7 h. The shrinkage of emulsions formed by the SES solution was stopped after around 9 h, and tight emulsion blocks were observed in the upper phase. After shrinkage, a small amount of oil phase was emulsified into the SES solution, forming a brown Winsor I type microemulsion at the bottom of the glass tube (Figure 4). To characterize the morphology of the generated emulsions, microscopic images at the beginning and end of shrinkage were captured (Figures 4 and 5). It was observed that a single O/W emulsion was generated in the WES solution, whereas multiple emulsions emerged in the SES solution, including light yellow microemulsion, W/O emulsion, and W/O/W emulsion, when the aqueous phase was mixed with the oil phase. After the shrinkage, the W/O/W emulsion generated by the SES solution broke. Meanwhile, aqueous phase droplets were observed in the upper phase (Figure 4c), which implied the tight emulsion block formed by the SES solution to be a W/O type emulsion. These aqueous phase droplets displayed light yellow color due to the solution of some oil phase into the SES solution. In contrast, all of the O/W emulsions generated by the WES solution broke and formed a pure oil phase after the shrinkage (Figure 5c). 3.2. Identification and Flow Behaviors of In Situ Emulsions. Core flooding experiments were conducted to clarify the in situ emulsions formed by SES and WES solutions in sandstone cores. Figure 6 shows the heavy oil recovery

Figure 6. Water cut, recovery, and pressure drop as functions of fluid injection volumes: (a) C1 experiment and (b) C2 experiment.

factor, water cut, and injection pressure of the core flooding experiments as functions of pore volumes of injected fluids. Results of the C1 experiment showed that the initial water flooding, SES flooding, and chase water flooding achieved additional recoveries of the original oil in place (OOIP) of 32.7, 26.7, and 4.9% (Figure 6a), respectively. It could also be observed from the pressure drop curve that the injection pressure started to rise when the SES injection exceeded 0.76 PV and peaked when the SES injection reached 0.97 PV. To shed light on effects of SES, microscopic images of the produced fluid were captured and analyzed (Figure 7). The produced fluids seemed to be W/O/W emulsions (Figure 5964

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970

Article

Energy & Fuels

Figure 7. Images of the produced fluid during surfactant flooding: (a) the produced fluid in C1 experiment before emulsion breakage; (b) the produced fluid in C1 experiment after emulsion breakage; (c, d) microscopic images of the produced fluid in C1 experiment before emulsion breakage; and (e) the produced fluid in C2 experiment after emulsion breakage.

Figure 8. Original images of the micromodel flooding at different times: (a) water flooding; (b) WES flooding; and (c) SES flooding.

7c,d). As shown in Figure 7a,b, the produced W/O/W emulsions broke after shrinkage for around 2 h and O/W emulsions were formed in the upper phase, which is consistent

with the results of the emulsion phase behavior tests. Results of the C2 experiment showed that the initial water flooding, SES flooding, and chase water flooding achieved additional 5965

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970

Article

Energy & Fuels

Figure 9. Highlights of the microscopic images after WES flooding. Note that red circles indicate oil droplets formed during WES flooding.

Figure 10. Highlights of the microscopic images after SES flooding. Note that red circles indicate the W/O/W emulsion and blue arrows indicate the W/O emulsion.

recovery increased slightly. Different from the flooding processes of the water phase and WES solution, emulsion phase change was observed during SES flooding, especially in the initial flowing path of water breakthrough. Moreover, highviscosity W/O emulsions were found to be formed due to an interaction between the oil phase and SES, blocking the flow path of the initial aqueous phase and diverting the subsequent aqueous phase to unswept areas (Figures 8c and 10). The W/ O/W emulsion, similar to the product of the core flooding experiment, was also observed (Figure 10). As proposed by Malkin et al.,16 the flow behaviors of the W/O/W emulsion were similar to those of the O/W emulsion and could be recovered more easily than those of the W/O emulsion. Results of micromodel flooding experiments further confirmed the existence of a complex phase behavior during the SES flooding. 3.3. Emulsification and EOR Potential of In Situ Emulsions. Core flooding experiments and micromodel flooding experiments clearly demonstrated the existence of complex emulsions generated by the SES solution. Nevertheless, the above results failed to clarify the emulsification and flow behaviors of these complex emulsions. Therefore, these experiments were repeated, accompanied by discussions on the formation of emulsions and their flow behaviors. Figure 11 provides a detailed view of the interface where streams of oil and SES solution first came in contact. Microemulsion was formed as a boundary layer at the aqueous/heavy oil contact surface. Similar results were reported by Unsal et al.25 and Tagavifar et al.,29 which were attributed to the diffusion at the two-phase contact surface. As shown in Figure 12, the microemulsion could peel off the heavy oil phase at the glass surface to improve the sweep area, which is highlighted by blue circles. This indicated the microemulsion to be a wetting phase

recoveries of OOIP of 30.4, 15.9, and 2.8% (Figure 6b), respectively. During WES flooding, the injection pressure started to rise when the WES injection exceeded 0.91 PV and peaked when the WES injection reached 1.15 PV, which indicated the possible formation of the O/W emulsion. However, no stable O/W emulsion was recovered (Figure 7e). Based on the above results, correlations between the emulsion phase behavior in cylindrical glass tubes and the flow dynamics of in situ emulsions formed by SES and WES in cores could be obtained, which also implied the huge significance of the investigation on the flow behaviors of W/ O/W emulsions in understanding the SES solution flooding process. To further investigate the flow physics of the SES and WES flooding, three micromodel flooding tests were conducted; the processed images of oil displacement are shown in Figure 8. Viscous fingering was found to be the dominant initial flow behaviors for all three experiments due to the similar mobility of the three aqueous phases. During water flooding, oil phase was rarely recovered after water breakthrough (Figure 8a), which indicated that most of the water phase followed the flowing path of the initial water flooding. Compared with the processed images of water flooding experiments, the decrease in the oil saturation with continuous WES solution flooding was still observed after the WES solution breakthrough. Figure 9 displays the formation of oil droplets during the WES flooding. A few oil droplets could flow with the aqueous phase, whereas large oil droplets might block the flow path of the aqueous phase and divert the subsequent aqueous phase to unswept areas, both of which resulted in heavy oil recovery enhancement. Though the WES solution that displayed weak emulsifying tendency has been discussed in Section 3.1, no obvious emulsion phase behavior was observed and the oil 5966

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970

Article

Energy & Fuels

Figure 11. Heavy oil and SES solution contact surface.

Figure 13. Dissolution effect of the microemulsion phase for heavy oil, indicated by blue circles.

Figure 14. Phase change behavior of (a) microemulsion and (b) W/ O emulsion.

existed under the flow condition. This phase change behavior could be explained under the assumption of local equilibrium of microemulsion as proposed by Quintela et al.34 and Tagavifar et al.29 Microemulsion films attached on the micromodel surface were under uniform extrusion of the aqueous phase flow. The uniform extrusion force on the microemulsion led to the uniform thickness of the microemulsion film. Because the thin film tension increases with film thickness,35,36 the gradient of the local interfacial tension could be caused by the uniform thickness of the microemulsion film, thereby generating a Marangoni flow36−38 from the surrounding area. This kind of lateral flow not only drove the microemulsion at the channel edge to the center, leading to the thickening of the microemulsion, but also carried aqueous droplets into the microemulsion, resulting in the phase change from the microemulsion to W/O emulsion. Further studies are needed to explain how the flow of excessive aqueous phase destroyed the structure of the microemulsion. This phase behavior implied the local EOR performance of in situ microemulsion under the flow condition. Emulsification of bulk oil at the aqueous/oil interface was observed (Figure 15), with red arrows indicating the emulsification front. As shown in Figure 15, the W/O emulsion was formed when the oil phase and aqueous phase

Figure 12. Microemulsion dynamics over time. Red arrows mark the phase change behavior of the microemulsion (detailed images can refer to Figure 10), blue circles indicate the peeling off of the oil attached on channel walls, and green arrows indicate the lateral flow direction during the microemulsion phase change.

in the micromodel, which was consistent with the description of the microemulsion wettability proposed by Hellweg et al.32 and Delshad et al.33 Furthermore, the residual oil attached on the edges of the channels was solubilized into microemulsion and then trapped on the glass surface due to its wettability (Figure 13). This dissolution effect could be explained by the low IFT between the microemulsion and heavy oil phase. Dynamic changes of the microemulsion were tracked, which seemed to be able to provide an explanation for this phenomenon. As shown in Figures 12 and 14, the microemulsion trapped on the glass surface was transformed to the W/O emulsion during the continuous aqueous phase flooding, which implied that the phase change of the microemulsion 5967

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970

Article

Energy & Fuels

Figure 15. Emulsification of the oil phase on the contact surface of oil and aqueous phase: (a) original images and (b) grayscale images for better visualization.

were brought in contact. Shanhidzaeh et al.39 and Spooner et al. 40,41 have claimed that this kind of spontaneous emulsification without an external applied shear was induced by the Marangoni stresses. As proposed by Tagavifar et al.,29 this emulsification process can be explained by the Marangoni flow formed by the IFT gradient at the interface of the oil and aqueous phases. The aqueous phase droplets were dragged into the oil phase by the Marangoni flow to form the W/O emulsion. As the effect of the Marangoni flow was limited, only peripheral oil phases in the bulk oil were emulsified into the W/O emulsion (Figure 16). Because the formation of the W/

Figure 17. Formation of W/O/W emulsion (indicated by blue circles) under the flow condition.

emulsion observed in the C1 experiment. This implied that the surfactant could be adsorbed on the surface of the W/O emulsion, thereby forming the interfacial film with a certain strength in the environment of excessive surfactant solution. No coalescence occurred when two drops of the W/O/W emulsion collided with each other under the influence of the interfacial film (Figure 18). The W/O/W emulsion could be extruded and deformed to flow through narrow channels and divert aqueous phase flow to unswept areas, resulting in enhanced heavy oil recovery. Based on the above discussion, the emulsification process during the SES flooding is illustrated in Figure 19. First, the microemulsion and the W/O emulsion were formed at the

Figure 16. Emulsion (green arrow) with excessive aqueous phase and emulsion (red arrow) on the oil-aqueous phase transition zone.

O emulsion is flow-rate-dependent,42 emulsions with higher viscosity formed during the flowing process were usually distributed in the high flow rate areas, and they diverted the aqueous phase flow to unswept areas. Furthermore, the W/O emulsion could also be displaced by following aqueous flooding, and thus be easily dispersed into W/O emulsion droplets (Figure 17), which were similar to the W/O/W

Figure 18. Flow steering (indicated by red arrows) of the aqueous phase under the influence of snapping off caused by the oil droplet (indicated by red circles). 5968

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970

Article

Energy & Fuels

Figure 19. Schematic diagram illustrating the complex emulsification process during SES flooding.

porous media in the SES flooding process. The in situ microemulsion formed by SES solutions could peel off the heavy oil attached on the oil-wet surface and dissolve the remaining oil due to its low interfacial tension. The formed W/ O emulsion with high viscosity and the W/O/W emulsion could divert the following SES solution to displace the bypassed oil phase, which contributed to an additional oil recovery.

contact interface of the heavy oil and SES solution under the action of convection and diffusion. The formed microemulsion was then peeled off and dissolved in the trapped oil phase, but the microemulsion was unstable under the flow condition and could be easily transformed into W/O emulsion due to flow disturbance. Different from the experiments in the burettes, the emulsion was relatively stable under the flow condition in the porous media, and its EOR effect was significant. Because of the flow rate dependency of the emulsion formation, the W/O emulsion with higher viscosity was usually formed in areas with higher aqueous phase flow rates, and it could divert the following aqueous phase flow to unswept areas. Furthermore, the surfactant was adsorbed on the surface of the W/O emulsion to form an interfacial film of a certain strength, while W/O/W droplets were formed under the shear action of porous media in the flooding process. The bypassed oil could be displaced when these droplets got stuck.

■

AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. ORCID

Junjian Li: 0000-0003-0336-8452 Notes

The authors declare no competing financial interest.

■

4. CONCLUSIONS Core flooding experiments and microfluidic experiments were combined to elaborate the in situ emulsion flooding process at room temperature. The SES and WES solutions were quantified and differentiated in terms of their emulsification tendency and EOR potential in these particular experimental conditions (room temperature, aqueous phase composition, and heavy oil properties). Based on the core flooding experiments, W/O/W emulsions were confirmed to be the ultimately produced fluids of SES flooding, which were different from those of WES flooding. Further efforts were made to investigate the formation and flow dynamics of W/O/W emulsions formed by SES solutions in a porous micromodel. According to the observations in the microfluidic experiments, the complex emulsification process of the selected oil−water system during SES flooding was well understood. Microemulsion and W/O emulsion were formed at the contact surface of heavy oil and SES solutions under the action of convection and diffusion. The flow rate dependency contributed to the W/O emulsion formation dominantly in the high flow rate areas. The subsequently formed interfacial films under the influence of excessive surfactant promoted the generation of W/O/W emulsion under the shear action of

ACKNOWLEDGMENTS This research was supported by the Major Program of National Natural Science Foundation of China (Grant ID: 2017ZX05009-005). We would like to sincerely thank Dr. Liang Tianbo from China University of Petroleum (Beijing) for proofreading the manuscript. In addition, we sincerely thank the editor and reviewers from Energy & Fuels for their time and efforts on improving the quality of this paper.

■

REFERENCES

(1) Saboorian-Jooybari, H.; Dejam, M.; Chen, Z. X. Heavy oil polymer flooding from laboratory core floods to pilot tests and field applications: Half-century studies. J. Pet. Sci. Eng. 2016, 142, 85−100. (2) Sun, X.; Zhang, Y.; Chen, G.; Liu, T.; Ren, D.; Ma, J.; Sheng, Y.; Karwani, S. Wettability of hybrid nanofluid-treated sandstone/heavy oil/brine systems: implications for enhanced heavy oil recovery potential. Energy Fuels 2018, 32, 11118−11135. (3) Baghernezhad, D.; Siavashi, M.; Nakhaee, A. Optimal scenario design of steam-assisted gravity drainage to enhance oil recovery with temperature and rate control. Energy 2019, 166, 610−623. (4) Aitkulov, A.; Luo, H. S.; Lu, J.; Mohanty, K. K. Alkali-cosolventpolymer flooding for viscous oil recovery: 2D evaluation. Energy Fuels 2017, 31, 7015−7025. 5969

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970

Article

Energy & Fuels

(26) Broens, M.; Unsal, E. Emulsification kinetics during quasimiscible flow in dead-end pores. Adv. Water Resour. 2018, 113, 13− 22. (27) Bazazi, P.; Sanati-Nezhad, A.; Hejazi, S. H. Role of chemical additives on water-based heavy oil mobilization: A microfluidic approach. Fuel 2019, 241, 1195−1202. (28) Xiao, R.; Teletzke, G. F.; Lin, M. W.; Glotzbach, R. C.; Aitkulov, A.; Yeganeh, M. In A Novel Mechanism of Alkaline Flooding to Improve Sweep Efficiency for Viscous Oils, SPE Annual Technical Conference and Exhibition; Society of Petroleum Engineers; Society of Petroleum Engineers: San Antonio, Texas, USA, 2017. (29) Tagavifar, M.; Xu, K.; Jang, S. H.; Balhoff, M. T.; Pope, G. A. Spontaneous and flow-driven interfacial phase change: dynamics of microemulsion formation at the pore scale. Langmuir 2017, 33, 13077−13086. (30) Alzahid, Y. A.; Mostaghimi, P.; Walsh, S. D. C.; Armstrong, R. T. Flow regimes during surfactant flooding: The influence of phase behavior. Fuel 2019, 236, 851−860. (31) Celia, C.; Trapasso, E.; Cosco, D.; Paolino, D.; Fresta, M. Turbiscan lab expert analysis of the stability of ethosomes and ultradeformable liposomes containing a bilayer fluidizing agent. Colloids Surf., B 2009, 72, 155−160. (32) Hellweg, T.; Brûlet, A.; Sottmann, T. Dynamics in an oil continuous droplet microemulsion as seen by quasielastic scattering techniques. Phys. Chem. Chem. Phys. 2000, 2, 5168−5174. (33) Delshad, M.; Bhuyan, D.; Pope, G. A.; Lake, L. W. In Effect of Capillary Number on the Residual Saturation of a Three-Phase Micellar Solution, SPE Enhanced Oil Recovery Symposium; Society of Petroleum Engineers: Tulsa, Oklahoma, USA, 1986. (34) Quintela, M. A. L.; Fernández Nóvoa, A.; Quibén, J.; Losada, D.; Ferreiro, C. Nonequilibrium Phenomena in Critical Microemulsions. In Trends in Colloid and Interface Science I; Springer, 1988; Vol. 76, pp 165−168. (35) Hirasaki, G. Thermodynamics of Thin Films and Three-Phase Contact Regions. Interfacial Phenomena in Petroleum Recovery; Marcel Dekker Inc., 1991; pp 23−75. (36) Warren, P. B.; Buchanan, M. Kinetics of surfactant dissolution. Curr. Opin. Colloid Interface Sci. 2001, 6, 287−293. (37) Wilde, P.; Mackie, A.; Husband, F.; Gunning, P.; Morris, V. Proteins and emulsifiers at liquid interfaces. Adv. Colloid Interface Sci. 2004, 108−109, 63−71. (38) Chen, I.; Akbulut, M. Nanoscale dynamics of heavy oil recovery using surfactant floods. Energy Fuels 2012, 26, 7176−7182. (39) Shahidzadeh, N.; Bonn, D.; Aguerre-Chariol, O.; Meunier, J. Spontaneous emulsification: relation to microemulsion phase behavior. Colloids Surf., A 1999, 147, 375−380. (40) Spooner, S.; Li, Z. S.; Sridhar, S. Spontaneous Emulsification as a Function of Material Exchange. Sci. Rep. 2017, 7, No. 5450. (41) Spooner, S.; Rahnama, A.; Warnett, J. M.; Williams, M. A.; Li, Z. S.; Sridhar, S. Quantifying the Pathway and Predicting Spontaneous Emulsification during Material Exchange in a Two Phase Liquid System. Sci. Rep. 2017, 7, No. 14384. (42) Walstra, P. Principles of emulsion formation. Chem. Eng. Sci. 1993, 48, 333−349.

(5) Le Van, S.; Chon, B. H. Chemical flooding in heavy-oil reservoirs: from technical investigation to optimization using response surface methodology. Energies 2016, 9, 711. (6) Yu, L.; Dong, M.; Ding, B.; Yuan, Y. Emulsification of heavy crude oil in brine and its plugging performance in porous media. Chem. Eng. Sci. 2018, 178, 335−347. (7) Liu, Z. Y.; Li, Y. Q.; Luan, H. X.; Gao, W. B.; Guo, Y.; Chen, Y. H. Pore scale and macroscopic visual displacement of oil-in-water emulsions for enhanced oil recovery. Chem Eng. Sci. 2019, 197, 404− 414. (8) Hirasaki, G. J.; van Domeselaar, H. R.; Nelson, R. C. Evaluation of the Salinity Gradient Concept in Surfactant Flooding. Soc. Pet. Eng. J. 1983, 23, 486−499. (9) Kumar, R.; Dao, E.; Mohanty, K. K. Heavy oil recovery by in-situ emulsion formation. Soc. Pet. Eng. J. 2012, 17, 326−334. (10) Perazzo, A.; Tomaiuolo, G.; Preziosi, V.; Guido, S. Emulsions in porous media: From single droplet behavior to applications for oil recovery. Adv. Colloid Interface Sci. 2018, 256, 305−325. (11) Nguele, R.; Sasaki, K.; Sugai, Y.; Omondi, B.; Al-Salim, H. S.; Ueda, R. Interactions between Formation Rock and Petroleum Fluids during Microemulsion Flooding and Alteration of Heavy Oil Recovery Performance. Energy Fuels 2017, 31, 255−270. (12) Li, Z.; Wu, H.; Yang, M.; Jiang, J.; Xu, D.; Feng, H.; Lu, Y.; Kang, W.; Bai, B.; Hou, J. Spontaneous emulsification via once bottom-up cycle for the crude oil in low permeability reservoirs. Energy Fuels 2018, 32, 3119−3126. (13) Bai, Y.; Xiong, C.; Shang, X.; Xin, Y. Experimental study on ethanolamine/surfactant flooding for enhanced oil recovery. Energy Fuels 2014, 28, 1829−1837. (14) Wu, Z.; Huiqing, L.; Wang, X.; Zhang, Z. Emulsification and improved oil recovery with viscosity reducer during steam injection process for heavy oil. J. Ind. Eng. Chem. 2018, 61, 348−355. (15) Balsamo, V.; Nguyen, D.; Phan, J. Non-conventional techniques to characterize complex sagd emulsions and dilution effects on emulsion stabilization. J. Pet. Sci. Eng. 2014, 122, 331−345. (16) Malkin, A. Y.; Zuev, K.; Arinina, M. P.; Kulichikhin, V. G. Modifying the viscosity of crude heavy oil by using surfactants and polymer additives. Energy Fuels 2018, 32, 11991−11999. (17) Liang, T.; Zhou, F.; Lu, J.; et al. Evaluation of wettability alteration and ift reduction on mitigating water blocking for lowpermeability oil-wet rocks after hydraulic fracturing. Fuel 2017, 209, 650−660. (18) Mohammadzadeh, O.; Sedaghat, M. H.; Kord, S.; Zendehboudi, S.; Giesy, J. P. Pore-level visual analysis of heavy oil recovery using chemical-assisted waterflooding process - Use of a new chemical agent. Fuel 2019, 239, 202−218. (19) Ning, J.; Wei, B.; Mao, R.; Wang, Y.; Shang, J.; Sun, L. Porelevel observations of an alkali-induced mild o/w emulsion flooding for economic enhanced oil recovery. Energy Fuels 2018, 32, 10595− 10604. (20) Xu, K.; Liang, T.; Zhu, P.; Qi, P.; Lu, J.; Huh, C.; Balhoff, M. A 2.5-D glass micromodel for investigation of multi-phase flow in porous media. Lab Chip 2017, 17, 640−646. (21) Xu, K.; Agrawal, D.; Darugar, Q. Hydrophilic Nanoparticlebased enhanced oil recovery: microfluidic investigations on mechanisms. Energy Fuels 2018, 32, 11243−11252. (22) Yu, F.; Jiang, H.; Li; Fan, Z.; Xu, F.; Su, H.; Cheng, B.; Liu, R.; Li, J. Flow physics of Winsor I type surfactant solution enhanced imbibition recovery in oil-wet porous media. Petro. Explor. Dev. 2018, 46, 1−9. (23) Xu, K.; Zhu, P.; Huh, C.; Balhoff, M. T. Microfluidic investigation of nanoparticles’ role in mobilizing trapped oil droplets in porous media. Langmuir 2015, 31, 13673−13679. (24) Xu, K.; Zhu, P.; Colon, T.; Huh, C.; Balhoff, M. A microfluidic investigation of the synergistic effect of nanoparticles and surfactants in macro-emulsion based EOR. Soc. Pet. Eng. J. 2017, 22, 459−469. (25) Unsal, E.; Broens, M.; Armstrong, R. T. Pore scale dynamics of microemulsion formation. Langmuir 2016, 32, 7096−7108. 5970

DOI: 10.1021/acs.energyfuels.9b00154 Energy Fuels 2019, 33, 5961−5970