Pore-Scale Experiment on Blocking Characteristics and EOR

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Pore-Scale Experiment on Blocking Characteristics and EOR Mechanisms of Nitrogen Foam for Heavy Oil: A 2D Visualized Study Zhengbin Wu, Huiqing Liu, Zhanxi Pang, Chuan Wu, and Min Gao Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01769 • Publication Date (Web): 19 Sep 2016 Downloaded from http://pubs.acs.org on September 24, 2016

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Pore-Scale Experiment on Blocking Characteristics and EOR Mechanisms of Nitrogen Foam for Heavy Oil: A 2D Visualized Study Zhengbin Wu*1, Huiqing Liu1, Zhanxi Pang1, Chuan Wu2, and Min Gao1 (1. Ministry of Education Key Laboratory of Petroleum Engineering in China University of Petroleum, Beijing 102249, PR China; 2. Sinopec Petroleum Exploration and Production Research Institute，Beijing 100083，PR China)

Abstract：How to enhance heavy oil recovery to meet the oil consumption is a popular issue around the world and it has attracted widespread attention. A two-dimensional visualized model was adopted to study the pore-scale mechanisms and development effects of foam for enhancing oil recovery in steam injection processes for heavy oil. Experimental images visually presented that small bubbles gather together to form bigger foams, thus blocking the small pores and throats and leading to fluid diversion in porous media. As a result, the sweep efficiency was improved from 46.18% to 77.93% after foam injection. Foams could effectively improve mobility ratio between oil and water and decreased water cut after foam injection, which was significant for decaying the decline of oil production. As for pore scale level, after foams were injected into the visualized model, the residual oil caused by steam flooding entered into the main streamline under the disturbance of foams and was carried out by the following displacement fluid. The heavy oil was emulsified into O/W emulsions that had lower viscosity under the action of foams, hence more trapped oil was mobilized and displaced. As a result, the micro oil displacement efficiency increased from 72.76% to 84.01%. In order to provide a reference for the choice of foam injection, experiments that investigated development effects of cold foam and hot foam were also conducted. Compared with the incremental of oil recovery caused by cold foam, that induced by hot foam was 41.51% higher, demonstrating that the co-injection of steam and foam was more advantageous to heavy oil production. Keywords: steam injection; foam flooding; pore scale; heavy oil; enhanced oil recovery

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1. INTRODUCTION Steam injection, including steam huff-n-puff and steam flooding, is one of the most commercially successful technologies for enhancing heavy oil recovery around the world.1-6 In general, the mechanisms of steam injection for enhancing heavy oil recovery include heating viscosity reduction, steam distillation, thermal expansion effect, emulsification effect, etc. Whereas, steam channeling, fingering and override resulting from the differences of viscosity and density between oil and water and reservoir heterogeneity often happen in steam injection projects. Consequently, the injected steam always enters into high-permeable areas and gets around the remaining oil and residual oil, which restricts heavy oil recovery to a great extent. In order to alleviate disadvantageous influences of steam injection for heavy oil development, many scholars have carried out laboratory experiments and field tests on the development effects of adding non-condensable gas or chemical agents to pure steam for enhancing heavy oil recovery.7-9 As a kind of non-condensable gas that is not corrosive, N2 is still gaseous under reservoir condition, and has good permeability and expansibility. Therefore, N2 is helpful for increasing heating radius and sweep area during the steam injection process. N2 is slightly soluble in crude oil and generates fluid that is similar to emulsion, thus decreasing oil viscosity. The mechanisms of adding N2 to steam for the development of heavy oil mainly lie in: a) N2 increases steam sweep volume and supplement reservoir energy. b) The good expansibility of N2 increases the elastic energy during the oil displacement process. On the other hand, the expansion effect disperses crude oil and alters oil flow pattern, thus increasing oil flow ability and accelerating oil flowback. c) N2 plays a good role in heat insulation and enhances heat utilization of steam. d) N2 has lower flow resistance in porous media and preferentially occupies pores, decreasing residual oil saturation and increasing oil displacement efficiency.10-12 Foam has been demonstrated as an effective profile control agent and widely used for the conformance control

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in steam injection processes. In general, foam is created by the co-injection of gas and surfactant solution. Bond and Holbrook firstly introduced nitrogen foam as an agent for enhancing oil recovery to oil development field. Since then, lots of researches have focused on foam transporting and blocking mechanisms in porous media and its application in steam injection.13-16 Furthermore, the micro mechanisms of foam blocking and mobility control have also attracted attention from researchers.17-21 Foam has good profile control ability in heterogeneity formation and can improve sweep efficiency by blocking big pores and throats and diverting fluid to areas with lower permeability. In addition, foam flows in porous media and contacts with residual oil clung to particles. With the constant disturbance of foam, the residual oil is stripped and carried out by the following fluid. As a result, the microscopic displacement efficiency is increased. Laboratory studies indicated that foams could reduce steam mobility by up to 40%. A successful field test of improved steamdrive with nitrogen foam was conducted at the Mideway-Sunset Field in the San Joaquin Vally, California. N2 and surfactant were injected at different rates. The test showed that foam generated by the co-injection of N2/surfactant effectively diverted steam toward the unswept regions of the test pattern.22-23 The two-dimensional (2D) visualized experiment is an important method to study the mechanisms of EOR techniques for improved heavy oil recovery. Argüelles-Vivas et al.24 observed the lateral spreading of the steam chamber during steam-assisted gravity drainage (SAGD) for heavy-oil recovery. They investigated the dynamics of SAGD and the formation of residual oil during the process at the pore level. Conn et al.25 and Mohammadi et al.26-27 recorded the variation of sweep area and studied the effect of reservoir heterogeneity on oil recovery with a two-dimensional micromodel. Conn pointed out that compared with water flooding, gas flooding, surfactant flooding, and water/gas co-injection, foam improved the total oil displacement and sweep efficiency under the same injection conditions. Lu et al.28 made a 2D visualized model and used it to study the displacement mechanisms by injecting viscosity reducer and non-condensable gas to assist steam injection for heavy oil. In this paper, a series of visualized experiments are performed to investigate the EOR mechanisms of foam 3


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flooding in heavy oil reservoirs. During the displacement processes, small-scale visualization in a two-dimensional and transparent porous medium is presented to illustrate the generation of residual oil caused by steam flooding and how pore-scale mobility control induces flow division and thus decreases residual oil saturation and yields a larger-scale recovery percentage. What’s more, images that intuitively reveal the variation of sweep areas prior and posterior foam flooding are displayed, as well as water cut and pressure drop (∆p) between the inlet and outlet. In addition, of the performances of cold foam and hot foam (foam injection accompanied by steam injection) for oil recovery improvement are also compared to identify the appropriate scheme for enhanced oil recovery.

2. EXPERIMENT 2.1. Experimental Materials and Setup 2.1.1. Experimental Materials During the experiments, brine with 3712ppm of NaHCO3 was pre-prepared as the formation water. The crude oil used in this study was from Jinglou Oilfield in Henan, China with a viscosity of 3170mPa•s and a density of 0.97g/cm3 at 30℃. The viscosity-temperature relationship of the crude oil was shown in Figure 1. Nitrogen with high-purity was used for the co-injection with foaming agent solution to generate foams. To successfully perform the experiment, a series of surfactants were tested to identify one that had the best stability at both room temperature and high temperatures.

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100000 10000

Viscosity/ mPa·s

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1000 100 10 1 0

50

100

150

200

250

300

Temperature/ ℃ Figure 1. Viscosity-temperature relationship curve of crude oil

2.1.2. Experimental Setup The schematic of the experiments was illustrated in Figure 2 and the 2D model was the most important part. The 2D model was composed of two 25cm-long and 25cm-wide quartz-glass plates, in the space between which was filled with glass beads with diameter of 0.84mm to form a transparent, unconsolidated porous media. The size of the visual area was 20cm×20cm as shown in Figure 3 and Figure 4. Around the glass was sealed with a kind of glass cement that was resistant to 350℃ and 3MPa. The 2D model could work normally under 3MPa and 300℃. A digital camera was mounted above the visualization model to get the real-time displacement characteristics in the model both macroscopically and microscopically. Meanwhile, a plane light was mounted under the 2D model in order to make the experimental processes clearer. During the experiments, high-temperature steam (from the steam generator), crude oil (from the oil tank), water (from the formation water tank), foaming agent solution (from the surfactant solution tank) and nitrogen (from the nitrogen cylinder) could be simultaneously injected into the model. The steam injection pipeline was covered with electric heater unit to keep the steam temperature. The nitrogen injection rate 5


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was adjusted by a gas mass flow controller. The liquid injection rate was controlled by a micro-gear pump with constant rate and high pressure. Nitrogen and surfactant solution simultaneously injected through the foam generator filled with glass beads of 0.2mm to create foam into the 2D model. The inlet and outlet of the 2D model were respectively mounted a pressure gauge to record the pressure drop. The products of the experiments were collected by a cylinder at the outlet of the 2D model. Oil tank, water tank, surfactant solution tank, six-way valve, foam generator and 2D model were all mounted in a constant-temperature oven that could study the influence of temperature on the experiments.

Figure 2. Schematic of the displacement experiments

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a

b

c

Figure 3. Experimental setup. (a) Quartz glass. (b) Side elevation diagram of the visualized model. (c) Top view diagram of the visualized model.

(a) Side elevation diagram

(c) Top view diagram (b) Porous media area Figure 4. Structure diagram of the visualization model 1-nut; 2-model holder; 3- silicone pad; 4- quartz glass; 5- porous media; 6- glass beads; 7-draining trench; 8-tape; 9-injection pot; 10-production pot

2.2. Experimental Methods and Procedures 2.2.1. Thermal Stability of Bulk-foam and Foaming Agent Selection Considering steam temperature during the displacement process, it was necessary to evaluate the thermal stability of foaming agents against high temperature. Two parameters of foaming volume (Vm) and half-time were employed to evaluate foamability and stability of foaming agents, respectively. The former was defined as the maximum volume of foam for a certain foaming agent solution shearing for several minutes at a certain temperature, and the latter was defined as the time that foam takes to decrease to half of its initial volume at the same temperature. In this part, three kinds of surfactant solutions, named SDS (sodium dodecyl sulfate), ABS (sodium dodecyl

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benzene sulfonate) and AAS (alkylaryl sulfonate), with the mass concentration of 0.5% were tested of foaming volume and half-time at 20℃, 50℃, 100℃, 150℃, 200℃, 250℃, respectively. The experimental apparatus included automatic mixer, visual reaction oven, glass rod, 1000-mL breaker, and stopwatch. During the experiment, 100-mL surfactant solution was injected into the reaction oven which was then kept at the experimental temperatures for three hours. Then, the surfactant solution was stirred by the automatic mixer at a rotating speed of 1400r/min for five minutes. Afterwards, the foaming volume and half-time were measured at the same temperature. The reaction oven was set at another temperature to test the corresponding foaming volume and half-time. Consequently, the foaming volume and half-time of the other two surfactants at different experimental temperatures were obtained with the previous method.

2.2.2. Visualization of Oil Displacement by Steam/Nitrogen Foam After the experimental setup was prepared as Figure 2, the 2D model was saturated with formation water. During this process, several parameters of the model such as porosity and permeability were tested until the pressures at both the inlet and outlet of the model became stable. The porosity was measured based on the volume difference between the total injected water and produced water. Afterwards, the model was displaced by crude oil at 50℃ to form the connate-water saturation condition. Leave the model stand for several hours to make the fluid inside uniformly distributed. In order to comprehensively evaluate the effects of foam flooding in steam injection projects, two groups of experiments were conducted. The first was that steam flooding was converted to nitrogen foam flooding when the water cut was 98% at the outlet until the displacement process ended. The other was that steam flooding accompanied by nitrogen foam when the water cut was 98% at the outlet, namely steam flooding was converted into steam-foam injection process until the experiment ended. In the first experiment, the foam injected to the model was unheated, so it was called cold foam, while that in the second experiment was hot foam. The physical parameters of the two models were listed in Table 1. The injection rates of formation water, crude oil and steam were all 8


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0.2mL/min. Steam temperature was 200℃.

Table 1. Physical Parameters of 2D Model Scheme 1

Scheme 2

Porosity (%)

0.375

0.356

Permeability (D)

4.32

4.25

Oil volume (mL)

23.88

21.35

3. RESULTS AND DISCUSSIONS 3.1. Static Performance of Foaming Agents The foaming volume and half-time of the three foaming agents at elevate temperatures were presented in Table 2. The results showed that foaming volume and half-time of SDS were both the maximum at different temperatures, indicating that SDS had the best foamability and thermal stability. Therefore, SDS was selected as the objective foaming agent in the following experiments. The viscosity and density of the foaming agent solution was 0.85mPa·s and 1g/cm3 at 20℃, respectively. Table 2. Foaming volume and half-time of foaming agents at different temperatures Vm(mL)/T1/2(min) Foaming agents 20℃

50℃

100℃

150℃

200℃

250℃

SDS

600/230

550/183

500/155

490/148

450/118

420/103

ABS

550/176

500/160

480/150

450/112

420/78

410/55

AAS

400/153

350/137

310/120

290/100

250/47

230/36

3.2. Steam Flooding Process The sweep efficiency, oil recovery and pressure drop were functions of time t and represented in dimensionless form as the injected pore volume PV=tQ/Vp. Q was the fluid injection rate and Vp was the pore volume of the porous media. Figure 5 showed the dynamic variation of macroscopic sweep in the oil layer by steam injection. The black part 9


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in this result was crude oil and small white spots were glass beads filled in the 2D model. The bright yellow that presented irregular shape of the branches was steam sweep area. Typical viscosity fingering phenomena occurred between the injector and producer and the following steam mainly flowed along the existing channels that had a weaker flow resistance. As steam injected, the sweep areas gradually expanded, but the viscosity fingering was more obvious, as shown in Figure 5b. Once the steam front arrived at the model outlet, namely steam breakthrough happened, the expansion of steam to both sides of the mainstream channel was further restricted, as shown in Figure 5c. In the sweep areas, crude oil mobility was improved and was easily carried out from the glass beads by high-temperature steam (200℃) because of oil viscosity sensitivity to temperature. However, heat loss of steam front and large viscosity of crude oil made the sweep efficiency was quite limited. Results showed that the sweep efficiency of steam flooding was 46.18%.

a

b

c

Injector Producer Figure 5. Macroscopic images of steam flooding. (a) 0.21PV. (b) 0.45PV. (c) 1.02PV

Figure 6 presented the microscopic images of steam flowing in porous media and the generation of flowing channels. Fluid (steam, hot water, condensate, crude oil, etc.) firstly entered the main channel under the action of pressure difference, as shown in Figure 6a. But due to human factors and the sorted behavior of glass beads, it was inevitable that the glass beads did not have a totally uniform diameter and they were not so uniformly distributed in the space between the two glass plates during the manufacture of the visualized model. Therefore, the visualized 10


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model was somewhat heterogeneous at the micro level. As a result, with the constant injection of steam, more steam channels were formed (Figure 6b) due to micro heterogeneity.

a

b

Figure 6. Microscopic images of steam flooding. (a) Fluid flows along the mainstream channel. (b) Branches of the mainstream channel.

As was mentioned above, large quantity of residual oil was left behind after steam flooding. In general, steam bypass made for the generation of residual oil at the micro level. And further, reservoir wettability and micro-heterogeneity, as well as considerable oil and water interfacial tension influenced the flow of steam at the pore-scale level. The space between the two quart glasses was only filled with two-layer glass beads and pores of different sizes were formed between glass beads. Consequently, the injected high-temperature steam made the steam channeling obvious at the micro level, as shown in Figure 7. Figure 7 presented two types of residual oil generated in the steam flooding process. Steam bypassed areas with higher flow resistance and left plenty of residual oil still clung to the glass beads and adhesive tape on both sides of the flow channel (Figure 7a). With the continuous scouring of steam, residual oil saturation in the sweep areas gradually decreased, but there still gathered some oil in the shape of oil-ring (Figure 7b).

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Figure 7. Microscopic images of residual oil caused by steam flooding. (a) Residual oil in unsweep areas. (b) Residual oil in sweep areas.

3.3. Foam Flooding Process Foam has been demonstrated as an effective blocking agent used in petroleum industry. In this article, foam flooding was carried out as an alternative for steam flooding. Figure 8 presents the macroscopic sweep of the oil layer during foam injection process. As clearly reflected in the images, the sweep areas constantly expanded with the injection of foams. Foam is a kind of selective fluids that preferentially flows into high-permeable areas in porous media and blocks the bigger pores. Therefore, the following fluid is diverted into the areas with lower permeability, thus improving the sweep efficiency. The ultimate sweep efficiency was 77.93%, 31.75% higher than that of pure steam flooding.

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a

b Injector

c Producer

Figure 8. Macroscopic images of foam flooding. (a) ~ (b) Foam flooding process—1.03 PV and 3.85 PV. (c) Foam flooding ended (4.95PV)

Figure 9 presented the micro mechanisms of foams on enhancing oil recovery. As a kind of non-Newtonian fluid, foam firstly entered bigger pores in porous media that had a lower flow resistance. During the foam injection process, continuous small bubbles constantly flowed to pores and gathered at the throat under the action of Jamin effect. Thereafter, dispersive small bubbles coalesced to bigger bubbles and blocked the throat due to the greater apparent viscosity (as shown in Figure 9a and Figure 9b), diverting the following foams and other fluid to the smaller pores nearby, thus improving the sweep efficiency. In addition, foam agent itself as a kind of surfactants, together with natural emulsifying agents in crude oil such as naphthenic acid and soap made the crude oil form dispersive oil-in-water (O/W) emulsions with lower viscosity and better mobility (as shown in Figure 9c, Figure 9d and Figure 10). Meanwhile, foams decreased interfacial tension (IFT) between oil and water and further increased oil fluidity. As a result, under the constant disturbance of the fluid during foam injection process, residual oil in the sweep areas was further carried out and the residual oil saturation of the entire oil-bearing areas was also declined.

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c

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d

Figure 9. Microscopic images of foams in porous media. (a) ~ (b) Foams block bigger pores in porous media. (c) ~ (d) Crude oil was divided into dispersive O/W emulsions

Figure 10. Initial crude oil and emulsions in the effluent

Figure 11 presented dynamic displacement characteristics during the whole injection process. The crude oil in the 2D model was initially displaced by 1.74 PV steam. During steam injection process, ∆p increased rapidly until steam breakthrough occurred (0.49PV) and then decreased. Meanwhile, the increase of oil recovery to 33.6% indicated that the injected steam still gradually heated the crude oil and carried the mobilized fluid out of the model. Afterwards, about 3.7 PV of foam flooding was conducted until no oil was produced at the outlet, which contributed another 31.9% of OOIP (original oil in place). The ultimate oil recovery was 65.5%. Generally, the mechanisms of foam flooding were mainly reflected in two important aspects: profiles control in injector and water cut reduction in 14


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producer. The former was clearly exhibited in Figure 8 that with the injection of foam, sweep areas extended outwards along both sides of the main channel and residual oil saturation near the injector was quite low. The latter could be obtained in Figure 11 that after foam injection, water cut declined to 76.3%, indicating that more residual oil was displaced, which was beneficial for the extension of production.

Figure 11. Oil recovery and water cut as functions of PV

In the previous flooding process, foam flooding was performed following steam injection. So it could be considered that the injected foams were cold foams. On one hand, fluid from outside with lower temperature could decrease the model temperature by heat exchange, which was disadvantageous for crude oil. On the other hand, relatively lower temperature might influence surfactant activity. Based on the analysis above, another injection scheme was carried out by diverting continuous injection into slug injection. The development effects of cold foams and hot foams (co-injection of steam and foam) were also compared. The dynamic displacement characteristics were presented in Figure 12. The entire displacement process could be divided into four stages. Firstly, the crude oil was displaced by 2.01 PV steam and followed by 1.0 PV foam injection in the second stage. As the foam injection process ended, the oil recovery was 52.75%, 17.25% higher than that at the end of steam injection in the first stage with a value of 35.5%. Compared with steam injection in the third stage, oil recovery was 18.05% higher in the

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fourth stage of steam-foam (hot foam) injection process. The variation of curves during the first cycle injection of steam and foams was similar to that in Figure 11. Water cut decreased during foam injection and increased in the following steam injection process (from 2.01 PV to 3.01 PV). Pressure drop and the increment of oil recovery in the fourth stage of steam-foam process were both higher than those in the second stage of foam flooding, indicating that on one hand, flow division caused by foam blocking happened in the porous media; on the other hand, the synergistic effect of steam and foam was helpful to promote oil recovery. Namely, hot foam was more beneficial than cold foam under a certain condition. The ultimate oil recovery was approximately 77%, 11.5% higher than that in the cold foam flooding process.

Figure 12. Oil recovery and water cut as functions of PV during slug injection process

4. CONCLUSIONS A 2D visualized model is used in this paper to investigate the pore-scale displacement mechanisms of nitrogen foam flooding for heavy oil. Based on the experimental results, several conclusions are obtained as follows: (1) The injection of foam has a positive effect on conformance control. Foam preferentially enters high-permeable areas and blocks the throats due to Jamin effect, thus diverting fluid to areas with lower permeability to improve sweep efficiency. 16


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(2) The constant disturbance of foam flowing and migration in porous media makes residual oil stripped from the glass beads. Foaming agent as a kind of surfactant facilitate the generation of O/W emulsions that has a lower viscosity and better mobility. The two actions together promote the oil displacement efficiency. (3) The ultimate oil recovery of cold foam flooding is 65.5%, 31.9% higher than that of pure steam flooding. While after hot foam injection, oil recovery is improved by another 18.05% of OOIP. The synergistic effect of steam and foam is beneficial to promote oil recovery

AUTHOR INFORMATION Corresponding Author *E-mail:[email protected].

Notes The authors declare no competing financial interest.

ACKOWLEDGEMENTS The authors would like to acknowledge the financial support of the National Natural Science Foundation of China (No. 51274212 and No. 51474226).

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(4) Jabbour C.; Quintard M.; Bertin H.; et al. Oil recovery by steam injection: three-phase flow effects. J. Petrol. Sci. Eng. 1996, 16(1), 109-130. (5) Patzek, T. W. Field applications of steam foam for mobility improvement and profile control. SPE Reservoir Eng. 1996, 11(2), 79–86. (6) Fatemi, S. M.; Jamaloei, B. Y. Preliminary considerations on the application of toe-to-heel steam flooding (THSF): Injection well–producer well configurations. Chem. Eng. Res. Des. 2011, 89(11): 2365-2379. (7) Ji, Y. J.; Cheng, L. S.; Liu, Q. C.; et al. Digital experiment on steam and in-condensable gas push for extra heavy oil reservoir. Acta Petrolei Sinica 2010, 31(4): 602-606. (8) Sun, J. F. Study and application on HDNS technology to develop shallow and thin super heavy oil reservoir. Petrol. Geol. Rec. Eff. 2012, 19(2):47-49. (9) Zhang, Y. F.; Wu X. D.; Zhang Y. M.; et al. Two-phase closed thermosyphon (TPCT) decreases heat loss of liquid within heavy oil wellbores. Petrol. Explor. Dev. 2011, 38(2): 228-232. (10) Ouyang, B.; Chen S. B.; Liu D. J. Application of nitrogen gas insulating heat and aiding flow technology in Liaohe heavy oilfield development. Oil Drill. Prod. Technol. 2003, 25(S1):1-3. (11) Wang, D. Y.; Chen, D. M.; Ran, J.; et al. Using aid to drain technology by nitrogen heat-proof to improve oil producing efficiency by viscous crude steam soak. Drill. . Prod. Technol. 2001, 24(3):25-28. (12) Wang, X. Z.; Wang, J. Z.; Qiao, M. Q. Horizontal well, nitrogen and viscosity reducer assisted steam huff and puff technology: Taking super heavy oil in shallow and thin beds, Chunfeng Oilfield, Junggar Basin, NW China, as an example. Petrol. Explor. Dev. 2013, 40(1): 97-102. (13) Mast, R. F. Microscopic behavior of foam in porous media. Proceedings of the Fall Meeting of the Society of Petroleum Engineers of AIME, San Antonio, Texas, October 8-11, 1972. (14) Hirasaki, G. J.; Lawson, J. B. Mechanisms of foam flow in porous media: apparent viscosity in smooth 18


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Energy & Fuels

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Pore-Scale Experiment on Blocking Characteristics and EOR

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