Article pubs.acs.org/EF
Utilization of Surfactant-Stabilized Foam for Enhanced Oil Recovery by Adding Nanoparticles Qian Sun,† Zhaomin Li,*,† Songyan Li,† Lei Jiang,‡ Jiqian Wang,‡ and Peng Wang† †
College of Petroleum Engineering, China University of Petroleum, Qingdao 266580, Shandong, China Centre for Bioengineering & Biotechnology, China University of Petroleum, Qingdao 266580, Shandong, China
‡
ABSTRACT: Nitrogen foam flooding is a promising technique for enhanced oil recovery, but instability of the foam limits its application. In this article, partially hydrophobic modified SiO2 nanoparticles with an anionic surfactant, sodium dodecyl sulfate (SDS), were used together to increase foam stability. Micromodel flooding and sandpack flooding were adopted to assess the stability and effect on enhanced oil recovery of the SiO2 stabilized foam (SiO2/SDS foam). The experimental data showed that the foam stability was decreased with an increase in temperature, while the foam volume was increased first and then decreased. SiO2/SDS foam showed better temperature tolerance than the SDS foam (foam stabilized by SDS) due to the adsorption of nanoparticles on the surface of the bubble. Almost all of the bubbles maintained spherical or ellipsoidal shape with prolonged time due to the enhanced surface dilational viscoelasticity, which was different from that of SDS foam. According to the micromodel flooding results, SiO2/SDS foam displaced more oil than brine flooding, SDS solution flooding, or SDS foam flooding. As the foam stability was enhanced, gas mobility and channeling were controlled effectively. In addition, more oil on the pore wall and in the dead-end pores was displaced out because of the higher viscoelasticity of the SiO2/SDS foam. The sandpack flooding results showed that the increase of differential pressure and profile control effect was a proportional function of the SiO2 concentration in SiO2/SDS foam. The test with a higher SiO2 concentration resulted in a higher oil recovery when SiO2 concentration was less than 1.5 wt %.
1. INTRODUCTION With the increasing demand and consumption of energy globally, more crude oil needs to be exploited from the existing oilfield. But only about 35% to 50% of the crude oil in reservoirs has been recovered through conventional oil recovery methods (including primary and secondary recovery).1,2 Several tertiary or enhanced oil recovery (EOR) techniques have already been adopted to exploit the residue oil in reservoirs.3−11 As estimated, 377 billion barrels of “stranded” oil (in the U.S.) in place would be the target of EOR applications at present.12 Complex fluids (e.g., steam, gas, surfactant, and foam), instead of water only are injected into reservoir in EOR techniques. Oil recovery is enhanced either by increasing sweep volumes or by improving oil displacement efficiency.13 Foam flooding is one of the promising EOR techniques of recovering the residue oil recovery after waterflooding. Both experimental results and field applications have proved the tremendous success of foam flooding.14,15 Foam flooding has been developed as a kind of mature oil displacement technique since 1950s. Foam is a two-phase system in which gas bubbles are enclosed by a thin liquid film, while gas flow is easily controlled, and the volumetric sweep efficiency is improved.16 Foam’s apparent viscosity is several orders of magnitude greater than that of either gas or liquid. The high apparent viscosity of foam controls viscous fingering and increases the oil recovery. In heterogeneous porous media, foam could be generated in higher permeable layers first and then diverted into lower permeable layers.17−19 Obviously, foam stability is important for field application, though the bubble is unstable both thermodynamically and kinetically. There are three interdependent modes of foam instability: (1) © 2014 American Chemical Society
foam drainage, by which liquid is segregated from the bubble surface under the action of gravity and retarded by capillary forces and shear stress imparted at the bubble surface;20 (2) the rupture of liquid films;21 and (3) interbubble gas diffusion caused by nonuniform bubble size distributions. Surfactant loss caused by its adsorption on rock has been found to be another factor of foam instability in reservoir. Enhancement of foam stability, especially in reservoirs, is a key factor to increase sweep efficiency. As has been reported, nanoparticles, such as silica, can improve the stability of foam through two mechanisms. Nanoparticles absorb at the air− water interface, and the interwoven distribution can increase the flow resistance of water on liquid film and slow down liquid drainage.23 Stratification of nonadsorbing nanoparticles in the intervening thin film separating the dispersed phase, forming a three-dimensional network structure, improves the stability of foam against shrinkage and coalescence.24 Binks and Horozov25 proposed that the adhesion energy of nanoparticles at the air− liquid interface was several hundreds or thousands times larger than that of a typical surfactant molecule. Once the nanoparticles attach to the air−liquid interface, such an attachment is normally irreversible. Nanoparticle-stabilized foams have recently attracted attention for their potential applications in food industry,26 as well as the production of metallic foam and froth flotation.27 Nanoparticles could stabilize foam because they not only retard drainage but also provide a steric barrier to film rupture, i.e., a barrier that Received: December 16, 2013 Revised: March 12, 2014 Published: March 12, 2014 2384
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Shengli Oilfield. The size of the micromodel was 8 cm × 8 cm × 6 mm, and the depth and width of the channel were about 40 and 50 μm−80 μm, respectively. The schematic of the microscopic experimental apparatus and the micromodel saturated with oil is shown in Figure 1.
Dickson26 referred to as “colloidal armour”. However, the optimum conditions for particle stabilization are still unclear. Kaptay28 showed theoretically that the contact angle of the nanoparticle surface to stabilize the foam film might be between 20° and 90°, but Dippenaar29 demonstrated that foam stability was dependent upon the shape of the particles. However, Hunter et al.27 proposed that the optimum contact angle was between 70° and 80°. Generally particle-stabilized foams benefit from surfactant adsorption as well as particle attachment at the gas−liquid interface. Zhang et al.30 studied the stability of aqueous foams prepared by mixtures of Laponite particle and C12E4 (tetraethyleneglycol monododecyl ether). The foams become more stable with increasing C12E4 concentration. Recently, Espinoza et al.31 suggested the application of nanoparticle-stabilized foams in reservoir displacement operations, but they did not prove the utility of such kinds of foam in sandpack or coreflooding. After investigating the application of nanoparticle-stabilized CO2 foam for oil recovery, Mo et al.32 found that it could improve oil recovery after waterflooding in both low and high permeability cores. Yu et al.33 studied the adsorption and transportation behavior of nanoparticles in sandstone, limestone, and dolomite. The results show that the equilibrium adsorption of nanoparticles on the three porous media is very low. Also, the coreflood tests indicate that nanoparticles do not change the core permeability. Aminzadeh et al.34 found that the nanoparticle-stabilized foams can increase sweep efficiency and reduce the gravity override compared to displacements without nanoparticles by using CT scanning techniques. Despite the significant work on particle-stabilized foams above, there is little investigation on the properties and applications of particle-stabilized foam in porous media for EOR. In this article, the stability of SiO2/SDS foam and the displacement behavior for enhanced oil recovery has been studied by micromodel tests. The concentration of SiO2 on the pressure differential, diversion ratio, and oil recovery were analyzed by conducting sandpack flooding experiments. The effective oil displacement by SiO2/SDS foam was also examined, analyzed, and discussed.
Figure 1. Schematic of the microscopic oil displacement experimental apparatus. 2.2.2. Sandpack Experiments. The schematic of the coreflooding apparatus used in the sandpack experiments is shown in Figure 2. The
2. EXPERIMENTAL SECTION Figure 2. Schematic of the sandpack flooding apparatus.
2.1. Materials. Sodium dodecyl sulfate (SDS) and sodium chloride (NaCl) were supplied by Sigma (USA), both with a purity of >99.0 wt %. The critical micelle concentration (CMC) of SDS in water at 25 °C was 0.23 wt %.35 SiO2 nanoparticles (HDK, H18) were supplied by Germany Wacker Chemical Co., Ltd. The nitrogen used in this study was supplied by Tianyuan Inc. (China), with a purity of 99.9 wt %. The crude oil was provided by Shengli Oilfield, China, with a viscosity of 413 mPa·s and a density of 0.913 g/cm3 at 60 °C. All of the solutions were prepared with NaCl at a concentration of 0.5 wt % to simulate the formation water. In this study, the nanoparticles (purity >99.8 wt %) are nearly spherical with an average diameter of approximately 14 nm. The surface of the particles was modified by the manufacturer to increase its hydrophobicity by coating with dimethyl siloxane,23 while the density of silanol groups was about 0.5 per nm2. The surface area of the SiO2 nanoparticles was approximately 200 m2/g. The weight loss was less than 0.6 wt % after drying at 105 °C for 2 h. All glassware were cleaned with alcohol (Sinopharm Chemical Reagent Co., Ltd., China). In order to simulate the real formation conditions, experiments were conducted at 60 °C unless specified otherwise. 2.2. Apparatus. 2.2.1. Micromodel Test. The glass-etched micromodel used in this experiment was made by etching a twodimensional network of pores and throats by a photochemical method. The network was patterned from the pore structure of a core from
inner diameter and length of the sandpack tube were 2.5 and 30.0 cm, respectively. There were two sandpack models in Figure 2 for different experiments. Silica sands with different diameters were used to pack the model in order to obtain cores with different permeabilities. Table 1 lists some key parameters of sandpack models. A foam generator, which is a porous medium sealed in the flow channel, was used upstream of the sandpack. The foam generator is full of silica sand, with diameters of about 70 μm−100 μm. Then the foam itself was generated by passing the gas and surfactant-containing liquid simultaneously through the foam generator. A back-pressure regulator (BPR) with an accuracy less than 0.001 MPa was used to control the pressure right downstream of the sandpack. The back-pressure for all of the sandpack experiments during displacement was 2.0 MPa. The temperature of the experiments was controlled by conducting the sandpacks in a fixed-temperature chamber. Details of the coreflooding apparatus and other apparatus used in the experiments can be found elsewhere.36 2.3. Experimental Procedures. 2.3.1. Foaming SiO2/SDS Dispersions Preparation. SiO2/SDS dispersion was prepared by dispersing a certain mass of SiO2 nanoparticles and SDS (0.5 wt %) into brine (0.5 wt % NaCl). The prepared dispersion was stirred for 12 2385
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2.3.5. Micromodel Test. Micromodel flooding experiments were conducted to identify the displacement mechanisms for improving oil recovery after waterflooding. The first experiment was waterflooding followed by SDS solution flooding. The steps are briefly described as follows: (1) the micromodel was evacuated; (2) brine (0.5 wt % NaCl) was injected to saturate the micromodel; (3) crude oil was injected until no more water was produced; (4) the oil was displaced by water for 2.0 PV (pore volume); and (5) the SDS solution (0.5 wt %) was injected for 0.5 PV followed by 6.5 PV of water. The second experiment was waterflooding followed by SDS foam flooding. Like the first experiment, the oil was displaced by water for 2.0 PV in the micromodel. Then, the SDS foam of 0.5 PV was injected into the model followed by 6.5 PV of water. The third experiment was waterflooding followed by SiO2/SDS foam flooding. The procedure was the same as that of the second experiment except that the foam was changed to SiO2/SDS foam. During the experiments, the whole injection rate was 0.005 mL/ min, and w the back-pressure was 2 MPa. For foam flooding, the foam formula solution (0.0025 mL/min) and N2 (0.0025 mL/min) were injected into the foam generator simultaneously, then a very uniform foam (see Figure 2) was injected into the micromodel. In order to make uniform foam and guarantee its efficiency in foam flooding, the injecting rate of the liquid and gas should be the same. The injecting rate can directly affect bubble generation and foam stability. More detailed explanations are described elsewhere.38 The concentrations of SDS and SiO2 nanoparticles were 0.5 wt % and 1.0 wt %, respectively. The experiments were recorded during the different stages of injection by a digital microscopic imaging system. 2.3.6. Sandpack Experiments. 2.3.6.1. Single-Core Sandpack Experiment. The sandpack flooding tests were conducted horizontally. SDS solutions with different concentration of SiO2 (0.0 wt %, 0.1 wt %, 0.5 wt %, 1.0 wt %, 1.5 wt %, and 2.0 wt %,) were injected into six single-tube sandpack models with nearly the same permeability (#1− #6), respectively. For each sandpack, it was saturated with water first, and then its pore volume and permeability were measured. Subsequently, oil was injected into the sandpack until no more water was displaced, and the initial oil saturation was calculated. Second, 2.0 PV of water was then injected into the sandpack until the oil production became negligible (oil cut less than 1.0 wt %). After the initial waterflooding, a fixed slug size of 0.6 PV foam was followed by the extended waterflooding until the oil production became negligible again. During the flooding test, the volumes of produced oil and differential pressure were measured as a function of time. Unless otherwise noted, the injecting rate of water was 1.0 mL/min, and the rates of foam formula solution and gas were 0.5 mL/min and 0.5 mL/ min, respectively. 2.3.6.2. Double-Core Sandpack Experiment. Six heterogeneous double-tube sandpack models (#7−#12) were used in this study. The two sandpacks with permeabilities varying by a factor of approximately 5.0 were arranged in parallel (see Figure 2). Each of the sandpack models began with water saturation, and then pore volume and permeability were determined. Then the cores were saturated with crude oil and the initial oil saturation recorded. Water was injected into the double-tube sandpack model for 2.0 PV. Then, 1.0 PV of foam was injected into the model followed by waterflooding. The diversion flow volumes for the high and low permeability sandpack (QH and QL) and the produced oil volumes were measured in a certain time interval. The diversion ratio is defined as the ratio of diversion flow volume (QH or QL) to total flow volume (QH + QL). Unless otherwise noted, the injecting rate of water was 2.0 mL/min, and the rates of foam formula solution and gas were 1.0 mL/min and 1.0 mL/min, respectively.
Table 1. Parameters of Sandpack Models model no.
permeability (μm2)
porosity (%)
#1 #2 #3 #4 #5 #6 #7a
0.85 0.84 0.84 0.82 0.85 0.84 4.20 0.82 4.06 0.81 4.40 0.84 4.25 0.87 4.19 0.86 4.36 0.88
36.5 36.3 36.6 37.7 35.8 36.6 38.3 36.1 39.8 37.3 40.2 37.8 38.6 36.7 40.7 37.4 41.2 36.2
#8a #9a #10a #11a #12a
permeability ratiob
5.12 5.04 5.21 4.91 4.87 4.96
initial oil saturation (%) 86.4 87.5 86.7 85.9 88.7 87.6 86.7 87.2 87.8 88.1 88.2 86.2 87.5 87.7 89.2 88.9 87.9 88.3
a Numbers 7−12 are double-core sandpack models. bThe permeability ratio is defined as the permeability of the high-permeability sandpack divided by the permeability of the low-permeability sandpack.
h followed by 2 h of sonication. The dispersion was slightly hazy. The particles in the dispersion were in a dispersed state, but particles might aggregate partially. Then, the dispersion was sealed for use. 2.3.2. Foam Stabilized by SiO2/SDS Dispersion. Foam was prepared by using the Warning Blender methods. A 100 mL dispersion was poured into a blender (GJ-3S, Qingdao Senxin Machinery Equipment Co., Ltd., China) and stirred for 3 min at 8000 rpm. When the blender was stopped, the foam was transferred into a 500 mL cylinder to record the foam volume immediately. The time required for half of the original amount of liquid to drain from the foam (half-life) was also recorded. Since foam stability is crucially dependent upon environmental humidity, the top of the cylinder was sealed. All of the stability experiments were performed in an oven to control the temperature. 2.3.3. Measurement of Interfacial Tension (IFT). The IFTs between oil and the different solutions were measured using a spinning drop interface tensiometer (TX500C, Bowing Industry Co., USA) at 60 °C. This instrument is equipped with image acquisition and analysis software, and the IFT can be recorded dynamically. During the experiments, it usually took about 10 to 90 min to reach equilibrium IFT. 2.3.4. Adsorption of SDS. The adsorption tests were conducted by agitating 30 mL of SDS solution with 50 g of sand for 1 h in an incubator maintained at the desired temperature. At the end of the test, 4 mL of the supernatant solution was centrifuged (8500 r/min) for 15 min. The SDS residual concentration of the supernatant was measured using a methylene blue spectrophotometric method. A certain amount of supernatant was diluted in proportion and mixed with methylene blue solution (0.25 g/L), then the solution was extracted with chloroform to remove excessive methylene blue. Finally, the aqueous solution was analyzed using an ultraviolet spectrophotometer to determine the absorbance value, and the SDS concentration was calculated according to the standard curve. The method is described in detail elsewhere.37 Adsorption of SDS on the sand surface was calculated using the following equation:
3. RESULTS AND DISCUSSION 3.1. Determination of Foam Stability. Since high temperature could deteriorate foam stability under the formation condition in oilfields, the half-life of foam at different temperatures was studied. The concentrations of SDS and SiO2 nanoparticles were 0.5 wt % and 1.0 wt %, respectively. As
A = [(ρo − ρx )V ]/m where A is the adsorption capacity (mg·g−1); ρo and ρx are the initial and final concentrations of SDS, respectively (mg·L−1); V is the volume of the SDS solution (L); and m is the mass of the sand (g). 2386
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shown in Figure 3, the foam volume first increased with increasing temperature until the maximum value was reached,
Figure 3. Half-life time and foam volume at different temperatures (a, 0.5 wt % SDS solution; b, 0.5 wt % SDS + 1.0 wt % SiO2 dispersion; c, 0.5 wt % SDS solution; and d, 0.5 wt % SDS + 1.0 wt % SiO2 dispersion). Figure 4. Behaviors of foams at different temperature as a function of time (a, SDS foam at 60 °C; b, SiO2/SDS foam at 60 °C; c, SDS foam at 80 °C; and d, SiO2/SDS foam at 80 °C).
and then the foam volume decreased with temperature. The maximum foam volume of both SDS foam and SiO2/SDS foam occurred at 60 °C. Half-life time of both SDS foam and SiO2/ SDS foam decreased with an increase in temperature. The SiO2/SDS foam volume was about 20%−30% lower than that of SDS foam, while its half-life time had increased significantly. At 20 °C, the half-life time was about 7 times that of SDS foam. When the temperature rose to 80 °C, it was about 35 times that of SDS foam. Compared to SDS foam, the SiO2/SDS foam has higher thermal stability. Although it is confirmed that the SiO2/SDS foam has higher thermal tolerance, there is no direct link established between the stability of foam outside porous media and inside porous media. Given this situation, foam was injected into the micromodel (without oil), and then the inlet and outlet of the model were shut down. Then, a series of photographs were taken every 5 min right after the foam injection. A detailed visualization of these experiments is given in Figure 4, presenting a sequence of images that illustrates the evolution of foam at different temperatures as a function of time. For SDS foam, the bubbles were becoming bigger and had an irregular shape as time went on at the same temperature (see Figures 4a and c). The bubble size grew quickly with time, and big bubbles coalesced with adjacent small bubbles due to the pressure differences caused by the Young−Laplace effect.22 The pressure difference acted as the driving force for gas diffusion from small to large bubbles. Therefore, the volume of big bubbles increased at the cost of the small ones. At the end of the experiments, the gas and liquid were separated (see Figure 4c), and gas channeling formed, which was bad for the displacement efficiency of foam fluid. Compared with Figure 4a and c, it was also shown that both the number of bubbles and the stability of foam decreased with an increase in temperature. For foam prepared from SiO2/SDS dispersion, the bubbles were more uniform than SDS foam. Although the bubble volume became larger and larger with time (see Figure 4b and d), the shape of the bubbles was still either spherical or ellipsoidal. It was mainly because the surface dilational viscoelasticity increased with the SiO2 adsorbed on the bubble surface,39 and the enhanced foam interfacial layer resisted the
deformation. About 8 h later, the gas and liquid were not separated. Although the number of bubbles decreased with temperature increments like SDS foam, its extent of decrease was much lower than that of SDS foam. It means that the temperature increment has less effect on SiO2/SDS foam than on SDS foam. The attached nanoparticles on the bubble surface reduced the surface area available for interbubble gas diffusion, which stabilized foam against Ostwald ripening.40 The nanoparticles were located on the lamella between bubbles, and these particles built up a three-dimensional network structure in continuous phase,24 while the bubbles were trapped; then, the thermal stability of bubbles was significantly improved. 3.2. Micromodel Flooding Experiments. 3.2.1. Waterflooding. During waterflooding, water bypassed the oil on the pore walls (see 1 in Figure 5) because of the adverse mobility ratio between the oil and water phases. Some of the oil was still stranded in the throat because of capillary force (see 2 in Figure 5). During the flooding process, water mainly flowed along the diagonal direction, and the sweep efficiency was very low once water breakthrough occurred. When 9 PV of brine was injected into the oil saturated micromodel, it could be observed in
Figure 5. Local microscopic image (left) and distribution of remaining oil after waterflooding (right) (left, 0.5 PV water injected; right, 9.0 PV water injected). The flow direction is indicated by a red arrow. 2387
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Figure 5 that there existed a lot of oil unswept on both sides of the main diagonal line. After that, only a little oil could be recovered by waterflooding, and oil saturation was still high in the micromodel at the end of the displacement. 3.2.2. Displacement of SDS Solution Flooding. As a surfactant, SDS in the solution could lower the oil/water interfacial tension and form O/W or W/O emulsions (see 1 and 2 in Figure 6). The IFTs for oil/SDS solution and oil/brine
Figure 7. Microscopic images for SDS foam flooding and SiO2/SDS foam flooding at different times (a, 2 PV waterflooding + 0.1 PV SDS foam flooding; b, 2 PV waterflooding + 0.3 PV SDS foam flooding; c, 2 PV waterflooding +0.5 PV SDS foam flooding; d, 2 PV waterflooding + 0.5 PV SDS foam flooding + 1 PV waterflooding; e, 2 PV waterflooding + 0.1 PV SiO2/SDS foam flooding; f, 2 PV waterflooding + 0.3 PV SiO2/SDS foam flooding; g, 2 PV waterflooding + 0.5 PV SiO2/SDS foam flooding; and h, 2 PV waterflooding + 0.5 PV SiO2/SDS foam flooding + 1 PV waterflooding). The flow direction is indicated by a red arrow.
Figure 6. Local microscopic image (left) and distribution of remaining oil after SDS solution flooding (right) (left, 2 PV waterflooding + 0.3 PV SDS solution flooding; right, 2 PV waterflooding + 0.5 PV SDS solution flooding + 6.5 PV waterflooding). The flow direction is indicated by a red arrow.
could not be trapped in the bubble effectively because the SDS foam was unstable. The dense film formed by nanoparticles adsorbed on bubble surface can inhibit the bursting of bubbles, and the stability of the bubbles was enhanced. So, the separation of gas and liquid was inhibited even at the beginning of SiO2/SDS foam flooding. After 1.0 PV of additional brine flooding, the brine took the place of SDS foam because of bubble coalescence and rupture, but for SiO2/SDS foam flooding, there were still lots of bubbles remaining in the pores due to enhanced foam stability. Since the bubble film of SDS foam easily ruptures due to the transfer of SDS molecules from the foam surface to rock surface, the bubble was unstable, and coalescence was always observed during the experiments (Figure 8a and b). The adsorption amount of SDS on the sand surface is shown in Table 3. The adsorption increased with increasing concentrations of SDS. When the temperature rose to 80 °C, the adsorption was a little lower than that of adsorption at 60 °C. As for the SiO2/SDS foam, the coalescence rarely occurred during the flooding process. When SDS foam contacted with the oil on the pore wall, the foam was more likely to deform and flow around the oil (Figure 8c−f). Then, the oil on the pore wall could not be displaced. For the SiO2/SDS foam, the foam had lateral pressure on the pore wall, so the residual was extruded and pulled out. Lu et al.41 found that it was mainly because of the viscoelasticity of bubbles. Bubbles kept their spherical shape due to the adsorption of SiO2 and deformed when they were in contact with the oil droplet. On account of the high viscoelasticity of the bubble film, bubbles recovered their spherical shape, resulting in a microforce on the oil droplet. Thus, the oil droplet changed its shape and was pulled out (Figures 8g−j). The schematic mechanism of SDS foam and SiO2/SDS foam working on the oil droplet is shown in Figure 9. For SDS foam, the microforce acting on the oil droplet was small, and the bubble was more apt to deform, so it could not change the shape of the oil droplet and move it. According to the surface rheology measurement, nano-SiO2 enhanced the viscoelasticity of the liquid/air surface layer remarkably. 39 The SiO 2 nanoparticles adsorbed on the bubble surface could provide a barrier to film rupture, and the viscoelasticity of the bubble was enhanced. The higher the viscoelasticity is, the more the
Table 2. IFTs between Oil and Foaming Agent Solution formula of solution brine (0.5 wt % NaCl) 0.0 wt % SiO2 + 0.5 wt 0.1 wt % SiO2 + 0.5 wt 0.5 wt % SiO2 + 0.5 wt 1.0 wt % SiO2 + 0.5 wt 1.5 wt % SiO2 + 0.5 wt 2.0 wt % SiO2 + 0.5 wt
% % % % % %
SDS SDS SDS SDS SDS SDS
unit
IFT
mN/m mN/m mN/m mN/m mN/m mN/m mN/m
21.7 4.2 4.5 5.2 5.8 6.1 6.3
were shown in Table 2. The data showed that the SDS solution could reduce the IFT of oil/water. So, oil was easily stripped from the rock. Besides, the W/O emulsions could retard viscous fingering, plug the water channel due to high viscosity, and increase the sweep volume.5 It can be seen from Figure 6 that the displacement effect of SDS solution flooding was better than that of waterflooding; however, there was still considerable oil residue on both sides of the main diagonal line (see the oval zones on the left in Figure 6). 3.2.3. Displacement of SDS Foam Flooding and SiO2/SDS Foam Flooding. During SDS foam flooding, a few bubbles were formed at first. Parts of gas and liquid were separated (Figure 7a), and a gas channeling path appeared. As more foam was injected into the micromodel, the number of bubbles was increased gradually (Figures 7b and c). When 1.0 PV of additional brine was injected into the model, the bubble number decreased because of brine flushing (Figure 7d). Compared with SDS foam flooding, more bubbles were formed at first (Figure 7e) in the process of SiO2/SDS foam flooding, thereby reducing the mobility of gas and preventing gas breakthrough. The number of bubbles was increased as more foam was injected into the model (Figure 7f and g). Although bubble number is decreased when 1.0 PV of additional brine was injected, it was still higher than that of SDS foam, proving that there exists a better brine flushing resistance in SiO2/SDS foam (Figure 7h). At the beginning of SDS foam flooding, gas 2388
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Figure 8. Different flow behaviors for SDS foam (a−f) and SiO2/SDS foam (g−j) in a micromodel. The flow direction is indicated by a red arrow.
Table 3. Adsorption of Different Concentrations of SDS on the Sand Surface concn of SDS/wt %
unit
adsorptiona (60 °C)
adsorptionb (80 °C)
0.1 0.2 0.3 0.4 0.5
mg/g mg/g mg/g mg/g mg/g
0.08 0.23 0.38 0.55 0.62
0.07 0.20 0.32 0.51 0.58
a b
Figure 10. Residual oil in a dead-end pore swept by different displacing fluids (a, brine flooding; b, SDS foam flooding; and c, SiO2/ SDS foam flooding). The flow direction is indicated by a red arrow.
Adsorption amount of SDS on the sand surface measured at 60 °C. Adsorption amount of SDS on the sand surface measured at 80 °C.
impact in sweeping oil from the pore. During the brine flooding process, the displacing brine could only be in contact with one side of the dead end pore; therefore, the sweep volume was very small. When SDS foam flooding was adopted (Figure 10b), about 30% of the residual oil in the dead end had been displaced. The larger bubbles pushed the smaller ones into the pores, so some of the oil could be displaced from the dead end pore. In addition, it was possible that SDS in the bulk phase could reduce the IFT of oil/water, thereby assisting oil removal from the dead end pore, but there was still a lot of residual oil left in the pore. As the oil had a negative effect on SDS foam stability, the unstable bubbles could not occupy the space of dead end pores, and the efficiency of foam displacement was
microforce works on the oil droplet. So, the shape-changed oil droplet was easier to move and pull out. As a result, the SiO2/ SDS foam displaces more oil than the SDS foam. In porous media, some pores have only one open end, which are called “dead end pores,” and there is a lot of residual oil after waterflooding. In this way, how to improve the displacement of oil in dead end pores attracts many researchers’ attention. In this study, microscopic model tests were also carried out to examine the effect of SiO2/SDS foam on displacing the residual oil in the dead end pores. As can be seen in Figure 10a, the dead end pore remained full of residual oil after brine flooding, indicating that brine flooding had very little
Figure 9. Displacement differences for an oil droplet on a pore wall by SDS foam (left) and SiO2/SDS foam (right). The flow direction is indicated by a red arrow. 2389
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reduced. While SiO2/SDS foam demonstrated much higher sweeping efficiency than SDS foam, over 60% of oil in the dead end pore was displaced (Figure 10c). The SDS in the SiO2/ SDS dispersion could also lower the IFT of oil/water and increase the displacement efficiency, although it was slightly higher than that of SDS solution. SiO2 nanoparticles on the bubble surface enhanced the foam stability against film rupture and Ostwald ripening, and the bubble was more stable than SDS foam when it came in contact with the residual oil. The smaller bubbles could be squeezed into the dead end pores by flushing larger bubbles. These stable bubbles penetrated further into the pore and displaced more oil. When the stable bubbles invaded the dead end pore, the microforces acting on the oil droplet also helped to recover more oil.42 On the basis of the foam flooding tests, it the micromodel, it can be seen (Figure 11) that the SiO2/SDS foam displaced
Figure 12. Pressure changes during foam flooding as a function of SiO2 concentration.
The oil recovery during the flooding was also recorded. As shown in Table 4, the oil recovery of waterflooding was about 32.7%−35.3%, which meant that a lot of residual oil was still in the core. When the SDS foam flooding was adopted, the increased oil recovery was about 12.1%. It can be seen from Figure 12 that the differential pressure was about 0.6 MPa during the SDS foam flooding process. It indicated that the SDS foam could partly block the water channels and increase the sweep volume. Besides, the SDS in the bulk phase could reduce the IFT of oil/water and therefore help to improve oil recovery. The enhanced oil recovery exhibited a significant change and increased with the SiO2 concentration ranging from 0.1 wt % to 1.5 wt %. When SiO2 was above 1.5 wt %, the oil recovery only increased slightly. It is noted that the value of the differential pressure peak was also a function of SiO2 concentration and exhibited the same trend as oil recovery. As shown in Figure 12, there was a rather low peak in the differential pressure during SDS foam flooding. The SDS foam was unstable in porous media, and the bubble broke easily, causing cross flows of gas phase and reduced the efficiency of foam flooding. There exists a significant increase in the differential pressure when the SiO2 concentration was above 0.5 wt %. The oil recovery showed a good correspondence with the increase of the differential pressure during foam flooding. 3.3.2. Double-Core Sandpack Oil Displacement. Six heterogeneous double-core sandpack models (#7−#12) were also conducted to evaluate the effectiveness of SiO2/SDS foam flooding for oil recovery to simulate the oil displacement in heterogeneous formation. The compositions of foam formula and results of flooding are shown in Table 5. The oil recoveries of waterflooding for high permeability and low permeability sandpacks were 41.3%−44.3% and 10.8%−13.1%, respectively. The total oil recovery from the dual-core sandpack by waterflooding was 26.7%−28.8%, and the increased oil recovery with different concentrations of SiO2 ranged from 6.1% to 32.4%. The oil mainly came from the high permeability sandpack when waterflooding. For SDS foam flooding, the EOR-H and EOR-L were almost the same, but for SiO2/SDS foam flooding, the EOR-L was higher than EOR-H, and the higher the concentration of SiO2, the greater the gap between EOR-L and EOR-H. However, when the concentration of SiO2 was above 1.5 wt %, the gap changed slightly. During the foam flooding process, more and more oil came from the low permeability sandpack as the concentration of the SiO2
Figure 11. Distribution of remaining oil for SDS foam flooding (left) and SiO2/SDS foam flooding (right) (left, 2 PV waterflooding + 0.5 PV SDS foam flooding + 6.5 PV waterflooding; right, 2 PV waterflooding + 0.5 PV SiO2/SDS foam flooding + 6.5 PV waterflooding). The flow direction is indicated by a red arrow.
more oil in micromodel than SDS foam. The oil saturation after SDS foam flooding was about 23.2%, while the value was 6.1% after SiO2/SDS foam flooding by using the image analysis technique. The foam stability was enhanced with the SiO2 adsorbed on the bubble surface, and more gas was trapped in, thus gas channel was avoided. The bubbles reduced the mobility of gas phase and improved the sweep volume. In addition, the enhanced viscoelasticity of foam and reduced oil/ water IFT also helped to displace more residual oil droplets from the pore wall and dead end pores. 3.3. Sandpack Flooding Experiments. 3.3.1. Single-Core Sandpack Oil Displacement. Foam flooding tests (#1−#6) were conducted to examine the effect of SiO2 concentration on oil recovery with a single-core sand pack to simulate the oil displacement in homogeneous formations. Figure 12 shows the pressure drop responses as a function of injected fluid volume during the flooding tests. It was observed that, at the beginning of waterflooding, the differential pressure increased and that a peak appeared quickly. Then, the differential pressure fell sharply, indicating that the water breakthrough occurred in the core at 0.2 PV of water injection. From the low breakthrough PV, it is indicated that the displacement process was unstable and viscous fingering might dominate during waterflooding. With 0.6 PV injection of SiO2/SDS foam, the differential pressure started to rise, and a high differential pressure peak value was observed (see Figure 12). The differential pressure rose up with an increase in SiO2 concentration. The built-up differential pressure suggested that the stable foam blocked the water channels. As a result, the subsequently injected water was forced to the oil enrichment zone and improved sweep efficiency. 2390
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Table 4. Summary of SiO2/SDS Foam Flooding Tests in Cores
a
sandpack no.
waterflooding recovery/%
concn of SiO2/%
increased oil recoverya/%
final oil recovery/%
remaining oil saturation/%
#1 #2 #3 #4 #5 #6
34.55 35.32 33.64 34.21 32.65 33.37
0 0.1 0.5 1.0 1.5 2.0
12.1 16.3 24.4 29.3 37.6 38.3
46.7 51.8 58.0 63.5 70.2 71.7
47.1 43.1 38.2 33.4 25.4 23.8
Oil displaced by foam flooding and subsequent water flooding.
Table 5. Enhanced Oil Recovery in Heterogeneous Double-Core Sandpack sandpack no. #7 #8 #9 #10 #11 #12
foam formula 0.0 0.1 0.5 1.0 1.5 2.0
wt wt wt wt wt wt
% % % % % %
SiO2 SiO2 SiO2 SiO2 SiO2 SiO2
+ + + + + +
0.5 0.5 0.5 0.5 0.5 0.5
wt wt wt wt wt wt
% % % % % %
SDS SDS SDS SDS SDS SDS
EOR-Ha/%
EOR-Lb/%
EOR-Tc/%
remaining oil saturation/%
6.2 6.5 13.8 18.3 21.0 22.5
5.9 14.7 26.6 33.6 43.1 43.6
6.1 10.5 19.9 25.8 31.5 32.4
58.1 53.3 45.7 38.9 32.7 31.9
a Oil displaced from the high permeability sandpack by foam flooding and subsequent waterflooding. bOil displaced from the low permeability sandpack by foam flooding and subsequent waterflooding. cThe total oil displaced from the double-core sandpack by foam flooding and subsequent waterflooding.
permeability sandpack, and more oil was displaced from the sandpack for 1.0 PV SiO2/SDS foam flooding and subsequent waterflooding. However, there was a slight decrease of the diversion ratio of the low-permeability sandpack when the SiO2 concentration was 2.0 wt %. The result indicates that the SiO2/ SDS foam could improve the water injection profile of porous media effectively and displace more oil in the dual-core sandpack. The diversion ratios of high- and low-permeability sandpacks were still maintained at 50% even when the brine had been injected for 1.0 PV, indicating that the SiO2/SDS foam had a large resistance to water flushing (Figure 7h). At the beginning of foam injection, the stable foam went into the highpermeability path in the sandpack and then plugged the water channel by its high apparent viscosity. When subsequent brine was injected, the brine changed the direction of flow and displaced the remaining oil in the low-permeability sandpack. Ma et al.43 also proved that the better the foam stability was, the better was the diversion effect with a micromodel. From Table 5, it can be seen that the oil recovery increased with the SiO2 concentration. As a result, it can be concluded that the nanoparticles impose a positive effect on oil recovery and that the oil recovery from the low-permeability sandpack exhibits a larger change than that of the high permeability sandpack. The increased oil mainly came from the low-permeability sandpack. It is suggested that there exits a great developing potential with SiO2/SDS foam in low-permeability formation after waterflooding.
increased, and the EOR-T was also increased. This result indicates that the SiO2/SDS foam can effectively plug the high permeability sandpack and improve the sweep volume in the low permeability sandpack. Besides, the SDS could also lower the IFT of oil/water, so the oil was more removable and displaced out of the sandpack. The changes of diversion ratio and oil recovery during the injection process of foam flooding with different concentrations of SiO2 are shown in Figure 13. The initial diversion ratios of high and low permeability sandpacks with waterflooding were about 84.0% and 16.0%, respectively. During the waterflooding process in heterogeneous formation, the injected water would go through along the high-permeability path first; the sweep region was mainly in the high-permeability zone. Since the low-permeability zone was almost unswept, the oil recovery for low-permeability during waterflooding was very low, and the whole oil recovery from the dual-core sandpack was also very low (Table 5). There was still a lot of remaining oil in both high- and low-permeability sandpacks. During foam flooding, the diversion ratio of the high-permeability sandpack decreased, but the low-permeability sandpack increased with increasing injection volume of the foam. For SDS foam flooding, the diversion ratio of the lowpermeability sandpack increased, but the increase was minor. At the end of SDS foam flooding, the diversion ratio of the lowpermeability sandpack was about 34.0%, so the enhanced oil recovery for 1.0 PV SDS foam flooding (4.9%) and subsequent waterflooding (1.2%) was very low. The diversion ratio of the low-permeability sandpack went up when the SiO2/SDS foam was injected into the dual-core sandpack models, and it had a good correspondence with the increase of SiO2 concentration. When the concentration of SiO2 was 1.0 wt %, the equal diversion ratios of high-permeability and low-permeability sandpacks began to appear at the end of foam flooding, and the enhanced oil recovery for 1.0 PV SiO2/SDS foam flooding was about 17.2%, and 8.6% for the subsequent waterflooding. The diversion ratio of the low-permeability sandpack was higher than that of the high-permeability sandpack when the concentration of SiO2 was 1.5 wt %. That means that more fluid came from the low-permeability sandpack than the high-
4. CONCLUSIONS (1) The foam stability is increased when SiO2 nanoparticles are added into the SDS solution, although the foam volume is decreased slightly. The SiO2/SDS foam shows better temperature tolerance than the SDS foam, and the bubble can maintain spherical or ellipsoidal shape with time in porous media. This is mainly due to the adsorption of nanoparticles on the bubble surface. (2) The micromodel flooding experiments show that SiO2/ SDS foam flooding can displace more oil than waterflooding, SDS solution flooding, or SDS foam flooding, and it has been 2391
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Figure 13. Change of diversion ratio and oil recovery during foam flooding as a function of SiO2 concentration (a, 0.0 wt % SiO2 + 0.5 wt % SDS; b, 0.1 wt % SiO2 + 0.5 wt % SDS; c, 0.5 wt % SiO2 + 0.5 wt % SDS; d, 1.0 wt % SiO2 + 0.5 wt % SDS; e, 1.5 wt % SiO2 + 0.5 wt % SDS; and f, 2.0 wt % SiO2 + 0.5 wt % SDS).
observed to have greater utility for flushing oil from dead end pores. The improvement is attributed to the enhanced foam stability and viscoelasticity caused by the attached particles. (3) The sandpack flooding tests indicate that SiO2/SDS foam has good properties for oil displacement in both homogeneous and heterogeneous formation. The increases in differential pressure and profile control effect have a good correspondence with the increase of SiO2 concentration, and the test with higher SiO2 concentration leads to a higher oil recovery. When the SiO2 concentration is above 1.5 wt %, the increase is minor. In addition, SDS could lower the IFT of oil/ water and help to improve oil recovery.
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Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS
This work was financially supported by the National Natural Science Foundation of China (51274288), the National Natural Science Foundation of Shandong Province (2012ZRE28014), the National Natural Science Foundation of China-Petrochemical Industry Fund (U1262102), the Fundamental Research Funds for the Central Universities (13CX06026A, 13CX02061A, and 13CX05018A), the Fundamental Research Funds for the Central Universities (13CX06027A), and the Outstanding Doctoral Dissertation Training Program of the China University of Petroleum (Grant LW130201A). We sincerely thank other colleagues in the Foam Fluid Research
AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. 2392
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