Effect of Salinities on Supercritical CO2 Foam Stabilized by Betaine

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Fossil Fuels

Effect of Salinities on Supercritical CO2 Foam Stabilized by Betaine Surfactant for Improving Oil Recovery Weitao Li, Falin Wei, Chunming Xiong, Jian Ouyang, Mingli Dai, Liming Shao, and Jing Lv Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b01688 • Publication Date (Web): 29 Aug 2019 Downloaded from pubs.acs.org on August 30, 2019

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Energy & Fuels

Effect of Salinities on Supercritical CO2 Foam Stabilized by Betaine Surfactant for Improving Oil Recovery Weitao Li*, Falin Wei, Chunming Xiong, Jian Ouyang, Mingli Dai, Liming Shao, Jing Lv Research Institute of Petroleum Exploration & Development, PetroChina, Beijing, 100083, P. R. China

ACS Paragon Plus Environment

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ABSTRACT

A zwitterionic surfactant, hexadecyl hydroxypropyl sulfo betaine (HHSB), was examined for its ability to stabilize supercritical CO2 foam (SC-CO2 foam), with the goal of improving the oil recovery from mature oil fields with high temperatures and salinities. Herein, we present a detailed investigation of the effect of salinity on the SC-CO2 foam. First, the bulk foaming capacity was assessed for a betaine surfactant with different salinities, using a high-temperature high-pressure (HTHP) foam generation apparatus. The effect of salinity on the rheology, flow resistance, and foam texture of the SC-CO2 foams was characterized using a flow loop apparatus with a capillary tube and high-pressure visual cell that was under high-temperature and highpressure conditions. The stabilization mechanisms of the salinity for the SC-CO2 foam were also explored by means of an HTHP interfacial tensiometer. Experimental results showed that the foaming volume slightly decreased, whereas the stability and apparent viscosity of the SC-CO2 foam increased with increasing salinity. The foam half-life increased approximately 1.6-fold, from 22.2 to 35.2 min, while the apparent viscosity increased from 43.4 to 62 mPa•s at 16 s-1. The resistance factor of the steady-state CO2 foam increased from 48 to 53 with increasing salinity, and the bubble size was approximately 10~20 μm during the core flooding experiments. The experiments indicated that the salinity could enhance the stability of the foam against film drainage and bubble coalescence. The interfacial experiments presented evidence that salt ions could drive more betaine surfactant molecules to adsorb on the lamella interface. The greater surfactant adsorption provided the large steric repulsion between bubble lamellae and enhanced the

disjoining

pressure,

thereby

improving

the

foam

stability.


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1 INTRODUCTION CO2 flooding, which is designed to improve oil recovery in the middle-low permeability reservoirs, has been increasingly implemented worldwide since the early 1970s.1 Under reservoir conditions with high pressures, which are usually above the minimum-miscibility pressure (MMP), supercritical CO2 is readily miscible with crude oil and can expand the oil volume and decrease its viscosity, thereby improving the mobility of the remaining oil in water-drive oilfields and efficiently recovering the residual oil.2-4 The main challenge for CO2 flooding is the poor sweep efficiency, which includes the gas gravity override, viscosity fingering, and preferential channeling caused by the large density and viscosity differences between the gas and fluid, due to the reservoir heterogeneity.5,6 Therefore, several methods have been developed to control the CO2 mobility, such as the water alternating gas (WAG) method, CO2 foams,7 polymer gels, and CO2 responsive hydrogels.8 The ability of the WAG to control CO2 mobility is usually limited, and the increased oil recovery is lower after the WAG measurements. Polymer gel treatment also faces some drawbacks. For example, the polymer solution may undergo shear degradation, leading to limited conformance control in deep reservoirs. CO2 responsive hydrogels may consume large amounts of surfactant, and their costs are very high.9 By comparison, CO2 foam is a promising tool for controlling CO2 mobility, due to the relatively low cost and in-depth conformance control.10,11 With the development of mature oilfields with high temperatures (>70°C) and high salinities (10×104 mg/L),12 forming agents, such as anionic, nonionic, and cationic surfactants, face challenges because of their poor performances in harsh conditions.13 Anionic surfactants such as sodium dodecyl sulfate, alpha olefin sulfonate, and sodium lauryl sulfate, cannot be applied under high salinity conditions due to the strong interactions between the anionic groups and


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divalent cations.14 Nonionic surfactants, such as polyethylene glycol tert-octyl phenyl ether (TX100), precipitate above the cloud point temperature, which decreases with high salinity.15 Cationic surfactants, such as cetyltrimethylammonium bromide (CTAB), undergo strong adsorption on negatively charged reservoir rocks. Recently, betaine surfactants, as a type of zwitterionic surfactant, have attracted increased attention due to their great resistance to high temperatures and salinities. Betaine surfactants have been widely applied for improving oil recovery for mature oil fields. For example, Cai et al.16 synthesized two betaine surfactants from a long chain fatty acid and alcohol. The betaine surfactants exhibited great salt resistance at salinities as high as 20×104 mg/L and reached ultralow interfacial tensions within a wide concentration range. In addition to their use as a good oil-displacement agent, the betaine surfactant could also play an important role as a foaming agent. Many experiments have shown that SC-CO2 foam generated by betaine surfactants exhibited good stability, tolerance to salinity and temperature, and low adsorption on rock.17-19 Interactions between betaine surfactants and anionic surfactants or salts have been studied extensively. Iwasaki found that a mixed system containing betaine surfactants and sodium dodecyl sulfate (SDS) showed viscoelastic behaviors due to the electrostatic interactions of oppositely charged head groups between these two surfactants.20 Chorro showed that the increase in NaCl and CaCl2 contents increased the saturation adsorption of betaine surfactants onto silica gel by approximately 10%.21 They argued that the presence of salt in the surfactant solution could screen the electrostatic repulsion between dipolar heads, which contributed to the tight arrangement of surfactant molecules on the surface. Our group found that hexadecyl hydroxypropyl sulfo betaine sulfonyl betaine (HHSB) can generate good SC-CO2 foam at high temperatures (up to 90°C) and high salinity (20×104 mg/L). The foam stability could be improved at high temperature by additions to some foam stabilizers,


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such as nanoparticles and philic-CO2 surfactants.22,23 Although extensive studies have been conducted to study the oil-displacement and foaming capacities of zwitterionic surfactants, few comprehensive experimental investigations have been conducted on the stabilization of SC-CO2 foam due to high salinities. The objective of this study was to confirm that an increase in salinity could enhance the foam stability by different experimental methods at 70°C and 8 MPa. The salt concentration ranged from 2×104 to 25×104 mg/L in the experiments. The stabilization mechanisms of the salinity on the SC-CO2 foam were also explored by measuring the interfacial tension. 2 EXPERIMENTAL SECTION 2.1 Materials. The zwitterionic surfactant hexadecyl hydroxypropyl sulfo betaine (C16H33N(CH3)2CH2CH(OH)CH2SO3), was donated by the Shanghai Nuosong Chemical Co., Ltd., China. Sodium chloride and calcium chloride were purchased from Beijing Chemical Works, China. Six types of formation brine were prepared using deionized (DI) water, with the addition of NaCl and CaCl2 in a 9:1 ratio. The total dissolved solid contents were 2×104, 5×104, 10×104, 15×104, 20×104, and 25×104 mg/L. 2.2 SC-CO2 Foaming Ability and Stability Assessment. SC-CO2 foam was prepared by a blending method using a high-temperature, high-pressure (HTHP) foaming apparatus,24 as shown in Figure 1. First, a 100-mL surfactant solution was pumped into the HTHP view chamber from the bottom, and the volume of the chamber was approximately 600 mL. The gas storage tank inside the oven was heated to 70°C, and the pressure in the storage tank was kept steady. CO2 was injected into the HPHT view chamber from the bottom and pressurized to 8 MPa. After the pressure and temperature in the view chamber were stable, the surfactant solutions were agitated at a speed of 2000 rpm for 5 min. Finally, the maximum foaming volume was recorded to assess


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the foaming ability. The drainage volume was recorded with time, as shown in Figure 2, and the time when 50% of the fluid separated from the bulk foam and appeared at the bottom of the chamber was referred to as the half-life of the SC-CO2, which was used to characterize the foam stability. 2.3 Viscosity and Density Measurements of Bulk Surfactant Solutions under HTHP Conditions. The apparent viscosity of the surfactant solutions was measured using a Cambridge HPHT viscometer, which was based on a simple and reliable electromagnetic concept. The sampling chamber was heated to the desired temperature, after which the surfactant solutions with different salinities were pumped into the cell until it reached the desired pressure. Finally, the measurements started automatically. The measurements ignored the effect of CO2 on the viscosities of the surfactant solutions. The densities of the surfactant solutions were measured using an Anton Paar HPHT densimeter. The density measurement procedure was similar to that of the viscosity measurements. 2.4 Rheology Measurements of SC-CO2 Foam under HTHP Conditions. The rheology of the SC-CO2 foam was measured using a capillary tube (4-mm ID, 8000 mm long).25 The apparatus for the viscosity measurements is shown in Figure 3. The SC-CO2 foam was produced by co-injecting the CO2 and surfactant solution through the foam generator to achieve a gas-fluid ratio of 1:1 at a temperature of 70°C and a back pressure of 8 MPa. The pressure difference was determined using a differential pressure meter, the range of which was 50 kPa. The average differential pressure was obtained by averaging the testing values for 10 min after the foam reached a steady state in the capillary tube. The total flow rate was set to 6, 8, 10, and 15 mL/min, corresponding to shear rates of 15.9, 26.5, 39.8, and 53 s-1, respectively. The shear rate γN and shear stress τN of a Newtonian fluid can be calculated using Equations (1) and (2).26


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Energy & Fuels

γN 

τN 

8v f

(1)

D

DP 4L

(2)

A power law model (expressed by Equation (3)) was applied to describe the rheological behavior of the SC-CO2 foam, because foams usually behave as non-Newtonian fluids.26

τ  Kγ n

(3)

The shear rate of the non-Newtonian fluid γ was calculated using Equation (4).  3n  1  γ  γN    4n 

(4)

The parameter n was obtained by fitting a straight line to the natural logarithms of γN and τN. The parameter K was obtained from the apparent wall shear rate stress at a shear rate of 1 s-1. The apparent viscosity of the SC-CO2 foam was calculated using Equation (5). μa 

τ  Kγ n 1 γ

(5)

where vf is the velocity of the SC-CO2 foam in the capillary, D is the inner diameter of the capillary tube, ΔP is the pressure difference between the two capillary ends, L is the length of the capillary tube, and n and k are the power-law exponent and consistency coefficient, respectively. 2.5 Steady-State SC-CO2 Foam Test and Optical Microscopy under HTHP Conditions. The steady-state SC-CO2 foam was formed when the bubble generation rate and bubble coalescence rate reached equilibrium in the porous medium. First, the core was vacuum-saturated with brine, and the permeability of the core was determined. Next, 10 pore volumes of surfactant solution were injected into the core to saturate the core surface with adsorbed surfactant. Then,


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the CO2 and surfactant solutions were co-injected into the core with a volume ratio of 2:1 until the pressure difference along the core fluctuated within a fairly narrow range (the differential pressure varied by less than 5% of the average value), indicating that a steady state was reached. After a steady state was achieved, the SC-CO2 foam was injected into the HTHP microscope cell. The microscope cell was mounted beneath the microscope (Leica S6D). The path length of the microscope cell was approximately 100 μm. Upon stopping the flow through the cell, photomicrographs of the SC-CO2 foams were obtained using a microscope camera that was connected to a computer, to observe the effluent foam textures. The size distributions of the SCCO2 foam were determined by analyzing the microscope images using the ImageJ software. The foam strength was evaluated through the resistance factor at the steady state. The resistance factor was calculated through the following equation (6):

RF=

kw μw

kf μf

=

Pf

(6)

P0

where RF is the resistance factor, kw is the effective permeability of water, μw is water viscosity, kf is the effective permeability of foam, μf is foam viscosity, Pf is the pressure difference produced by SC-CO2 foam, and P0 is the pressure difference produced by formation water. The core was cleaned with 10 pore volumes of isopropanol, followed by a few hundred milliliters of DI water, until the effluent was surfactant-free. The schematic of the flow loop apparatus for evaluating foam dynamics and bubble texture is shown in Figure 4, and the parameters of the core are listed in Table 1. 2.6 Surface Tension Measurements under HTHP Conditions. The interfacial tension (IFT) values between CO2 and different surfactant solutions were measured with an HTHP interfacial


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tensiometer (ramé-hart Instrument, France), as shown in Figure 5. The values of the IFT were obtained using image analysis software. Determination of the IFT for every measurement was repeated three times, and the average value was calculated. Due to the relatively low mutual solubility of water and CO2, the pure component density was used for the calculation. The IFT was calculated by the following equation (7):

γ=

ρgR0 2

(7)

β

where γ is the surface tension, Δρ is the mass density difference between the surfactant solution and CO2, R0 is the radius of curvature at the drop apex, and β is the shape factor. 3 RESULTS AND DISCUSSION 3.1 Effect of Salinity on Foaming Properties. When the foaming agent was injected into the reservoir, it experienced adsorption and dilution. To ensure a better foaming capacity under the reservoir conditions, the optimum surfactant concentration must be selected.27 The foaming capacities of the betaine surfactant with different concentrations ranging from 0.03% to 1% were evaluated at 70°C and 8 MPa. As shown in Figure 6, with the increase in the surfactant concentration, the foaming volume decreased slightly, whereas the half-life of the SC-CO2 foam increased considerably. As the surfactant concentration was changed from 0.03% to 0.3%, the half-life increased considerably. When the surfactant concentration was greater than 0.3%–1%, the half-life of SC-CO2 foam increased relatively slowly with the increase in the surfactant concentration. Thus, the surfactant concentration must exceed 0.3%. Otherwise, the foaming stability will decline sharply, due to the adsorption and dilution. It is known that when the surfactant concentration is greater than the critical micelle concentration (CMC), more spherical micelles form, as a result of the higher surfactant concentration, leading to a high solution viscosity and lower drainage rate.28 Accounting for the surfactant cost, the optimized surfactant


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concentration is 0.5%. In the following experiments, to evaluate the foam stabilized by the betaine surfactant, the concentration of the foaming agents was set to 0.5%. Figure 7 shows the evolution of the foaming volume and half-life as a function of salinities when the HHSB concentration was 0.5%. The salinities had little effect on the foaming volume. The foaming volume decreased from 515 to 500 mL, with an increase in salinity from 2×104 to 25×104 mg/L, and the value of the foaming volume changed negligibly. However, the half-life of the SC-CO2 foam increased significantly. As the salinity increased from 2×104 to 25×104 mg/L, the foam half-life increased approximately 1.6 times, from 22.2 to 35.2 min, indicating that the salinity had an apparent effect on the SC-CO2 stability. It can be concluded that higher salinities delayed gravitational drainage of liquid, which would result in lamellae thinning and the ultimate rupture of the SC-CO2 foam bubbles. Figure 8 shows the drainage volume versus time for the surfactant solutions with different salinities. The presence of more salts in the surfactant solutions brought about reduced drainage rates. The plots of the drainage volume with time could be fit with straight lines. As shown in Figure 9, the slope of the curve decreased with an increase in the salinity, indicating that the drainage rate declined with the increase in salinity. The linear fit equation is given in Table 2. Based on the slope of the fitted curve, the drainage rate could be obtained. The drainage rate us of spherical emulsion droplets can be expressed using Stokes’ law as shown in Equation (8).29 The real drainage rate u will be slowed for a foam system with a specific dispersed phase volume.30 The relationship between the actual rate u and us can be expressed by Equation (9). Figure 10 shows the viscosity and density of surfactant solutions with different salinities at 70°C and 8 MPa. Because of the partial miscibility of water and CO2, the effect of CO2 solubility in water on the surfactant solution viscosity was neglected.31 With the increase in salinity, the


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viscosity and density of the surfactant solutions increased. Therefore, based on Equations (8) and (9), the average radius of the SC-CO2 foam can be calculated. The parameters and calculated results are shown in Table 3, and the average radius of the SC-CO2 foam decreased from 256.73 to 198.77 µm. The lower foam size indicated that the foam microstructure became denser, thereby retarding Ostwald ripening and the coalescence rate. After stirring was stopped, SC-CO2 foam, with a salinity of 10×104 mg/L, was injected into the HTHP microscope cell, and the microstructure is shown in Figure 11. It can be seen that the mean bubble size was approximately 88 µm initially, which was smaller than the calculated average bubble size. Equations (8) and (9) are as follows:

us 

2r 2 ρg 9 μc

u  us 1  Φ 

(8)

6.55

(9)

where r is the foam radius, Δρ is the density difference between the surfactant solution and SCCO2, μc is the viscosity of the continuous phase, us is the settling velocity in Stokes’ law, u is the real settling velocity, and φ is the volume fraction of the dispersed phase in the total foam volume. 3.2 Effect of Salinities on the Apparent Viscosity of SC-CO2 Foam. To control the gravity override and viscous fingering, SC-CO2 foam must have an apparent viscosity several orders of magnitude larger than that of CO2, thereby lowering the gas mobility and mitigating gas channeling.32 SC-CO2 foam is a non-Newtonian fluid, obeying a power law model.33 For the power law model, pseudoplastic fluids exhibit shear-thinning behaviors (n1), and the apparent viscosity increases with the growth of the shear rate. The


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apparent viscosity of the SC-CO2 foam flowing through a capillary tube was measured at 70°C and 8 MPa. Figure 12 shows the shear stress versus the shear rate curves on a log-log scale, which was fit with straight lines. The fitting equation is shown in Table 4. Based on the linear fit curve, power law equations were obtained (as shown in Table 5). The apparent viscosity of the SC-CO2 foam could be calculated according to the power law equations, and Figure 13 shows the viscosity variation of the SC-CO2 foam with different salinities. The apparent viscosities of the SC-CO2 foam in the capillary tube ranged from 20 to 60 mPa·s, as the shear rate was changed from 16 s-1 to 53 s-1, which was at least 1000 times higher than the gas viscosity (approximately 0.02 mPa·s at 70°C and 8 MPa). It is evident from Figure 13 that the apparent viscosity declined with increasing shear rate for the SC-CO2 foam, and the rheological index n was less than 1 for all the fit power law equations. The apparent viscosity was approximately 62 mPa·s at 16 s-1 for SC-CO2 foam with 25×104 mg/L, and it increased by nearly 1.5 times the value in SC-CO2 foam with 2×104 mg/L. Furthermore, the rheological index n increased with the increase of salinity, whereas consistency coefficients k decreased with the increase of salinity. The rheological behavior demonstrated once again that when the salinity increased, denser and stronger foams were generated in the capillary tube. 3.3 The Generation of SC-CO2 Foam in the Core Flooding. To investigate the effects of salinity on the SC-CO2 foam stabilized by betaine surfactants in a porous medium, six groups of foam flooding experiments were conducted to compare the resistance factors, which are typically used to characterize the foam mobility in reservoirs. The larger the resistance factor, the lower the foam mobility. The steady-state flow of SC-CO2 foam eliminated the effect of adsorption and dilution on the foam, allowing the dynamic properties of the SC-CO2 foam in the core to be objectively evaluated. Figure 14 shows the steady-state resistance factor as a function of


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injection time for SC-CO2 foams with different salinities. The dynamic foaming process can be divided into two phases. The first phase is the foam formation process, in which the foam generation rate was greater than the foaming coalescence rate, resulting in an increase in the resistance factor.34 The second process was the steady-state process, in which the foam generation rate was close to the foam coalescence rate. We introduced the steady-state resistance factor to quantify the foam strength in porous medium. When the salt concentration was relatively low ( ≤ 10×104 mg/L), the resistance factor was lower than 50. When the salt concentration became larger (>10×104 mg/L) the resistance factor was increased clearly, which was indicative of strong foam formation in the porous medium. 3.4 Texture of the Steady-State SC-CO2 Foam in the Core Flooding. Bubble size and foam texture were determined by processes that generated and destroyed foam lamellae in the porous medium at different times. Small bubble sizes and a dense foam texture indicated that the foam had good stability and contributed to the large resistance factor. After the foam in the core reached a steady state, where the bubble generation rate was close to the bubble coalescence rate, the images of the CO2 foam were captured in the view cell. Figure 15(a) shows the macrographs of the SC-CO2 foam in the high-pressure view cell near the core outlet. The SC-CO2 foam in the gray area (red circle) flowed through the view cell from the core end, and the surface structure of the foam was very compact and opaque. The foam in the white area (green circle) was stationary, and the effluent CO2 foam from the core did not sweep these areas, in which the surface structure of the CO2 foam was loose. The SC-CO2 foam in the gray area was enlarged and was observed through the microscope, as shown in Figure 15(b). It can be noted that the enlarged SC-CO2 foam was black, and the structure of a single bubble cannot be recognized at such a resolution image. The space between the sapphire windows was 100 μm, whereas the bubble size was


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approximately 20~30 μm. Therefore, the multilayer structure of SC-CO2 foam existed in the high pressure cell, and large amounts of lamellae overlapped, which resulted in a low degree of optical opacity. Figure 15(c) shows the microstructure of CO2 foam at room temperature and atmospheric pressure. The average bubble size was approximately 100~200 μm, which was much larger than the SC-CO2 foam. To determine the foam texture and foam stability in the core, microscope images at different times were captured, as shown in Figures 16 and 17 for SC-CO2 foams with salinities of 5×104 and 25×104 mg/L, respectively. The initial bubble sizes of the SC-CO2 foams with salinities of 5×104 and 25×104 mg/L were approximately 10~20 μm, which was much smaller than the calculated size of the foam prepared using a blending method in the HTHP foaming apparatus. The bubble size in the core was correlated with pore structure. The average pore diameter of the core can be calculated with Equation (10). The permeability and porosity of the core used in the experiment were 0.614 μm2 and 21.2%, respectively. The average pore diameter was 9.62 μm, according to the equation. Therefore, the average pore radius was very close to the mean foam size. Based on Equation (11), the Dsm values of the SC-CO2 foams, with salinities of 5×104 to 25×104 mg/L after 60 min, were calculated. The values of Dsm after 60 min decreased from approximately 221.1 to 194.2 μm, as the salinity increased from 5×104 to 25×104 mg/L, respectively. Therefore, SC-CO2 foams with higher salinities showed slower bubble growth, meaning that stronger foams were generated in the porous medium. Equation (10) and (11) are as follows: d 2

8k φ

(10)

where d is the average pore radius, φ is the porosity, and k is the permeability.


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D  D

3

i

Dsm

(11)

i

2

i

i

where Dsm is the Sauter mean diameter, and Di is the bubble diameter. 3.5 Effect of Salinity on Interfacial Tension. To explore the mechanism of foam stability with increased salinity, the interfacial tension was measured at 70°C and 8 MPa. Compared with the deionized water/SC-CO2 interfacial tension (approximately 30 mN·m-1 at 70°C and 8 MPa), the betaine surfactant reduced the interfacial tension considerably, to approximately 10 mN·m-1. According to Equation (2), the density difference between water and SC-CO2 became larger with increasing salinity, which would lead to a higher interfacial tension. However, as shown in Figure 18, with the increase in the salinity, the interfacial tension decreased slightly. Similarly, from Figure 19 it can be seen that the curvature radius of the liquid drop decreased with an increase in salinity. It was reported that the pH value of the water-CO2 binary system was approximately 3 as the pressure was increased to 8 MPa.35 The isoelectric point of the betaine surfactant was approximately 6.36 When the pH was below this point, the betaine surfactant was converted to the cationic protonated form, and the surfactant would be primarily positive charged.37 The electrostatic repulsion between the positively charged head groups on the surfactant molecules would be screened by the presence of Cl- ions in the surfactant solution, which could contribute to the compact molecule arrangement at the gas-liquid surface, as shown in Figure 20. The gasliquid interface was packed with more surfactant molecules, which would result in a greater adsorption of the surfactant and a lower interfacial tension. The greater surfactant adsorption could also affect the disjoining pressure, which includes van der Waals attraction and repulsive interactions (electrostatic, steric and structural interactions).38 If the disjoining pressure could


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overcome the van der Waals attractions, a stable film would be formed. Therefore, the increased film stability with the increase in salinity was influenced by different causes. On one hand, the salt can screen the electrostatic repulsive interactions between bubbles, which will facilitate film drainage and lead to rapid coalescence. On the other hand, a higher surfactant adsorption and lower interfacial tension implies that there were long enough repulsive steric interactions to prevent coalescence.30,39 Despite the reduced electrostatic repulsion resulting from salt ions, the relatively larger steric repulsion caused the increase of disjoining pressure between the foam bubbles, thereby leading to highly stable foam lamellae. To further demonstrate the high surfactant adsorption at the gas-liquid interface with higher salinities, the interfacial tension between CO2 and surfactant solutions with different salinities was measured as a function of surfactant concentration at 70°C and 8 MPa, and the results are shown in Figure 21. The slope of the line for the interfacial tension versus surfactant concentration below the critical micelle concentration (CMC) was used to calculate the area per surfactant molecule (Am) and the molar concentration of the surfactant per unit area (Γ).40,41 Am and Γ were calculated based on the Gibbs adsorption, presented in Equation (12), for the SC-CO2 foams with addition of different salinities in surfactant solutions. Equation (12) is as follows: Γ=

1 1  N A Am RT

 γ    ln Csurf

  T ,P

(12)

where NA is Avogadro’s number, Am is the area per surfactant molecule at the interface, R is the gas constant, and C surf is the molar concentration of the surfactant. The results are shown in Figure 22 and verify the above hypothesis. It can be seen that the area per molecule Am became lower, whereas the molar concentration of the surfactant per unit area (Γ) became slightly higher with increasing salinity. When salinity concentration was increased


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Energy & Fuels

from 5×104 to 25×104 mg/L, the area per molecule of HHSB decreased from 95.5 Å2 to 87.4 Å2, and the molar concentration of HHSB per unit area increased from 1.7×10−6 mol/m2 to 1.9×10−6 mol/m2. The higher surfactant adsorption for the aqueous solutions containing a higher salinity revealed a greater tendency for the HHSB molecules to partition at the gas-liquid interface, compared to those with a lower salinity. 4 CONCLUSIONS The SC-CO2 foam was produced at a temperature of 70°C and 8 MPa with different salinities. The foaming capacity measurements showed that the foaming volume declined slightly, whereas the foam stability became greater with an increase in salinity. The half-life of SC-CO2 foam increased approximately 1.6-fold, from 22.2 to 35.2 min. Based on Stokes’ law, the average size was calculated, and the increased salt content was found to reduce the bubble size. The apparent viscosity was measured using a capillary viscometer based on a power law model and the apparent viscosity increased from 43.4 to 62 mPa•s at 16 s-1 with salinity increased from 2. The SC-CO2 foam was shear thinning, and the apparent viscosity increased with an increase in salinity. The steady-state SC-CO2 foam was also characterized in the porous medium, which was different from the blender method in the high-pressure cell. With increasing salinity, the resistance factor increased, corresponding to great foam strength. The interfacial measurements indicated that higher salinities reduced the surface tension and drop radius. According to the adsorption density of the surfactant molecules, salt ions can drive more surfactant molecules to adsorb on the gas-liquid interface, which caused an increase of disjoining pressure and improves the film stability. This work provided guidance for screening surfactants with the aim of lowering CO2 mobility in high salinity reservoirs. AUTHOR INFORMATION


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Page 18 of 53

Corresponding Author Weitao

Li, E-mail: [email protected]

Tel: +86-010-83592346, Fax: +86-010-83592346 Notes The authors declare no competing financial interest. ACKNOWLEDGMENTS This work was supported by the National Science and Technology Major Project (Grant No. 2016ZX05016004), the Key State Science and Technology Project (Grant No. 2017ZX05030) and the PetroChina Science and Technology Major Project (Grant No. 2016B-1304).


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REFERENCES (1) Patil, P. D.; Knight, T.; Katiyar, A.; Vanderwal, P.; Scherlin, J.; Rozowski, P.; Nguyen, Q. P. CO2 Foam Field Pilot Test in Sandstone Reservoir: Complete Analysis of Foam Pilot Response. In Proceedings of SPE Improved Oil Recovery Conference, Tulsa, Oklahoma, April 14–18, 2018. (2) Emera, M. K.; Sarma, H. K. Use of Genetic Algorithm to Estimate CO2–Oil Minimum Miscibility Pressure—a Key Parameter in Design of CO2 Miscible Flood. J. Pet. Sci. Eng. 2015, 46 (1-2), 37–52. (3) Correa, A. C.; Pande, K. K.; Brigham, W. E. Computation and Interpretation of Miscible Displacement Performance in Heterogeneous Porous Media. SPE Reservoir Eng. 1990, 5 (1), 69–78. (4) Hamouda, A. A.; Chukwudeme, E. A.; Mirza, D. Investigating the Effect of CO2 Flooding on Asphaltenic Oil Recovery and Reservoir Wettability. Energy Fuels 2009, 23 (2), 1118–1127. (5) Chang, S. H.; Grigg, R. B. Effects of Foam Quality and Flow Rate on CO2-Foam Behavior at Reservoir Conditions. In Proceedings of SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April 19–22, 1998. (6) Farajzadeh, R.; Andrianov, A.; Krastev, R.; Hirasaki, G. J.; Rossen, W. R. Foam–Oil Interaction in Porous Media: Implications for Foam Assisted Enhanced Oil Recovery. Adv. Colloid Interface Sci. 2012, 183-184, 1–13.


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(7) Sagir, M.; Tan, I. M.; Mushtaq, M.; Pervaiz, M.; Shahzad, K. CO2 Mobility Control Using CO2 Philic Surfactant for Enhanced Oil Recovery. J. Pet. Explor. Prod. Technol. 2015, 6 (3), 1–7. (8) Chang, S. H.; Owusu, L. A.; French, S. B.; Kovarik, F. S. The Effect of Microscopic Heterogeneity on CO2 -Foam Mobility: Part 2-Mechanistic Foam Simulation. In Proceedings of SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, April 22–25, 1990. (9) Yongmin, Z.; Yujun, F.; Yuejiao, W.; Xiangliang, L. CO2-Switchable Viscoelastic Fluids Based on a Pseudogemini Surfactant. Langmuir 2013, 29 (13), 4187–4192. (10) Kahrobaei, S.; Li, K.; Onnieu, S. V.; Farajzadeh, R. Effects of Compositional Variations on CO2 Foam Under Miscible Conditions. AIChE J. 2018, 64 (2), 758–764. (11) Talebian, S. H.; Sagir, M.; Mumtaz, M. An Integrated Property–Performance Analysis for CO2-Philic Foam-Assisted CO2-Enhanced Oil Recovery. Energy Fuels 2018, 32 (7), 7773– 7785. (12) Ranka, M.; Brown, P.; Hatton, T. A. Responsive Stabilization of Nanoparticles for Extreme Salinity and High-Temperature Reservoir Applications. ACS Appl. Mater. Interfaces 2015, 7 (35), 19651–19658. (13) Chen, Y.; Elhag, A. S.; Cui, L.; Worthen, A. J.; Reddy, P. P.; Noguera, J. A.; Ou, A. M.; Ma, K.; Puerto, M.; Hirasaki, G. J. CO2-in-Water Foam at Elevated Temperature and Salinity Stabilized with a Nonionic Surfactant with a High Degree of Ethoxylation. Ind. Eng. Chem. Res. 2015, 54 (16), 4252–4263.


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(14) Ge, J.; Yang, W. Surfactant Enhanced Oil Recovery in a High Temperature and High Salinity Carbonate Reservoir. J. Surfactants Deterg. 2015, 18 (6), 1043–1050. (15) Adkins, S. S.; Xi, C.; Isabel, C.; Enza, T.; Nguyen, Q. P.; Sanders, A. W.; Johnston, K. P. Morphology and Stability of CO2-in-Water Foams with Nonionic Hydrocarbon Surfactants. Langmuir 2010, 26 (8), 5335–5348. (16) Cai, H.; Fan, J.; Han, D.; Fan, Z.; Zhu, Y.; Hu, Z. Development of Large-Hydrophobe Betaine Surfactants for Chemical Enhanced Oil Recovery in Low/High Salinity Reservoirs. In Proceedings of SPE Kingdom of Saudi Arabia Technical Symposium & Exhibition, Dammam, Saudi Arabia, April 24–27, 2017. (17) Kalyanaraman, N.; Arnold, C.; Gupta, A.; Tsau, J. S.; Ghahfarokhi, R. B. Stability Improvement of CO2 Foam for Enhanced Oil-Recovery Applications Using Polyelectrolytes and Polyelectrolyte Complex Nanoparticles. J. Appl. Polym. Sci. 2016, 134 (6), 2–15.

(18) Alzobaidi, S.; Da, C.; Tran, V.; Prodanović, M.; Johnston, K. P. High Temperature Ultralow Water Content Carbon Dioxide-in-Water Foam Stabilized with Viscoelastic Zwitterionic Surfactants. J. Colloid Interface Sci. 2017, 488, 79–91. (19) Chang, D.; Alzobaidi, S.; Jian, G.; Zhang, L.; Biswal, S. L.; Hirasaki, G. J.; Johnston, K. P. Carbon Dioxide/Water Foams Stabilized with a Zwitterionic Surfactant at Temperatures up to 150 °C in High Salinity Brine. J. Pet. Sci. Eng. 2018, 166, 880–890. (20) Iwasaki, T.; Ogawa, M.; Esumi, K.; Meguro, K. Interactions between Betaine-Type Zwitterionic and Anionic Surfactants in Mixed Micelles. Langmuir 1991, 7 (1), 358–360.


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(21) Chorro, M.; Kamenka, N.; Faucompre, B.; Partyka, S.; Lindheimer, M.; Zana, R. Micellization and Adsorption of a Zwitterionic Surfactant: N-Dodecyl Betaine—Effect of Salt. Colloids Surf., A 1996, 110 (3), 249–261. (22) Talebian, S. H.; Mohd Tan, I.; Sagir, M.; Muhammad, M. Static and Dynamic Foam/Oil Interactions: Potential of CO2-Philic Surfactants as Mobility Control Agents. J. Pet. Sci. Eng. 2015, 135, 118–126. (23) Sagir, M.; Tan, I. M.; Mushtaq, M.; Ismail, L.; Azam, M. R. Synthesis of a New CO2 Philic Surfactant for Enhanced Oil Recovery Applications. J. Dispersion Sci. Technol. 2014, 35 (5), 647–654. (24) Ibrahim, A. F.; Nasr-El-Din, H. Stability Improvement of CO2 Foam for Enhanced Oil Recovery Applications Using Nanoparticles and Viscoelastic Surfactants. In Proceedings of SPE Trinidad and Tobago Section Energy Resources Conference, Port of Spain, Trinidad and Tobago, June 25–26, 2018; p 17. (25) Bonilla, L. F.; Shah, S. N. Experimental Investigation on the Rheology of Foams. In Proceedings of SPE/CERI Gas Technology Symposium, Calgary, Alberta, Canada, April 3–5, 2000; p 14. (26) Xiao, C.; Balasubramanian, S. N.; Clapp, L. W. Rheology of Viscous CO2 Foams Stabilized by Nanoparticles Under High Pressure. Ind. Eng. Chem. Res. 2017, 56 (29), 8340– 8348.


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(27) Chen, Z.; Zhao, X. Enhancing Heavy-Oil Recovery by Using Middle Carbon AlcoholEnhanced Waterflooding, Surfactant Flooding, and Foam Flooding. Energy Fuels 2015, 29 (4), 2153–2161. (28) Andrianov, A.; Farajzadeh, R.; Nick, M. M.; Talanana, M.; Zitha, P. L. J. Immiscible Foam for Enhancing Oil Recovery: Bulk and Porous Media Experiments. J. Ind. Eng. Chem. 2011, 51 (5), 2214–2226. (29) Dickson, J. L.; Psathas, P. A.; Salinas, B.; Ortiz-Estrada, C.; Luna-Barcenas, G.; Hwang, H. S.; Lim, K. T.; Johnston, K. P. Formation and Growth of Water-in-CO2 Miniemulsions. Langmuir 2003, 19 (12), 4895–4904. (30) Dhanuka, V. V.; Dickson, J. L.; Ryoo, W.; Johnston, K. P. High Internal Phase CO2-inWater Emulsions Stabilized with a Branched Nonionic Hydrocarbon Surfactant. J. Colloid Interface Sci. 2006, 298 (1), 406–418. (31) Wiebe, R. The Binary System Carbon Dioxide-Water Under Pressure. Chem. Rev. 1941, 29 (3), 475–481. (32) Cui, L.; Ma, K.; Puerto, M.; Abdala, A. A.; Tanakov, I.; Lu, L. J.; Chen, Y.; Elhag, A.; Johnston, K. P.; Biswal, S. L. Mobility of Ethomeen C12 and Carbon Dioxide (CO2) Foam at High Temperature/High Salinity and in Carbonate Cores. SPE J. 2016, 21 (4), 1–151. (33) Al-Qasim, A.; Alotaibi, F.; Kokal, S.; Zhou, X. CO2-Foam Rheology Behavior under Reservoir Conditions. In Proceedings of SPE Kingdom of Saudi Arabia Technical Symposium & Exhibition, Dammam, Saudi Arabia, April 24–27, 2017.


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(34) Zeng, Y.; Muthuswamy, A.; Ma, K.; Wang, L.; Hirasaki, G. J. Insights on Foam Transport from a Texture-Implicit Local-Equilibrium Model with an Improved Parameter Estimation Algorithm. Ind. Eng. Chem. Res. 2016, 55 (28), 7819–7829. (35) Meyssami, B.; Balaban, M. O.; Teixeira, A. A. Prediction of pH in Model Systems Pressurized with Carbon Dioxide. Biotechnol. Prog. 1992, 8 (2), 149–154. (36) Worthen, A. J.; Parikh, P. S.; Chen, Y.; Bryant, S. L.; Huh, C.; Johnston, K. P. Carbon Dioxide-in-Water Foams Stabilized with a Mixture of Nanoparticles and Surfactant for CO2 Storage and Utilization Applications. Energy Procedia 2014, 63, 7929–7938.

(37) Xue, Z.; Worthen, A.; Qajar, A.; Robert, I.; Bryant, S. L.; Huh, C.; Prodanović, M.; Johnston, K. P. Viscosity and Stability of Ultra-High Internal Phase CO2 -in-Water Foams Stabilized with Surfactants and Nanoparticles with or without Polyelectrolytes. J. Colloid Interface Sci. 2016, 461, 383–395. (38) Exerowa, D.; Kolarov, T.; Khristov, K. Direct Measurement of Disjoining Pressure in Black Foam Films. I. Films from an Ionic Surfactant. Colloids Surf. 1987, 22 (2), 161–169. (39) da Rocha, S. R. P.; Harrison, K. L.; Johnston, K. P. Effect of Surfactants on the Interfacial Tension and Emulsion Formation between Water and Carbon Dioxide. Langmuir 1999, 15 (2), 419–428. (40) Ryoo, W.; Dickson, J. L.; Dhanuka, V. V.; Webber, S. E.; Bonnecaze, R. T.; Johnston, K. P. Electrostatic Stabilization of Colloids in Carbon Dioxide: Electrophoresis and Dielectrophoresis. Langmuir 2005, 21 (13), 5914–5923.


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(41) Chen, Y.; Elhag, A. S.; Worthen, A. J.; Reddy, P. P.; Ou, A. M.; Hirasaki, G. J.; Nguyen, Q. P.; Biswal, S. L.; Johnston, K. P. High Temperature CO2-in-Water Foams Stabilized with Cationic Quaternary Ammonium Surfactants. J. Chem. Eng. Data 2016, 61 (8), 2761–2770.


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TOC GRAPHIC

Figure 20. Schematic representation of betaine surfactant adsorption at the gas-liquid interface with the increase in salt concentration. More surfactant molecules were adsorbed at the CO2-water interface in the presence of high salinity due to the screening of positively charged groups of surfactant. Greater surfactant adsorption provided large steric repulsion and raised the disjoining pressure between bubble films, thereby improving foam stability.


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TABLES Table 1. The Parameters of the Core Core

Cross-sectional area/cm2

Length/cm

Pore volume/cm3

Permeability/mD

Value

4.9

9.5

9.9

614


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Table 2. The Parameters of the Equations of the Fitted Curve between Drainage Liquid and Time, with Different Salinities Salinity/

Intercept

Slope

Adj. RSquare/%

Equation

2

-70.66

5.41

99.13

y = -47.00 + 5.41*x

5

-60.15

4.97

98.69

y = -60.15 + 4.97*x

10

-55.41

4.74

99.47

y = -55.41 + 4.74*x

15

-39.98

3.20

98.27

y = -39.98 + 3.20*x

20

-49.49

3.14

97.48

y = -49.49 + 3.14*x

25

-47.00

2.66

97.18

y = -47.00 + 2.66*x

104 mg·L-1


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Energy & Fuels

Table 3. The Parameters for Calculating Foam Average Size as a Function of Salinities Salinity/

u/10-6 m/s

φ

us/10-2 m/s

μc/mPa·s

r/um

2

1.13

0.82

7.49

0.38

126.43

5

1.04

0.82

7.32

0.41

128.22

10

0.98

0.81

6.19

0.46

122.34

15

0.74

0.81

3.71

0.5

97.15

20

0.67

0.81

3.26

0.56

94.98

25

0.55

0.81

2.55

0.67

90.14

104 mg·L-1


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Table 4. The Parameters of the Equation of the Fitted Curve between Shear Rate and Time with Different Salinities Salinity/

Intercept

Slope

Adj. RSquare/%

Equation

2

-0.998

0.36

99.93

y = -0.998 + 0.36*x

5

-1.05

0.40

99.83

y = -1.05+ 0.40*x

10

-1.07

0.44

98.88

y = -1.07 + 0.44*x

15

-1.24

0.49

99.37

y = -1.24 + 0.49*x

20

-1.23

0.50

99.01

y = -1.23 + 0.50*x

25

-1.76

0.68

99.71

y = -1.76 + 0.68*x

104 mg·L-1


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Energy & Fuels

Table 5. Power Law Equation of SC-CO2 Foams with Different Salinities Salinity/

n

Kˊ

K

Equation

2

0.363

0.369

0.323

τ=0.323γ-0.637

5

0.400

0.348

0.306

τ=0.306γ-0.600

10

0.441

0.343

0.303

τ=0.303γ-0.559

15

0.492

0.289

0.258

τ=0.258γ-0.508

20

0.501

0.293

0.262

τ=0.262γ-0.499

25

0.676

0.171

0.160

τ=0.160γ-0.324

104 mg·L-1


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FIGURES

Figure 1. Schematic diagram of the apparatus to evaluate foam stability.


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Figure 2. Film drainage process in the high-pressure view cell.


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Figure 3. Schematic diagram of the capillary viscometer apparatus.


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Figure 4. Schematic of the flow loop apparatus for evaluating foam dynamics and bubble texture at 70°C and 8 MPa.


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Figure 5. Schematic diagram of the apparatus for interfacial tension measurement.


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Figure 6. Foaming volume and half-life versus surfactant concentration at 70 °C and 8 MPa.


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Figure 7. Foaming volume and half-life as a function of salinity at 70°C and 8 MPa, when the HHSB concentration was 0.5%.


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Figure 8. Settling liquid volume as a function of time at 70°C and 8 MPa.


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Figure 9. Fit curves for the drainage volume as a function of time.


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Figure 10. Variation of viscosity and density of surfactant solutions with different salinities at 70°C and 8 MPa.


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100μm

Figure 11. The microstructure of SC-CO2 foam after stirring was stopped at 70°C and 8 MPa.


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Figure 12. Fit curves between the shear rate and apparent wall shear stress for SC-CO2 foams with different salinities.


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Figure 13. Apparent viscosity of SC-CO2 foam as a function of shear rate with different salinities in surfactant solutions.


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Figure 14. The resistance factor of SC-CO2 foams with different salinities.


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(b)

(a)

enlarged

100μm (c)

100 μm

Figure 15. Macrograph (a) and micrograph (b) of SC-CO2 foam in the high-pressure view cell at 70°C and 8 MPa, (c) CO2 foam at room temperature and atmospheric pressure.


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Energy & Fuels

(a)

(b)

100 μm

100 μm

(d)

(c)

100 μm

(e)

100 μm

(f)

100 μm

100 μm

Figure 16. Micrographs of SC-CO2 foam with a salinity of 5×104 mg/L at 70°C and 8 MPa at different times of (a) 10, (b) 20, (c) 30, (d) 40, (e) 50, and (f) 60 min.


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Page 48 of 53

(b)

(a)

100 μm

100 μm

(d)

(c)

100 μm

(e)

100 μm

(f)

100 μm

Figure 17. Micrographs of SC-CO2 foam with a salinity of 25×104 mg/L at 70°C and 8 MPa at different times of (a) 10, (b) 20, (c) 30, (d) 40, (e) 50, and (f) 60 min.


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Figure 18. Effect of salinity on IFT between CO2 and betaine surfactant when surfactant concentration was 0.5% at 70°C and 8 MPa.


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Figure 19. Variation of radius of curvature of the liquid drop with salinities at 70°C and 8 MPa.


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Energy & Fuels

Figure 20. Schematic representation of betaine surfactant adsorption at the gas-liquid interface with the increase in salt concentration.


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Figure 21. The interfacial tension between CO2 and surfactant solutions with different salinities, as a function of surfactant concentration at 70°C and 8 MPa.


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Energy & Fuels

Figure 22. The area per surfactant molecule at the interface (Am) and the molar concentration of surfactant per unit area (Γ) versus different salinities at 70°C and 8 MPa.


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Effect of Salinities on Supercritical CO2 Foam Stabilized by Betaine

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