Design of CO2-in-Water Foam Stabilized with Switchable Amine

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Design of CO-in-Water Foam Stabilized With Switchable Amine Surfactants at High Temperature in High Salinity Brine and Effect of Oil Chang Da, Guoqing Jian, Shehab Alzobaidi, Jonathan Heesoo Yang, Sibani Lisa Biswal, George J Hirasaki, and Keith P. Johnston Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b02959 • Publication Date (Web): 13 Nov 2018 Downloaded from http://pubs.acs.org on November 17, 2018

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Page |1

Design of CO2-in-Water Foam Stabilized With Switchable Amine Surfactants at High Temperature in High Salinity Brine and Effect of Oil Chang Da1, Guoqing Jian2, Shehab Alzobaidi1, Jonathan Yang1, Sibani L. Biswal2, George J. Hirasaki2 and Keith P. Johnston1* 1

McKetta Department of Chemical Engineering, the University of Texas at Austin 2

Department of Chemical and Biomolecular Engineering, Rice University

ABSTRACT The design of surfactants for CO2-in-water (C/W) foams in carbonate reservoirs above 100 °C has been limited by thermal instability of surfactants, surfactant adsorption to mineral surfaces and challenges in generating and stabilizing the foams. Here, we have identified an diamine surfactant, C12-14N(CH3)C3N(CH3)2 (Duomeen CTM), with good thermal stability (> 1 month at 135 °C), that stabilizes viscous C/W foam with an apparent viscosity up to ~35 cP at 120 °C in 22% total dissolved solids (TDS) brine. Strong foams with excessively high viscosity were reported to be generated with longer-tailed C16-18N(CH3)C3N(CH3)2 (Duomeen TTM) that formed a viscoelastic aqueous phase. Here the tail length was shorter for C12-14N(CH3)C3N(CH3)2 and thus a viscoelastic aqueous phase was not formed, resulting in a weaker CO2 foam with a more appropriate viscosity for the proposed applications. Moreover, at the lowest superficial velocity studied (4 ft/day), the apparent viscosity for C12-14N(CH3)C3N(CH3)2 was ~20 fold lower than that of C16-18N(CH3)C3N(CH3)2, consistent with the lower viscosity for the aqueous phase. Not only was the foam viscosity with C12-14N(CH3)C3N(CH3)2 high enough for CO2 mobility control in enhanced oil recovery, but it was low enough to be more favorable with regard to the injection

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Page |2 pressure than the excessively high flow resistance associated with C16-18N(CH3)C3N(CH3)2. In addition, viscous C/W foam were maintained at low fractions of dodecane (model oil) and broke in the presence of large fractions of dodecane, both of which are beneficial to EOR. The oil/water (O/W) emulsions formed with C12-14N(CH3)C3N(CH3)2 were unstable and broke in 30 min, and the O/W partition coefficient depended greatly on pH at 120 °C in 22% TDS brine. All of these factors suggest that the surfactant C12-14N(CH3)C3N(CH3)2 is a good candidate for further evaluation and scale up for CO2 EOR, CO2 sequestration and hydraulic fracturing at high salinities and temperatures.

INTRODUCTION The production of oil in carbon dioxide enhanced oil recovery (CO2 EOR) can be improved by generating foams to produce a more uniform CO2/oil displacement front. This mobility control may be used to mitigate gravity override and viscous fingering through the reservoir 1. Furthermore, CO2 may be stored during EOR in geological reservoirs to reduce greenhouse gas emissions2. However, the recovery efficiency of CO2 EOR has been limited by the properties of CO2 and reservoir heterogeneity3, 4. Moreover, reservoir heterogeneity induces CO2 to pass through the more permeable layers in reservoirs instead of less permeable layers that contain more recoverable oil, resulting in early gas breakthrough5. To address gravity override and viscous fingering, mobility control of CO2 using foams was proposed nearly 40 years ago6-8. Many types of amphiphiles, such as surfactants9-12, nanoparticles13-16 and polymers4, 17-19, have been proved to effectively stabilize CO2 foams. Foams stabilized with surfactants usually have an apparent viscosity several orders of magnitude higher than that of pure gases and thus reduce viscous fingering1. Furthermore, the rheological behavior of the foam could mitigate the effect of reservoir heterogeneity by the generation of strong flow resistance in high permeable layers to divert more CO2 into low permeable regions20-23. Another role of a surfactant is to lower the interfacial tension (IFT) between CO2 and water, and stabilize


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Page |3 lamellae that separate dispersed CO2 droplets in the foam24. However, very few currently used surfactants are thermally stable for high temperatures above 100 °C. The design of appropriate surfactants (or formulations) for high temperature (above 100 °C) and high salinity reservoirs (> 20% TDS brine) is very challenging due to various limitations. First, solubility of surfactants in aqueous phase is significantly reduced under high temperature and salinity conditions. For example, many nonionic surfactants precipitate in an aqueous phase at elevated temperatures due to weaker hydrogen bonds formed with water25, 26. Secondly, many surfactants undergo thermal degradation over long time, which makes the injection of surfactants uneconomic. For example, Hoffman elimination may take place for quaternary amines at elevated temperatures and form tertiary amines27, 28. Furthermore, a low surfactant oil/water (O/W) partition coefficient is desired for EOR applications to prevent loss of surfactant to the oil phase29. Finally, only nonionic and cationic surfactants have low adsorption on positively carbonate surfaces, which is essential to minimize surfactant loss30, 31. A number of challenges have limited the generation and stabilization of successful foams for limestone reservoirs at high temperatures and salinity. To overcome the capillary pressure and mobilize foam lamellae in the pore throats the pressure gradient must be above the minimum pressure gradient (MPG) as shown in Eqn 1, 𝑀𝑃𝐺 ∝

𝛾∅ 𝑘

(Eqn 1)

where  is the interfacial tension,  the porosity and k the permeability32, 33. Below this pressure gradient, gas may flow as a continuous phase without generating strong foam32. For foams with a high MPG, limited lamellae mobilization may fail to generate strong foam in low permeability regions. Moreover, at high temperatures, foams are destabilized by faster drainage of the lamella between gas bubbles due to the reduced viscosity of the aqueous phase34, 35. Destabilization mechanisms including coalescence and Ostwald ripening may prevail as the foam lamella


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Page |4 become thinner34. Furthermore, the surfactant should be able to stabilize viscous C/W foam when in contact with low oil fractions, resembling the case of residual oil in the reservoir; on the other hand, the foam should break when encountering large fractions of oil at the sweeping front for more desirable oil production17, 36, 37. Recently, several surfactants including amine surfactants, Ethomeen C/12 (C12-14H2529N(C2H4OH)2)

1, 38-40

, Duomeen TTM (C16-18H33-37N(CH3)(C3H6)N(CH3)2)41, 42 and the zwitterionic

surfactant cetyl betaine (CH3(CH2)15N+(CH3)2CH2COO-)43, were shown to generate viscous C/W foam at high temperature and salinity conditions with limestone sandpacks and cores. The first two surfactants are switchable from the nonionic (unprotonated amine) state to cationic (protonated amine) state when dissolved in an aqueous phase under acidic pH conditions29, 42, 44, as shown in Figure 1. At temperatures up to 120 °C, C12-14N(EO)2 was shown to generate foam 50 times more viscous foam than the CO2–brine mixture fluid29. Moreover, the surfactant was shown to stabilize C/W foams and not oil/water (O/W) emulsions, which beneﬁcial in CO2 EOR45. However, the MPG of this surfactant was relatively high1 and the ethoxylated amine group may undergo thermal degradation after several weeks. On the other hand, the formation of viscous wormlike micelles with C16-18N(CH3)C3N(CH3)2 in the aqueous phase did not only lower the MPG for a C/W foam, but also strengthened the lamella against drainage, coalescence and Ostwald ripening, thus providing long-term foam stability42. However, if the foam generated with C1618N(CH3)C3N(CH3)2

becomes too viscous, it may make the injection pressure excessive in

reservoir applications46, 47. In the case of cetyl betaine, the zwitterionic charge made the surfactant insensitive to salinity or pH, and thermal degradation was not observed at 135 °C for up to 30 days43. Furthermore, it stabilized viscous foam at high temperature up to 120 °C and the MPG was low. However, its relatively high adsorption on limestone may limit its applicability in the field43.


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Page |5 The main objective of this study is to show that a newly designed switchable amine surfactant, Duomeen CTM (C12-14N(CH3)C3N(CH3)2), with long-term thermal stability (at 135 °C), stabilizes strong C/W foams at high temperature (up to 120 °C) and high salinity (up to 22% TDS). However, the foam was designed to be weaker than for C16-18N(CH3)C3N(CH3)2 such that the required pressure gradient for injectivity into reservoirs is more practical. The rheological properties of the aqueous solutions with both surfactants are measured as a function of shear rate. The foam stabilization mechanisms are described as functions of foam quality in a 22-Darcy limestone pack. Furthermore, the shear thinning effect on foam viscosity is studied and a MPG for foam generation was estimated in a 0.8-Darcy glass beadpack. The thermal stability of this surfactant was also demonstrated after 30 days of incubation at 135 °C, from concentration measurements with liquid chromatography/mass spectrometry (LC/MS). Moreover, the oil effects on both phase behaviour and foam apparent viscosity were studied with dodecane as a model oil. The major hypothesis was that with further modifications on switchable cationic surfactants with tertiary amine groups, for example C16-18N(CH3)C3N(CH3)2, surfactant aggregates made of wormlike micelles may be reduced for favourable field applications, while high C/W foam viscosity and low MPG are maintained. The advantage of C12-14N(CH3)C3N(CH3)2 to stabilize viscous C/W foam while maintain low aqueous phase viscosity and MPG can be of great benefit to the CO 2 mobility control and EOR in carbonate reservoirs with extremely high temperature and salinity conditions.

EXPERIMENTAL METHODS Materials The surfactants Ethomeen C/12 (Bis (2-hydroxyethyl cocoalkylamine), Duomeen TTM (N,N,N' trimethyl-N'-tallow-1,3- diaminopropane) and Duomeen CTM (N,N,N' trimethyl-N'-coco1,3- diaminopropane) were gifts from Akzo Nobel. All surfactants were used as received. The structures and compositions of the surfactants are shown in Table 1.


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Page |6 Carbon dioxide (99.99%) was provided by Matheson and used as is. Sodium chloride (NaCl, certified ACS), magnesium chloride hexahydrate (MgCl2·6H2O, certified ACS), and hydrochloric acid (HCl, technical) were purchased from Fisher. Calcium chloride dehydrates (CaCl2·2H2O, >99%) was purchased from Sigma-Aldrich. All chemicals were used as received. A synthetic brine with 22% TDS was prepared with 182 g/L NaCl, 77 g/L CaCl2∙2H2O, 26 g/L MgCl2∙6H2O in DI water to model the composition of the reservoir brine. Crushed limestone was purchased from Franklin Industrial Minerals and the average grain diameter was selected between 420 – 840 μm by sieving with 20-40 mesh sieves. Spherical glass beads were purchased from Polysciences with an average diameter of 30-50 μm. The glass beads were washed several times with water and ethanol to remove the impurities. Dodecane (99%) was purchased from Acros Organic and used as received. Aqueous phase viscosity measurements Aqueous phase viscosities versus shear rate at steady state and ambient condition (25°C and 1 atm) for aqueous solutions of 1 wt% surfactant dissolved in 22% TDS reservoir brine were measured with an AR G2 rotational rheometer (TA Instruments) equipped with a cone-and-plate geometry (40 mm, 2°), with a procedure similar to our previous publications41, 42. 1 N HCl was used to adjust the pH of the aqueous phase solution. Aqueous phase viscosity measurements were determined with a shear rate range from 0.2 s-1 to 200 s-1, since the rheometer was not very sensitive at ultra-low shear rates. C/W foam apparent viscosity measurements in porous media A schematic for the experimental set-up used to measure the foam apparent viscosity up to 120 °C and 3400 psia is shown in Figure 2. The packed bed used and the experimental procedure for foam apparent viscosity measurements was similar to those in previous publications29, 42, 43. The foam quality was defined as the volumetric fraction of the CO2 phase in


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Page |7 foams. The pressure drop across the packed bed was recorded and the foam apparent viscosity was calculated based on Darcy’s law, as shown in Eqn 2, 𝜇𝑎𝑝𝑝 =

𝑘∆𝑃𝐴 𝑞𝐿

(Eqn 2)

where 𝜇𝑎𝑝𝑝 is the foam apparent viscosity, ∆𝑃 is the pressure across the packed bed, 𝐴 is the cross-sectional area, 𝑘 is the permeability, 𝐿 is the length of the packed bed and 𝑞 is the total volumetric flow rate. The bulk foam viscosity was calculated from pressure drop across the capillary tube, based on the Hagen-Poiseuille equation. The oil effect on foam generation and apparent viscosity was also studied with the same equipment as shown above in Figure 2, and the procedure was similar to that mentioned above. Here we used dodecane as the model oil and varied the oil (dodecane) fraction in the nonaqueous phase, which was defined as 𝑉𝑜𝑖𝑙 /(𝑉𝑜𝑖𝑙 + 𝑉𝐶𝑂2 ), while maintaining the overall volume fraction of the aqueous phase as a constant (10%). Surfactant thermal stability study with liquid chromatography mass spectrometry (LC/MS) The detailed procedure of preparing surfactant samples with addition of Na2SO3 as the oxygen scavenger to prevent oxidation has been reported in previous publications41,

43

. The

surfactant sample was loaded in thick-wall high-pressure glass pipettes (Ace Glass #8648-12) and incubated in an oven at 135 °C, while a reference sample was stored at room temperature. After 30 days, both samples were diluted to 0.1 mg/L and fed into the LC/MS system (Agilent 6100 Series) for concentration analysis. The ionization method used in the LC/MS was Electrospray Ionization (ESI); 1 mL surfactant solution was injected. Static oil/water (O/W) emulsion stability Dodecane was used as a model oil to mimic the behavior of light hydrocarbons in reservoirs. An oil-soluble, water-insoluble red dye, oil red EGN (Sigma Aldrich) was used for visual


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Page |8 differentiation of the (red) oil phase and the colorless aqueous phase. At an equal volumetric ratio, 1 wt% surfactant in 22% TDS brine was mixed with dodecane. The O/W emulsion was generated with a high-speed homogenizer (IKA T25 basic ULTRA-TURRAX®) at a speed of 6500 rpm for 2 min to provide a relatively high shear condition. Emulsions were incubated in an oven at 120 °C and images were taken over 2 hours to trace the separation behavior. O/W partition coefficient measurements The samples were prepared similarly to the procedure shown in the section above, but the pH was varied from 2 to 7. After the O/W emulsions broke into two distinct phases, sample were taken from the lower-layer aqueous phase containing the surfactant and diluted 100 times. Surfactant solution in brine was also diluted over various concentrations (0.001-0.1mg/mL) as the standards for calibration. The concentration of surfactants remaining in the aqueous phase was measured with the LC/MS system (Agilent 6100 Series). The ionization method and injection volume were set the same as described before. The concentration of the surfactant resided in aqueous phase was calculated based on the linear extrapolation of the standards and thus the amount partitioned into oil phase was obtained. The O/W partition coefficient was defined as the weight fraction of surfactant in the oil over that in water29, 48.

RESULTS AND DISCUSSION Aqueous phase viscosity of 1 wt% C12-14N(CH3)C3N(CH3)2 in 22% TDS brine Similar to C16-18N(CH3)C3N(CH3)2, C12-14N(CH3)C3N(CH3)2 is a switchable amine surfactant, which will be protonated at lower pH conditions and thus achieve higher solubility in aqueous phase. The surfactant was soluble at concentrations of 1 wt% in 22% TDS at pH below 7. The viscosity of an aqueous phase with 1 wt% C12-14N(CH3)C3N(CH3)2 in 22% TDS brine as a function of shear rates is shown in Figure 3 at ambient temperature and pressure. At a shear rate of 1 s-1, the aqueous phase viscosity was ~6 cP indicating that assemblies such as viscoelastic


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Page |9 wormlike micelles were not formed. On the contrary, the aqueous phase viscosity of C1618N(CH3)C3N(CH3)2

in 22% TDS was ~600 cP at this shear rate and concentration, given the

formation of worm-like micelles given the reduced curvature produced by the relatively long tail length. The packing parameter 𝑝 is defined as, 𝑝 = 𝑣 ⁄𝑎0 𝑙𝑐

(Eqn 3)

In which 𝑣 is the volume occupied by surfactant tail, 𝑙𝑐 is the length of surfactant tail and 𝑎0 is the area of the head group

49, 50

. A relatively large volume of hydrocarbon tail and small headgroup

for C16-18N(CH3)C3N(CH3)2 result in a high packing parameter, which may lead to the formation of wormlike micelles51, 52. Thus, the injectivity of an aqueous surfactant solution may be expected to be improved for C12-14N(CH3)C3N(CH3)2 with a smaller pressure drop46. Shear thinning behaviour was observed starting from 0.2 s-1 to 2.5 s-1. At higher shear rate, the solution became Newtonian with a viscosity of 1.8 cP. C/W foam viscosity of C12-14N(CH3)C3N(CH3)2 at 120 °C C12-14N(CH3)C3N(CH3)2 and C16-18N(CH3)C3N(CH3)2 both stabilized viscous C/W foam apparent viscosities at 120 °C and 3400 psig in the carbonate sandpack are shown in Figure 4. The apparent viscosity of the C/W foam stabilized by C12-14N(CH3)C3N(CH3)2 increased with elevating foam quality and reached 35 cP at a foam quality of 95%. The foam was still viscous (~25 cP) at an ultra-high foam quality of 98%. The foam generated with C16-18N(CH3)C3N(CH3)2 totally collapsed at a foam quality of 98%, despite higher aqueous phase viscosities. These initial sandpack foam apparent viscosities tests showed potential for using C12-14N(CH3)C3N(CH3)2 in CO2 EOR given the values of the apparent viscosities. The bulk foam viscosity measured in capillary tube were demonstrated in the supporting information (Figure S1), which was comparable to those in porous media. The foam viscosity was also shown as functions of surfactant concentration and brine salinity in the supporting information (Figure S2 and S3).


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P a g e | 10 The increasing foam apparent viscosity with quality up to 0.95 and the fact of foam apparent viscosity of C12-14N(CH3)C3N(CH3)2 was lower than that of C16-18N(CH3)C3N(CH3)2 at all foam qualities below 98% could be explained by the smooth capillary model for foam flow in a natural porous media proposed by Hirasaki and Lawson.32 Here, the porous media is modeled by numerous small capillaries in parallel with inner diameters smaller than that of the foam bubbles, where the apparent viscosity of foam relative to the external phase viscosity is given by 1

1

(𝑛𝐿 𝑅) 3𝜇𝑒 𝑈 −3 𝑟 (1 − 𝑒 −𝑁𝐿 ) 𝜇𝑎𝑝𝑝 3𝜇𝑒 𝑈 −3 2 = 𝐿𝑠 𝑛𝐿 + 0.85 𝑟 ( ) [( ⁄𝑅 ) + 1] + (𝑛𝐿 𝑅) ( ) √𝑁𝑠 (1 + 𝑒 −𝑁𝐿 ) 𝜇𝑒 𝛾 𝛾 ( ⁄𝑅)

(Eqn 4)

where 𝜇𝑒 is the viscosity of the continuous (aqueous) phase, 𝐿𝑠 is the length of foam slugs, 𝑛𝐿 is density of foam lamella, Rc is the radius of capillaries, rc is the radius of curvature of gas-liquid interface, U is the velocity of the flowing foam, Ns is a dimensionless number for IFT gradient effect, and NL is a dimensionless number for bubble length.32 From this equation, the foam apparent viscosity is proportional to the viscosity of continuous aqueous phase. At a shear rate of 600 s-1 similar to that used in foam experiments, the aqueous phase viscosity of 1 wt% C1214N(CH3)C3N(CH3)2

in 22% TDS brine was ~3 cP, while that of C16-18N(CH3)C3N(CH3)2 was ~6 cP

(shown in Figure S4 in the supporting information). Thus, the foam stabilized with C1214N(CH3)C3N(CH3)2

was expected to be less viscous than that stabilized with C16-

18N(CH3)C3N(CH3)2,

based on a less viscous continuous phase as the wormlike micelles are mot

formed with C12-14N(CH3)C3N(CH3)2. A schematic demonstrating spherical and wormlike micelles the foam lamella was shown in Figure S5 in the supporting information. Moreover, before reaching the critical foam quality, an increase in foam quality leads to more lamellae per unit length thus a higher lamella density 𝑛𝐿 , resulting in an increasing apparent viscosity. In addition, the decrease of foam viscosity as foam quality increases from 0.95 to 0.98 can be explained by the increased capillary pressure (𝑃𝑐 ), which is pressure difference between the highly curved plateau border and the flat foam film as described in Eqn 553


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P a g e | 11 𝑃𝑐 = 𝛾⁄𝑅(1 − ∅i )0.5

(Eqn 5)

where 𝑅 is the film radius and ∅i is the foam quality. At an elevated ∅i of 0.98 the capillary pressure becomes extremely high such that the lamellar films rapidly thin under drainage and become vulnerable to coalescence and Ostwald ripening, resulting in an increased R and a decreased app54-56. However, the situations with extremely high foam quality are not much relevant to most applications in EOR. Effect of superficial velocity on C/W foam generation and apparent viscosity in a 0.8Darcy glass beadpack The effect of superficial velocity on C/W foam viscosity for C12-14N(CH3)C3N(CH3)2 (Figure 5) is compared to those for C12-14N(EO)2 and C16-18N(CH3)C3N(CH3)2. Foam stabilized with C12-14N(CH3)C3N(CH3)2 was generated at a superficial velocity as low as 4 ft/day with an apparent viscosity >40 cP. In contrast, with C12-14N(EO)2 foam was not generated until the superficial velocity reached 20 ft/day.1,

29

Thus C12-14N(CH3)C3N(CH3)2 is preferred for CO2

mobility control in actual reservoirs since viscous foam could be generated at extremely lower velocities which may be encountered in areas deep in the reservoirs and away from the well bore. On the other hand, although similar MPGs were approximated for C12-14N(CH3)C3N(CH3)2 and C16-18N(CH3)C3N(CH3)2 the apparent viscosity was only 30 cP for C12-14N(CH3)C3N(CH3)2 compared to >600 cP for C16-18N(CH3)C3N(CH3)2 at a superficial velocity of 4 ft/day. The foam apparent viscosity was ~20 fold lower with C12-14N(CH3)C3N(CH3)2 compared to C1618N(CH3)C3N(CH3)2 at

a level that is sufficient for EOR. Furthermore, the lower injection pressure

associated with the lower pressure drop would be highly beneficial. Beyond the maximum viscosity, shear-thinning behavior was observed for all the three surfactants, as the foam apparent viscosity decreased with increasing superficial velocity. The shear-thinning behavior could also be explained by the model of Hirasaki and Lawson32, as


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P a g e | 12 shown in Eqn 4 above. As a foam bubble passes through a single capillary with increasing velocity, the liquid film between the bubble and the capillary wall thickens, which changes the bubble curvatures and increases the pressure drop across the capillary57. According to their model, the pressure drop increases with an exponent of 2/3 on the gas velocity (𝑈)57, which leads to a foam apparent viscosity (𝜇𝑎𝑝𝑝 ) increase with the -1/3 power of 𝑈 (shown in Eqn 4 as the second term on the right side) and thus the shear-thinning effect. Moreover, Falls et al. added another contribution to account for the constriction in porous media and changed the exponent of 𝜇𝑎𝑝𝑝 on 𝑈 to -2/3. The results in Figure 5 showed a relationship between 𝜇𝑓𝑜𝑎𝑚 and 𝑈 developed from experiments, and the exponent was found to be around -0.69 for C1618N(CH3)C3N(CH3)2,

-0.69 for C12-14N(EO)2 and -0.55 for C12-14N(CH3)C3N(CH3)2. Thus we can tell

that the experimental exponents with all surfactants fit close to the Falls model. In addition, as foam bubbles pass through the capillary, surfactants are forced and expelled to the rear side of the bubbles, resulting in an interfacial tension gradient which prevents the moving of foam bubbles as the result of the Gibbs-Marangoni effect58. The IFT contribution (𝛾) to 𝜇𝑎𝑝𝑝 is also proportional to the -1/3 power of 𝑈 (shown in Eqn 4 as the third term on the right side). Effect of oil (dodecane) fraction on foam apparent viscosity Figure 6 showed the effect of model oil on the foam viscosity in porous media. As mentioned above, we used a constant volume fraction of the aqueous phase (10%) and then varied the dodecane (model oil) fraction in the non-aqueous phase, which was defined as 𝑉𝑜𝑖𝑙 /(𝑉𝑜𝑖𝑙 + 𝑉𝐶𝑂2 ). Under the reservoir condition of 120 °C and 3400 psia as mentioned above, dodecane is miscible with CO2 in all proportions as the non-aqueous phase, as shown in a previous study45. Other studies showed that n-alkanes with longer hydrocarbon chains (for example hexadecane) have minimum miscibility pressure (MMP) lower than 3400 psia at 120 °C59, 60

, proving miscibility of dodecane with CO2 at this conditions. , Foam viscosity decreased from

25 cP to 13 cP as the oil fraction increased from 0 to 60%. Furthermore, when the non-aqueous


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P a g e | 13 phase was composed of pure dodecane (absence of CO2), the viscosity of the O/W mixture was 40 cP at 120 °C and 3400 psia, more than an order of magnitude lower than for C16-18N(CH3)C3N(CH3)2. The lower foam viscosity is due in part to a lower aqueous phase viscosity, given the fact that shorter tails favor spherical micelles rather than the entangled wormlike micelles produced with the C16-18 tails. This lower apparent viscosity may be expected to be advantageous for lower injectivity in reservoir applications. The surfactant stabilized viscous C/W foam at low dodecane fractions, which is analogous to the situation with a small amount of residual oil in a reservoir; on the other hand, the foam broke when in contact with large fractions of dodecane, which is also preferred in CO2 EOR. The C12-14N(CH3)C3N(CH3)2 surfactant satisfied other key criteria, that it was thermally stable at temperatures up to 135 °C for one month, and the O/W emulsions formed with the surfactant were unstable and broke in 30 min. The O/W partition coefficient of switchable surfactant C1214N(CH3)C3N(CH3)2 was

very sensitive to pH, and became very low under acidic environments at

reservoir conditions. All of these factors suggest that the surfactant C12-14N(CH3)C3N(CH3)2 is a good candidate for various practical applications including CO2 EOR, CO2 sequestration and hydraulic fracturing at high temperatures and salinities. ACKNOWLEDGMENT This work was supported by the Abu Dhabi National Oil Company and the Welch Foundation F1319. We thank Prof. Kishore Mohanty and Dr. Krishna Panthi for the training and assistance on the rotational rheometer at the University of Texas in Austin. CONFLICT OF INTEREST The authors declare no competing interests.


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Energy & Fuels

P a g e | 17 References 1. Cui, L.; Ma, K.; Puerto, M.; Abdala, A. A.; Tanakov, I.; Lu, L. J.; Chen, Y.; Elhag, A.; Johnston, K. P.; Biswal, S. L.; Hirasaki, G., Mobility of Ethomeen C12 and Carbon Dioxide (CO2) Foam at High Temperature/High Salinity and in Carbonate Cores. SPE Journal 2016, 21, (04), 1151-1163. 2. Damen, K.; Faaij, A.; Turkenburg, W., Health, Safety and Environmental Risks of Underground Co2 Storage – Overview of Mechanisms and Current Knowledge. Climatic Change 2006, 74, (1), 289-318. 3. Enick, R. M.; Olsen, D. K.; Ammer, J. R.; Schuller, W. In Mobility and Conformance Control for CO2 EOR via Thickeners, Foams, and Gels--A Literature Review of 40 Years of Research and Pilot Tests, SPE improved oil recovery symposium, 2012; Society of Petroleum Engineers: 2012. 4. Alzobaidi, S.; Lee, J.; Jiries, S.; Da, C.; Harris, J.; Keene, K.; Rodriguez, G.; Beckman, E.; Perry, R.; Johnston, K. P., Carbon dioxide-in-oil emulsions stabilized with silicone-alkyl surfactants for waterless hydraulic fracturing. Journal of Colloid and Interface Science 2018, 526, 253-267. 5. Lake, L. W., Enhanced oil recovery. 6. Holm, L., Foam injection test in the Siggins field, Illinois. Journal of Petroleum Technology 1970, 22, (12), 1,499-1,506. 7. Lawson, J. B., The Adsorption Of Non-Ionic And Anionic Surfactants On Sandstone And Carbonate. In Society of Petroleum Engineers. 8. Li, R. F.; Yan, W.; Liu, S. H.; Hirasaki, G. J.; Miller, C. A., Foam Mobility Control for Surfactant Enhanced Oil Recovery. SPE Journal 2010, 15, (4), 934-948. 9. Zeng, Y.; Muthuswamy, A.; Ma, K.; Wang, L.; Farajzadeh, R.; Puerto, M.; Vincent-Bonnieu, S.; Eftekhari, A. A.; Wang, Y.; Da, C.; Joyce, J. C.; Biswal, S. L.; Hirasaki, G. J., Insights on Foam Transport from a Texture-Implicit Local-Equilibrium Model with an Improved Parameter Estimation Algorithm. Industrial & Engineering Chemistry Research 2016, 55, (28), 7819-7829. 10. Andrianov, A.; Farajzadeh, R.; Mahmoodi Nick, M.; Talanana, M.; Zitha, P. L. J., Immiscible Foam for Enhancing Oil Recovery: Bulk and Porous Media Experiments. Industrial & Engineering Chemistry Research 2012, 51, (5), 2214-2226. 11. Farajzadeh, R.; Barati, A.; Delil, H. A.; Bruining, J.; Zitha, P. L., Mass transfer of CO2 into water and surfactant solutions. Petroleum Science and Technology 2007, 25, (12), 1493-1511. 12. Farajzadeh, R.; Vincent-Bonnieu, S.; Bourada Bourada, N., Effect of Gas Permeability and Solubility on Foam. Journal of Soft Matter 2014, 2014, 7. 13. AlYousef, Z.; Almobarky, M.; Schechter, D., Enhancing the Stability of Foam by the Use of Nanoparticles. Energy & Fuels 2017, 31, (10), 10620-10627. 14. Alzobaidi, S.; Lotfollahi, M.; Kim, I.; Johnston, K. P.; DiCarlo, D. A., Carbon Dioxide-in-Brine Foams at High Temperatures and Extreme Salinities Stabilized with Silica Nanoparticles. Energy & Fuels 2017, 31, (10), 10680-10690. 15. Singh, R.; Mohanty, K. K. In Nanoparticle-Stabilized Foams for High-Temperature, High-Salinity Oil Reservoirs, SPE Annual Technical Conference and Exhibition, 2017; Society of Petroleum Engineers: 2017. 16. 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. Journal of colloid and interface science 2016, 461, 383395. 17. Jian, G.; Hou, Q.; Zhu, Y., Stability of Polymer and Surfactant Mixture Enhanced Foams in the Presence of Oil Under Static and Dynamic Conditions. Journal of Dispersion Science and Technology 2015, 36, (4), 477-488. 18. Johnston, K. P.; Rocha, S. R. P. d., Colloids in supercritical fluids over the last 20 years and future directions. The Journal of Supercritical Fluids 2009, 47, (3), 523-530.


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Energy & Fuels

P a g e | 19 36. 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. Advances in colloid and interface science 2012, 183–184, 1-13. 37. Farajzadeh, R.; Andrianov, A.; Krastev, R.; Hirasaki, G.; Rossen, W. R., Foam–oil interaction in porous media: implications for foam assisted enhanced oil recovery. Advances in colloid and interface science 2012, 183, 1-13. 38. Burnstock, A.; White, R., A preliminary assessment of the agingidegradation of Ethomeen c-12 residues from solvent gel formulations and their potential for inducing changes in resinous paint media. Studies in Conservation 2000, 45, (sup1), 34-38. 39. Jin, F.; Liu, Z.; Pu, W.; Zhong, D.; Yuan, C.; Wei, B., Experimental Study of In-Situ CO2 Foam Technique and Application in Yangsanmu Oilfield. Journal of Surfactants and Detergents 2016, 19, (6), 1231-1240. 40. AlSumaiti, A. M.; Hashmet, M. R.; AlAmeri, W. S.; Anto-Darkwah, E., Laboratory Study of CO2 Foam Flooding in High Temperature, High Salinity Carbonate Reservoirs Using Co-injection Technique. Energy & Fuels 2017. 41. Da, C.; Elhag, A.; Jian, G.; Zhang, L.; Alzobaidi, S.; Zhang, X.; Al Sumaiti, A.; Biswal, S.; Hirasaki, G.; Johnston, K. In CO 2/Water Foams Stabilized with Cationic or Zwitterionic Surfactants at Temperatures up to 120° C in High Salinity Brine, SPE Annual Technical Conference and Exhibition, 2018; Society of Petroleum Engineers: 2018. 42. Elhag, A. S.; Da, C.; Chen, Y.; Mukherjee, N.; Noguera, J. A.; Alzobaidi, S.; Reddy, P. P.; AlSumaiti, A. M.; Hirasaki, G. J.; Biswal, S. L.; Nguyen, Q. P.; Johnston, K. P., Viscoelastic diamine surfactant for stable carbon dioxide/water foams over a wide range in salinity and temperature. Journal of Colloid and Interface Science 2018. 43. Da, C.; Alzobaidi, S.; Jian, G. Q.; Zhang, L. L.; Biswal, S. L.; Hirasaki, G. J.; Johnston, K. P., Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 degrees C in high salinity brine. Journal of Petroleum Science and Engineering 2018, 166, 880-890. 44. Chen, Y.; Elhag, A. S.; Poon, B. M.; Cui, L.; Ma, K.; Liao, S. Y.; Reddy, P. P.; Worthen, A. J.; Hirasaki, G. J.; Nguyen, Q. P., Switchable nonionic to cationic ethoxylated amine surfactants for CO2 enhanced oil recovery in high-temperature, high-salinity carbonate reservoirs. SPE Journal 2014, 19, (02), 249-259. 45. Chen, H.; Elhag, A. S.; Chen, Y.; Noguera, J. A.; AlSumaiti, A. M.; Hirasaki, G. J.; Nguyen, Q. P.; Biswal, S. L.; Yang, S.; Johnston, K. P., Oil effect on CO 2 foam stabilized by a switchable amine surfactant at high temperature and high salinity. Fuel 2018, 227, 247-255. 46. Lee, K.; Huh, C.; Sharma, M. M. In Impact of fractures growth on well injectivity and reservoir sweep during waterflood and chemical EOR processes, SPE Annual Technical Conference and Exhibition, 2011; Society of Petroleum Engineers: 2011. 47. Turta, A. T.; Singhal, A. K., Field foam applications in enhanced oil recovery projects: screening and design aspects. Journal of Canadian Petroleum Technology 2002, 41, (10). 48. Zeng, Y.; Ma, K.; Farajzadeh, R.; Puerto, M.; Biswal, S. L.; Hirasaki, G. J., Effect of Surfactant Partitioning Between Gaseous Phase and Aqueous Phase on $$\hbox {CO}_{2}$$ CO 2 Foam Transport for Enhanced Oil Recovery. Transport in Porous Media 2016, 114, (3), 777-793. 49. Yang, J., Viscoelastic wormlike micelles and their applications. Current opinion in colloid & interface science 2002, 7, (5), 276-281. 50. Zana, R.; Kaler, E. W., Giant micelles: properties and applications. CRC Press: 2007; Vol. 140. 51. Christov, N. C.; Denkov, N. D.; Kralchevsky, P. A.; Ananthapadmanabhan, K. P.; Lips, A., Synergistic Sphere-to-Rod Micelle Transition in Mixed Solutions of Sodium Dodecyl Sulfate and Cocoamidopropyl Betaine. Langmuir 2004, 20, (3), 565-571. 52. Chu, Z.; Feng, Y.; Su, X.; Han, Y., Wormlike Micelles and Solution Properties of a C22-Tailed Amidosulfobetaine Surfactant. Langmuir 2010, 26, (11), 7783-7791.


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Energy & Fuels

Surfactant

Denotation

Structure

Ethomeen C/12

C12-14N(EO)2

Duomeen TTM

C16-18N(CH3)C3N(CH3)2

Duomeen CTM

C12-14N(CH3)C3N(CH3)2


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Low pH


Page 22 of 31

Page 23 of 31 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Accumulator Back

ΔP 50 psi

Front Piston

ΔP 100 psi

ΔP 200psi

CO2

BPR

ISCO Pump

Heat exchangers Packed bed of crushed limestone or glass Capillary View cell beads Forced convection air oven

Oil Surfactant solution HPLC Pump


Energy & Fuels

Duomeen TTM

Duomeen CTM

1000

100 Viscosity cP

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 24 of 31

10

1 0.1

1

10 Shear rate /s


100

Page 25 of 31

Duomeen TTM

Duomeen CTM

45 40 Foam Apparent Viscosity cP

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

35 30 25 20 15 10 5 0 65

75

85 Foam Quality %


95

Energy & Fuels

Duomeen CTM

Ethomeen C/12

Duomeen TTM

1000

Foam apparent viscosity (cP)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 31

y = 1761.39x-0.69 R² = 0.96

100 y = 1036.88x-0.69 R² = 1.00

y = 276.89x-0.55 R² = 0.79

10 1

10 100 Superficial velocity (ft/day)


1000

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Energy & Fuels


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 28 of 31

Peak area (Abundance 107) 135 °C after one month 16.6 4.44

Change %

C12-14N(CH3)C3N(CH3)2

Reference group (25°C) 16.3 4.24

C12-14N(EO)2

6.65

4.51

-32.15

Surfactant candidates C16-18N(CH3)C3N(CH3)2


+1.84 +4.50

Page 29 of 31 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Surfactant

C12-14N(CH3)C3N(CH3)2

C16-18N(CH3)C3N(CH3)2

Page 30 of 31

pH

Peak area (Abundance x107)

Weight fraction in brine phase

Weight fraction in oil phase

Partition Coefficient

2 4 7 2 4 7

3.85 3.36 1.80 3.34 3.12 1.60

0.869 0.755 0.390 0.798 0.743 0.360

0.131 0.245 0.610 0.201 0.247 0.640

0.151 0.325 1.562 0.252 0.347 1.780


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Energy & Fuels


Design of CO2-in-Water Foam Stabilized with Switchable Amine

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