ALKOXYLATED ALKYL CARBOXYLATE SALTS AS VAPOR FOAM ADDITIVES FOR HEAVY OIL RECOVERY

Abstract

Recovery of heavy oil from an underground formation penetrated by at least one injection well and one production well, by injecting into an injection well a mixture of steam and an alkyl alkoxylated carboxylate salt, which increases the apparent viscosity of the steam while at the same time decreasing the mobility of the steam, and recovery of oil from the underground formation.

Description

ALKOXYLATED ALKYL CARBOXYLATE SALTS AS VAPOR FOAM ADDITIVES FOR HEAVY OIL RECOVERY FIELD OF INVENTION The present invention relates to vapor foam additives and a method of using them for heavy oil recovery, and in particular, to thermally stable surfactants that decrease vapor mobility. Specifically, the surfactants comprise mainly alkyl alkoxylated carboxylate salts. BACKGROUND OF THE INVENTION The present invention relates to a foaming surfactant and a method for improving the recovery of heavy oil from underground wells. As more light oil fields are either depleted or reach their economic limit, the percentage of heavy oils in global oil production continues to rise. However, heavy oil recovery can be problematic due to its extremely high viscosity at formation temperatures and the low permeability of sand formations (Carter et al., 2006). Conventional heavy oil recovery technologies, therefore, must apply heat to melt the oils in order to mobilize them for effective recovery. Some technologies use steam as the heat source. Others generate heat through in-situ combustion or electric heating (Nasa and Ayúdele, 2005; SSSS and Berry Jr., 1963; Álvarez and Han, 2013). Steam injection has proven to be one of the most effective recovery methods for heavy oils. By heating the formation, it decreases the viscosity of the heavy oils, thereby increasing their flow to the production wells. For example, steam-assisted gravity drainage (SAGA) has been the most common method in heat-infected recovery technologies for heavy oils. In this process, steam is injected into the steam injection well. The steam rises due to buoyancy forces and forms a steam chamber above the well. The heat in the steam chamber softens the oil, causing it to melt and flow into the production well located below the injection well. The oil, along with the condensed water from the steam, can then be pumped to the surface and separated from the water.Modifications to the SAGA process to improve oil recovery, such as solvent-steam injection and convective SAGA, have been evaluated (Wood, 2016; Nasa et al., 2003). However, steam injection in thermal processes such as SAGA, steam drive, and cyclic steam have their own problems, including steam spill and steam channeling, which result in low oil recovery in low-permeability zones (Zhang et al., 2007; Castañar and Brigán, 1991). Steam spill occurs when gravity causes low-density steam to rise to the top of the formation, diverting a significant fraction of the initial oil to the bottom of the reservoir.Steam channeling is observed when steam channels through relatively high permeability zones and displaces oil from those zones while diverting a significant fraction of oil to lower permeability zones (Durasen, 1986; Eso, 1983; Chan et al., 2010). Both phenomena occur due to the low viscosity of steam and can result in high steam generation costs and low oil recovery. It has been demonstrated in prior art literature that surfactants, injected with steam, create a steam foam flood that enhances the steam flooding process in heavy oil recovery. The presence of foam creates a barrier that slows the movement of steam to both upper formation levels and toward the production wells, resulting in the distribution of steam to low-permeability zones of the reservoir and more efficient heat transfer to the oil, thus reducing oil viscosity. In other words, steam spillover and channeling problems can be caused by an increase in the apparent viscosity of the steam due to the foam. 7CC7 ΠΠ / ί7Π7 / 3 / YILI of surfactant. As a result, the average residual oil saturation in the reservoir is reduced. The prior art systems described for anionic surfactants focus mainly on sulfate surfactants as foaming agents for steam ERO processes, at operating temperatures up to 200 °C (Gassman et al., 1984; Huango et al., 1984; Muís et al., 1988; Wall, 1989; Cuenca et al., 2014). Some carboxylates have also been reported as steam foaming agents up to 180 °C (Hawkins and Schievelbein, 1986). There is a continuing need for improved oil recovery techniques from various oil-bearing formations, such as underground oil wells, as well as tar or oil sands. The additional need to perform such recovery methods at elevated temperatures, as used in steam applications, is well met by the compounds and methods described in the present invention. BRIEF DESCRIPTION OF THE INVENTION The present invention has gone beyond the prior art and discovered a group of anionic surfactants, specifically surface-active salts of alkyl alkoxylated carboxylates, which demonstrate thermal stability and generate strongly stable foam up to 250 °C in the 7CC7 ΠΠ / ί7Π7 / 3 / YILI presence of oil. The structures of the identified surfactants can be tailored with respect to surfactant hydrophobicity to optimize the transport and thermodynamic properties of the surfactants and foams, in order to target the temperature and salinity of the reservoir. Such adaptation is affected by careful design, which takes into account the carbon chain length of the alkyl groups, the nature of branching, the choice of alkoxylation agent, the degree of alkoxylation, as well as the neutralizing agent used for salt formation. The present invention demonstrates a steam injection method that utilizes thermally stable surfactants that generate highly stable foam under vapor conditions. The surfactant structures of the present invention consist of long-chain alkyl alkoxylated carboxylate salts as steam foam additives for heavy oil recovery. The purpose is to utilize the surfactant foam in the vapor condition to decrease vapor mobility by increasing the apparent vapor viscosity. Of particular interest is the ability of these surfactant structures to be thermally stable and to generate stable foam under vapor conditions up to 250 °C. The present invention discloses the use of anionic surfactant as a vapor foam additive in heavy oil recovery, comprising: an alkyl alkoxylated carboxylate salt, wherein the alkyl alkoxylated carboxylate salt has a molecular structure as shown in (I): RO- (AO' )n- (A0)mR' -COO- M+[I] where R is a branched alkyl group, a linear alkyl group, or a mixture of branched and linear alkyl groups, having 16 to 36 carbon atoms, preferably 20 to 26 carbon atoms, much more preferably 24 carbon atoms, AO' is an ethoxy (EO) or propoxy (PO) group, AO is an EO or PO group, R' is a methylene or ethylene or propylene group, η = 1 - 15, m = 0 - 15, m + n < 20, with the condition that, in the case where both PO and EO groups are present, the molar ratio PO / EO is less than 1, and M+ is an alkali metal ion (e.g., sodium), an alkanol amine ion (e.g., monoethanolamine (MEA), diethanolamine (DEA), triethanolamine (TEA), monoisopropanolamine (MIPA), diisopropanolamine (DIPA), and triisopropanolamine (TIPA)), or another neutralizing agent (e.g., an alkylamine ion or an ammonium ion). It will be recognized by those skilled in the technique that, depending on the alcohol used to form the hydrophobic compound, a linear chain may include a small percentage of branched molecules, although it is generally referred to as linear. Similarly, a branched chain may have a small percentage of linear molecules, although it is generally referred to as branched. Accordingly, as used herein, the term linear means 90% to 100% linear, and thus may include a small amount of branched molecules. As used herein, the term branched means 95% to 100% branched, and thus may include a small amount of linear molecules. A mixture of linear and branched compounds has between 10% and 95% branched molecules. In the present invention, where R is branched or a mixture of linear and branched, preferably the branched molecules have an average number of 0.3 to 3.5 branches per molecule and at least one branch is in the 2-alkyl position. In a preferred embodiment of the present invention, for the anionic surfactant described herein above, R is a C24 branched 2-alkyl group, and the PO / EO molar ratio is < 1. Another embodiment of the present invention is a method for recovering heavy oil from a formation 7CC7 ΠΠ / ί7Π7 / 3 / YΙΛΙ underground that is penetrated by at least one injection well and one production well, comprising: i) Injecting into an injection well a mixture of steam and a surfactant, the surfactant comprising an alkyl alkoxylated carboxylate salt, described herein above in formula [i] ; ii) increase the apparent viscosity of the vapor, and at the same time decrease the mobility of the vapor, and iii) recover heavy oil from the underground formation. Suitable additives such as a co-surfactant for additional interfacial tension reduction or emulsification can optionally be added to the composition described above. These and additional features and advantages of the present invention will become evident from the following detailed description, where reference is made to the figures in the accompanying drawings. BRIEF DESCRIPTION OF THE DRAWINGS Fig. 1 shows HPLC profiles for surfactants of the present invention. Fig. 2 shows the thermal stability of surfactants of the present invention before and after being aged. 7CC7 ΠΠ / ί7Π7 / 3 / YΙΛΙ Fig. 3 is a graph showing the percentage of surfactant remnant of the present invention after aging. Fig. 4 shows the foaming performance of the surfactants of the present invention as compared to a surfactant of the prior art. Fig. 5 shows the apparent vapor viscosity of surfactants of the present invention in a column packed with oil-free sand. Figure 6 shows the apparent vapor viscosity of surfactants of the present invention in a packed column of sand with bitumen versus without bitumen. DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS The alkyl alkoxylated carboxylate salts of the present invention are highly stable at steam temperatures. Their performance can be improved by tailoring the hydrophobic structure (such as branching and chain length) and the levels of PO and EO units to the needs of the wells. For example, under steam conditions at 250°C without the presence of oil, long hydrophobic salts with 20 or more hydrocarbons, the alkyl alkoxylated carboxylates, are required to generate stable foam that results in steam viscosity increased by more than three orders of magnitude. The following non-limiting examples will demonstrate the 7CC7 ΠΠ / ί7Π7 / 3 / YΙΛΙ performance and advantages of the surfactants of the present invention. As used in the present, the following terms are proposed to have the meanings indicated below with reference to the hydrophic chain. * short chain = a carbon chain of fewer than 10 carbon atoms ( <C10) * cadena mediana = una cadena de carbono que tiene de 10 a 16 átomos de carbono (CIO a C16) * cadena larga = una cadena de carbono que tiene mayor que 16 átomos de carbono (> C16) * heavy chain = a carbon chain that has more than 20 carbon atoms (> C20). These definitions are for the purpose of clarifying the language used herein and are not intended to limit the invention. Materials All surfactants used in the following examples are anionic surfactants, specifically alkyl alkoxylated carboxylate salts. The surfactants consist of short-, medium-, long-, and heavy-chain alcohols with propoxy and / or ethoxy units. The alkyl hydrophobes are either linear or branched. The surfactants used are described in Table 1. It is understood that some of the surfactants tested are outside the scope of the present invention and are comparative examples to demonstrate the improved results produced by the present invention. Table 1 Surfactant Alcohol Name Alcohol Structure Carbon Chain Length PO / EO Number PO / EO Molar Ratio Comparative Surfactant 1 (BS-POEO-A3) isononanol short chain, branched C9 1.6PO / 2.4EO PO / EO < 1 Comparative Surfactant 2 (BM-EO) ITDA (isotridecanol; MARLIPALO13) medium chain, branched C13 7EO EO only Comparative Surfactant 3 (LM-EO) NAFOL 1214 medium chain, linear C12 / C14 4.5EO EO only Comparative Surfactant 4 (LM-EO) NAFOL 1214 medium chain, linear C12 / C14 7EO EO only Comparative Surfactant 5 (LM-POEO-A3) NAFOL 1214 medium chain, linear C12 / C14 2PO / 5EO PO / EO < 1 Comparative Surfactant 6 (BM-EO) ISALCHEM 123 median cadena, ramified of 2-alquilo C12 / C13 7EO EO only Surfactante 7 (BL-EO) LIAL 167 mezcla of large linear cadena and ramified of 2-alquilo C16 / C17 7EO EO only Surfactante 8 (BL-POEO-A3) LIAL 167 mixture of large, linear and branched 2-alkyl C16 / C17 2PO / 5EO PO / EO < 1 Comparative Surfactant 9 (LL-POEO-A1) NAFOL1618 large, linear C16 / C18 4.5PO / 2EO PO / EO > 1 Comparative Surfactant 10 (LL-POEO-A2) NAFOL 1618 cadena larga, lineal C16 / C18 4.5PO / 5EO PO / EO ~ 1 Surfactante 11 (LL-POEO-A3) NAFOL 1618 cadena larga, lineal C16 / C18 2PO / 5EO PO / EO < 1 Surfactante 12 (LH-EO) NAFOL 20+ cadena pesada, C20+ 7EO EO únicamente 7CC7 ηη / 17Π7 / 3 / ΥΙΛΙ lineal Surfactante 13 (LH-P0E0-A3) NAFOL 20+ heavy cadena, lineal C20+ 2PO / 5EO PO / EO < 1 Surfactante 14 (BM-EO) ISOFOL 12 median cadena, branched from 2-alquilo C12 7EO EO only Surfactante 15 (BM-POEO-A3) ISOFOL 12 medium cadena, branched from 2-alquilo C12 2PO / 5EO PO / EO < 1 Surfactant 16 (BL-EO) ISOFOL 20 broad cadena, branched from 2-alquilo C20 7EO EO only Surfactant 17 (BL-POEO-A3) ISOFOL 20 wide cadena, branched from 2-alquilo 2-alquilo C20 2PO / 5EO PO / EO < 1 Surfactant 18 (BH-POEO-A3) ISOFOL 24 Cadena pesada, ramificada de C24 2PO / 5EO PO / EO < 1 7CC7 ηη / 17Π7 / 3 / ΥΙΛΙ 2-alkyl Surfactant 19 (BH-POEO-A3) ISOFOL 28 heavy cadene, branched from 2-alkyl C28 2PO / 5EO PO / EO < 1 Thermal stability test 7CC7 ΠΠ / ί7Π7 / 3 / ΥΙΛΙ As used herein, the term thermal stability refers to surfactant activity that remains unchanged over a period of time under predetermined conditions. The thermal stability test was performed in a high-temperature, high-pressure (HTHP) Parr reactor at 200 and 250 °C. The surfactant was prepared as a 1 wt% solution with 1 wt% NaCl. Before the Parr reactor was heated to the desired temperature, nitrogen gas was slowly purged through the solution to remove oxygen, and the Parr reactor was pre-pressurized to 300 psi. Three samples of each surfactant solution were aged in the Parr reactor: one sample for 1 day, one sample for 1 week, and one sample for 2 weeks. The surfactant profile in the solution before and after the aging time was analyzed by high-performance liquid chromatography (HPLC) to determine surfactant degradation.Changes in the HPLC profile, typically a decrease in the peak or maximum surfactant area, indicate surfactant degradation. The thermal stability of the studied surfactants was evaluated at 200 and 250 °C, indicated by changes in the HPLC profiles of the surfactants in solutions before and after aging. Figure 1 shows the HPLC profiles for three surfactants, Comparative Surfactant 1, Comparative Surfactant 2, and Comparative Surfactant 3, at 250 °C for a 1-day test. Among the three surfactants, Surfactant Comparative Surfactant 3 showed the highest degree of degradation, much higher than that of Comparative Surfactant 2. Comparative Surfactant 3 and Comparative Surfactant 2 are both composed of medium-chain alcohols with similar EO content; however, Comparative Surfactant 3 has a linear hydrophore, while Comparative Surfactant 2 has a branched hydrophore. This indicates that the branched structure of the hydrophore retards surfactant degradation. Comparative Surfactant 1 showed negligible degradation, as indicated by the almost identical HPLC profile of the surfactant before and after the aging process. Comparative Surfactant 1 is composed of a branched short-chain alcohol with both PO and EO units. The result indicates that the thermal stability of the surfactant is improved not only by having the hydrophore of 7CC7 ΠΠ / ί7Π7 / 3 / YILI branched structure but also with the addition of PO units, which increases the hydrophobicity of the surfactant. The thermal stability of Comparative Surfactant 1 was further evaluated over a longer period of time at 1 and 2 weeks. The results are shown in Fig. 2. It can be observed that for the same aging period of 2 weeks, Comparative Surfactant 1 initially shows more significant degradation at 250 °C than at 200 °C. Table 2 summarizes the remaining amount of surfactant after each aging period at both temperatures. Table 2 7CC7 ΠΠ / ί7Π7 / 3 / YΙΛΙ Time (week) 200°C 250°C 0* 100% 100% 1 94% 52% 2 79% 38% *Fresh sample before the aging process. At 200 °C, 79% of the surfactant remained after 2 weeks, but only 38% remained at 250 °C. Based on the effect of surfactant structure on thermal stability, it was hypothesized that long-chain hydrophobes, especially branched ones, and the addition of PO units improve the thermal stability of surfactants at high temperatures. This hypothesis is demonstrated in Fig. 3. The results show that hydrophobic branching and chain length significantly impact surfactant thermal stability. Surfactant 5, a heavy branched hydrophobe (C20+), proved to be highly stable, with 90% surfactant activity remaining after 2 weeks at 250 °C. Table 3 summarizes the remaining amount of surfactant (%) after each aging period at 250 °C, for some of the surfactants evaluated. Table 3 7CC7 ΠΠ / ί7Π7 / 3 / YΙΛΙ Surfactant Alcohol name Carbon Chain Length PO / EO Number Thermal Stability @ 250°C [%] One day One week Two weeks Comparative Surfactant 1 (BS-POEO-A3) Isononanol C9 1.6PO / 2.4EO - 52.0 38.0 Comparative Surfactant (EO-LM) NAFOL 1214 C12 / 14 7EO 100 85.5 76.0 Surfactant 11 (LL-POEO-A3) NAFOL 1618 C16 / C18 2PO / 5EO 100 45.4 23.9 Surfactant 12 (LH-POEO-A3) NAFOL 20+ C20+ 2PO / 5EO 96.9 91.3 64.8 Surfactant 17 (BL-POEO-A3) ISOFOL 20 C20 2PO / 5EO 96.2 71.0 56.58 Surfactant (BH-POEO-A3) ISOFOL 24 C24 2PO / 5EO 93.3 96.5 90.0 7CC7 ΠΠ / ί7Π7 / 3 / ΥΙΛΙ Foam Performance in Volume The foaming performance of the surfactants was evaluated at 250 °C in a high-temperature, high-pressure (HTHP) vessel. The vessel was filled with 33 mL of the surfactant solution at 0.5 wt%. The backpressure regulator was set to 800 psi. The vessel was pre-pressurized to 800 psi with nitrogen gas before being heated to the test temperature of 250 °C. Once the oven temperature control indicated 250 °C, the solution was incubated for 30 minutes to ensure that the solution temperature reached 250 °C before nitrogen was injected from the bottom of the vessel to generate foam. Nitrogen gas was injected continuously at 1000 psi until the foam reached its maximum volume in the vessel, at which point the foam volume was recorded. The foam was visually observed through the sapphire window on the side of the vessel. The volume of foam was recorded every two minutes until the foam completely subsided.The foaming performance of the surfactant was quantified and expressed as the percentage of foam volume generated by the initial liquid volume used to generate the foam, as shown in Table 4. Table 4 Surfactant Carbon Chain Length PO / EO Number Initial Foam % by vol. Foam in 2 minutes, % by vol. Foam in 4 minutes, % by vol. Foam in 6 minutes, % by vol. Comparative Surfactant 3 (LM-EO) C12 / C14 4.5EO No foam Comparative Surfactant 4 (LM-EO-A2)* C12 / C14 7EO 50% 8% 8% 8% Comparative Surfactant 5 (LM-POEO-A3) C12 / C14 2PO / 5EO 37% 21% 13% 8% Comparative Surfactant 2 (BM-EO) C12 / C13 7EO No foam Surfactant 7 (BL-EO) C16 / C17 7EO No foam Surfactant C16 / C17 2PO / 5EO 111% 79% 18% 11% Comparative 8 (BL-POEO-A3) Surfactant 12 (LH-EO) C20+ 7EO No foam Surfactant 13 (LH-POEO-A3) C20+ 2PO / 5EO 282% 151% 58% 34% Surfactant 14 (BM-EO) C12 7EO 42% 24% 5% 5% Surfactant 15 (BM-POEO-A3) C12 2PO / 5EO 29% 11% 8% 8% Surfactant 16 (BL-EO) C20 7EO No foam Surfactant 17 (BL-POEO-A3) C20 2PO / 5EO 197% 184% 58% 16% Surfactant 18 (BH-POEO-A3) C24 2PO / 5EO 247% 187% 79% 63% Surfactant 19 (BH-POEO-A3) C28 2PO / 5EO insoluble 7CC7 ΠΠ / ί7Π7 / 3 / ΥΙΛΙ *Comparable to prior art Surfactant Agent 1 of US Patent 4,637,766. , do Since the starting surfactant concentration in the thermal stability experiments was 1 wt% and most of the surfactants studied had at least 50% surfactant remaining at 250 °C after two weeks, the volume foam test was performed at 0.5 wt% surfactant concentration and 250 °C. The volume foam test was first performed on EO surfactants only, and the results at 250 °C are summarized in Table 4. These surfactants had similar percentages of EO in their molecular structures. Only two surfactants were able to generate a small amount of foam, while the rest showed no foaming activity. This could be due to the fact that as the hydrophobic chain length increases, the surfactant's surface activity decreases. Therefore, the long-chain hydrophobe was unable to create a sufficiently stable film between the liquid and the air to form foam bubbles. These surfactant structures can be compared to and closely resemble a prior art example structure of C11 / C15-7 EO surfactant claimed as a vapor foaming agent in prior art. The foaming performance in volume of Comparative Example 4 and Surfactant 14 was compared with alkyl alkoxylated carboxylate salt surfactants of similar hydrophobic chain length but with both PO and EO units in the molecular structure. As can be seen in Table 4, having PO units in the molecular structure of these medium-chain hydrophobes does not provide a significant improvement in foaming performance at 250 °C. For longer hydrophobic PO / EO alkyl alkoxylate carboxylate salts, the effect of hydrophobic chain length on foam performance under vapor conditions was studied using alkyl alkoxylate carboxylate salts with similar PO and EO levels but varying hydrophobic chain lengths. The results showed that as the hydrophobic chain length increased, the foam volume generated at 250 °C increased significantly. The foam volume doubled to tripled as the hydrophobic chain length increased from C12, C14 to C16, C17. However, foam stability was not improved by this increase in hydrophobic chain length. In both cases, the foam almost completely subsided after six minutes.As the hydrophobic chain length increased to C20 and higher, both foam volume and foam stability improved, most significantly in terms of foam volume. The long, highly branched Surfactant 19 notably exhibited significantly higher foam volume and foam stability at 250 °C. The linear Surfactant 13 showed slightly higher foam volume and foam stability than the branched Surfactant 17. This could be due to the shorter main chain hydrophobic component of Surfactant 17 resulting from branching. In particular, Comparative Example 4 of surfactant, which is a representative example of U.S. Patent 4,637,766, incorporated herein by reference for all purposes, had lower foam volume and foam stability compared to the longer chain surfactants of the present invention. Sand-Packed Column Test To replicate downhole performance, the foaming performance of chemically stable surfactants in vapor condition was evaluated in sand-packed columns. Good foam performance was determined based on the apparent vapor viscosity, calculated from the pressure drop measured across the sand-packed columns using Darcy's law, as an indication of foam propagation and concentration during steam injection at temperatures up to 250 °C, with and without the presence of bitumen. Ottawa sand was used. The surfactants selected at 0.5% by weight were heated to 250°C before being co-injected into the sand-packed column with the steam at 75% quality (i.e., volume fraction of steam in the injected mixture of steam and surfactant solution) at up to 250°C. The sand-packed column experiments were carried out following the procedure described in Table 5. Table 5 7CC7 ΠΠ / 17Π7 / 3 / YILI Without bitumen With bitumen 1. Inject approximately 40 PV of 1 wt% KC1 solution into the cleaning sand packing (at room temperature). 1. Inject approximately 40 PV of 1 wt% KC1 solution into the cleaning sand packing (at room temperature). 2. Simultaneously inject KC1 solution and gas in different proportions. 2. Saturate the sand-packed column with bitumen. 3. Simultaneously inject 0.5 wt% surfactant solution and gas in different proportions. 3. Flood the sand-packed column with water containing 1 wt% KC1 solution. 4. Simultaneously inject KC1 solution and gas in different proportions. 5. Simultaneously inject 0.5 wt% surfactant solution and gas in different proportions. The dimensions of the sand-packed column are 1 inch ID x 12 inches long. The pressure drop across the column during steam injection was recorded. The sand-packed column was first saturated with a 1 wt% KC1 brine solution with approximately 40 pore volume (PV). The column permeability was calculated from this first stage based on Darcy's law (Eq. 1) : 'μΙ.fen where A = area, m2k = permeability, m2 L = length, m pb - pa = pressure drop (Pa) q = flow rate, m3 / s μ = viscosity, Pa.s The injection rate at each stage of the sand-packed column experiments is shown in Table 6. 7CC7 ΠΠ / 17Π7 / 3 / YILI Table 6 Injection Rate Brine only at ambient conditions Brine / gas at vapor conditions Surfactant / gas at vapor conditions Initial rate 13.33 cc / min Brine: 3.33 cc / min N2 gas: 10 cc / min Surfactant: 3.33 cc / min N2 gas: 10 cc / min Doubled rate 26.66 cc / min Brine: 6.66 cc / min N2 gas: 20 cc / min Surfactant: 6.66 cc / min N2 gas: 20 cc / min Darcy's law was then applied to calculate the 7CC7 ΠΠ / 17Π7 / 3 / YILI apparent vapor viscosity during injection of KC1 solution (as a baseline without surfactant) and surfactant solution in vapor condition (200 or 250 °C), showing the apparent vapor viscosity without and with surfactant, respectively, in order to evaluate the effect of surfactant foam on the apparent vapor viscosity. The column backpressure was monitored at 710 psi. The apparent viscosity of the vapor without surfactant was measured at 0.1 cP as the baseline reference. The foaming performance of the surfactants was evaluated based on the pressure drop across sand-packed columns under vapor conditions. It was found that above 150 °C, the short- and medium-chain surfactants studied, such as Comparative Surfactant 1, Comparative Surfactant 2, and Comparative Surfactant 3, were unable to generate foam, although they were found to be thermally stable up to 200 °C. As mentioned above, alkyl aryl sulfonates have been repeatedly reported in the literature as good steam foaming agents (Muís et al., 1988; Cuenca et al., 2014). Fig. 4 shows a comparison of the foam performance of Comparative Surfactant 9 and Surfactant 10 with that of a linear C15 / 16 alkylbenzene sulfonate of the prior art at 200 °C, without oil in sand-packed columns. The foaming performance of Comparative Surfactant 9 was comparable to that of the prior art C15 / 16 linear alkylbenzene sulfonate, which was inferior to the foaming performance of Surfactant 10 based on each surfactant's ability to increase the apparent vapor viscosity. The apparent vapor viscosity was only slightly increased (less than one order of magnitude) with Comparative Surfactant 9 and the alkylbenzene sulfonate only at the doubled gas and liquid injection rates. However, the apparent vapor viscosity was increased by two orders of magnitude by Surfactant 10 at both low and high injection rates at 200 °C. This result indicates that the higher PO / EO molar ratio in Comparative Surfactant 9 makes this surfactant highly hydrophobic for good foam generation compared to Surfactant 10, which has a lower PO / EO molar ratio.Therefore, it is speculated that a surfactant with a lower PO / EO molar ratio, such as Surfactant 11, is desired for better foam performance at temperatures higher than 200 °C. Based on the results of the thermal stability and foaming performance of the surfactants studied so far up to 200 °C, it is hypothesized that in order for a surfactant to have desirable thermal stability and foaming performance at temperatures higher than 200 °C, the surfactant needs to have a molecular structure consisting of a hydrophobe that is at least a long-chain alcohol (C16+) in which the branched structure is preferred with a PO / EO molar ratio less than 1. This hypothesis is further supported by the foaming performance tests of three surfactants with such structures (Surfactant 11, Surfactant 17 and Surfactant 18) in sand-packed columns at 250 °C. It should be noted that all three surfactants have the same PO / EO molar ratio which is less than 1 with the long linear hydrophobic (Surfactant 11), long branched hydrophobic (Surfactant 17) and heavy branched hydrophobic (Surfactant 18).The foaming performance indicated by the apparent vapor viscosity for the three surfactants at 250 °C without oil is shown in Fig. 5. At 250 °C without oil, the foam from Surfactant 11, which could only be generated at twice the gas and liquid injection rate, increased the apparent vapor viscosity by less than two orders of magnitude. However, the foam generated by the branched surfactants, Surfactant 17 and Surfactant 18, was able to increase the apparent vapor viscosity by at least three orders of magnitude. 7CC7 ΠΠ / 17Π7 / 3 / YILI magnitude at 100 cP in the gas both initial and duplicated in the liquid injection rates. This indicates that the branched structure of the long-chain, heavy hydrophobic surfactants significantly improves the foaming performance of surfactant 5 in the vapor condition at 250 °C, showing superior foaming performance to the linear and shorter-chain hydrophobic surfactants. Since Surfactant 17 and Surfactant 18 exhibit strong and stable foaming at 250 °C without oil, they were selected for the study of foam performance in the presence of bitumen. The properties of the bitumen used in this study are summarized in Table 7. Table 7 Viscosity Density 915,000 cP at 20 °C 929 kg / m3 6.1 cP at 200 °C 20.8 °API Figure 6 shows the effect of bitumen on the foaming properties of the surfactants, or the apparent vapor viscosity at 250 °C. For both surfactants, the apparent vapor viscosity in the presence of bitumen decreased by an order of magnitude compared to that without bitumen. However, the apparent vapor viscosity in the presence of bitumen was still two orders of magnitude higher with the surfactant foam than without it. Thus, Surfactant 17 and Surfactant 18 proved to be strong and stable foaming agents that significantly improve vapor mobility at 250 °C in the presence of bitumen. The test results described above demonstrate that for a surfactant to have thermal stability and foaming performance at temperatures higher than 200°C, the surfactant needs to have a molecular structure consisting of a hydrophobe that is at least a long-chain alcohol (C16+), in which branched structures are preferred, with a PO / EO molar ratio less than 1. At higher temperatures, i.e., 250°C, the surfactant with a branched heavy hydrophobe (C20+) was found to be highly stable, with 90% of the surfactant remaining after two weeks. The structure-property ratio established in the present invention is advantageous for developing a surfactant foaming agent suitable for a specific reservoir temperature and pressure.The surfactants of the present invention are particularly beneficial to thermal steam ERO processes because they generate strong and stable foam under steam conditions that can overcome steam spillage and channeling problems that result in low heavy oil recovery. Although specific modalities of the invention have 7CC7 RP / ί7RP7 / 3 / YILI described herein in some detail, this has been done solely for the purpose of explaining the various aspects of the invention, and is not intended to limit the scope of the invention as defined in the claims that follow. Those skilled in the art will understand that the embodiment shown and described is exemplary, and various other substitutions, alterations, and modifications, including but not limited to those design alternatives specifically discussed herein, may be made in the practice of the invention without departing from its scope. REFERENCES The following references are all incorporated herein for reference purposes. Larter, SR, Adams, J., Gates, ID, et al. 2006. The Origin, Prediction and Impact of Oil Viscosity Heterogeneity on the Production Characteristics of Tar Sand and Heavy Oil Reservoirs. Presented at the Canadian International Petroleum Conference, Calgary, Alberta, June 1315. PETSOC 2006-134. https: / / doi.org / 10.2118 / 2006-134. Nasr, TN and Ayodele, OR 2005. Thermal Techniques for the Recovery of Heavy Oil and Bitumen. Presented at the SPE International Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, Malaysia, December 5-6. SPE 97488. https: / / doi.org / 10.2118 / 97488-MS. 7CC? nn / L7n7 / q / Yi Szasz, E. and Berry Jr., V.J. 1963. Oil Recovery by Thermal Methods. Presented at the 6thWorld Petroleum Congress, Frankfurt am Main, Germany, June 19-26. WPC-10138. Alvarez, J. and Han, S. 2013. Current OverView of Cyclic Steam Injection Processes. J Pet Sci Res, 2 (3): 116-127. Sood, A. 2016. Convective SAGD Process. Presentado en the SPE Cañada Heavy Oil Technical Conference, Calgary, Alberta, 7-9 de junio. SPE-180734-MS. https: / / doi.org / 10.2118 / 180734-MS. Nasr, T.N., Beaulieu, G., Golbeck, H. y colaboradores. 2003. Novel Expanding Solvent-SAGD Process ES-SAGD. J Can Pet Technol, 42 (1): 13-16. PETSOC-03-01-TN. https: / / doi.org / 10.2118 / 30-01-TN. Zhang, W., Youn, S. and Doan, Q. 2007. Understanding Reservoir Architectures and Steam-Chamber Growth at Christina Lake, Alberta, by Using 4D Seismic and Croswell Seismic Imaging. SPE Res Eval & Eng 10 (5): 446-452. SPE9 7 8 0 8-PA. https: / / doi.org / 10.2118 / 97808-PA. Castanier, L.M. and Brigham, W.E. 1991. An Evaluation of Field Projects of Steam with Additives. SPE Res Eng 6 (1): 62zV. 68. SPE-17633-PA. https: / / doi.org / 10.2118 / 17633-PA. Duerksen, J.H. 1986. Laboratory Study of Foaming Surfactants as Steam-Diverting Additives. SPE Res Eng 1 (1): 44-52. SPE12785-PA. https: / / doi.org / 10.2118 / 12785-PA. 7CC? nn / L7n7 / q / Yi Eson, R.L. 1983. Improvement in Sweep Efficiencies in Thermal Oil-Recovery Projects through the Application of In-Situ Foams. Presentado en the SPE Oilfield and Geothermal Chemistry Symposium, Denver, Colorado, 1-3 de junio. SPE-11806-MS. https: / / doi.org / 10.2118 / 11806-MS. Chen, Q., Gerritsen, M.G. and Kovscek, A.R. 2010. Improving Steam-Assisted Gravity Drainage Using Mobility Control Foams: Foam Assisted-SAGD (FA-SAGD). Presentado en the SPE Improved Gil Recovery Symposium, Tulsa, Oklahoma, USA, 2428 de abril. SPE-129847-MS. https: / / doi.org / 10.2118 / 12 98 4 7-MS. Gassmann, Z.Z., Hawkins, J.T. and Brown, A. 1984. Injection of Steam Foaming Agents into Producing Wells. US Patent No. 4,577,688. Huang, W.S., Gassmann, Z.Z. and Hawkins, J.T. y colaboradores. 1984. Method of Improving Conformance in Steam Floods with Steam Foaming Agents. US Patent No. 4,540,050. Muijs, H.M., Keijer, P.P.M and Wiersma, R.J. 1988. Surfactants for Mobility Control in High-Temperature Steam-Foam Applications. Presentado en the SPE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 16-21 de abril. SPE-17361-MS. https: / / doi.org / 10.2118 / 17361-MS. Wall, R.G. 1989. Sequential Injection Foam Process for Enhanced Oil Recovery. US Patent No. 5,052,487. Cuenca, A., Lacombe, E. and Morvan, M. y colaboradores. 2014. Design of Thermally Stable Surfactants Formulations for Steam Foam Injection. Presentado en the SPE Heavy Oil 5 Conference-Canada, Calgary, Alberta, Cañada, 10-12 de junio. SPE-170129-MS. https: / / doi.org / 10.2118 / 170129-MS. Hawkins, J.T. and Scheivelbein, V.H. 1986. Method of Improving Conformance in Steam Floods with Carboxylate Steam Foaming 10 Agents. US Patent No. 4,637,466. 7CC7 ΠΠ / 17Π7 / 3 / ΥΙΛΙ

Claims

1. Use of a surfactant as a steam foam additive in heavy oil recovery, characterized in that the surfactant comprises: an alkyl alkoxylated carboxylate salt, wherein the alkyl alkoxylated carboxylate salt has a molecular structure as shown in [I]: RO-(AO')n-(A0)m-R'-COO-M+ [I] wherein R is a linear, branched, or mixed linear and branched alkyl group having 16 to 36 carbon atoms, AO' is an ethoxy (EO) or propoxy (PO) group, AO is an EO or PO group, R' is a methylene, ethylene, or propylene group, η = 1 - 15, m = 0 - 15, m + n < 20, with the condition that, in the case where both PO and EO groups are present, the PO / EO molar ratio is less than 1, and M+ It is an alkali metal ion, an alkanolamine ion, an alkylamine ion, or an ammonium ion.

2. The use according to claim 1, characterized in that R is a mixture of linear and branched alkyl groups.

3. The use in accordance with claim 1, characterized in that R is a branched alkyl group.

4. The use according to claim 2 or 3, characterized in that the branched molecules have an average number of 0.3 to 3.5 branches per molecule, and at least one branch is in the 2-alkyl position.

5. Use in accordance with any of claims 1-4, characterized in that both PO and EO are present.

6. Use in accordance with any of claims 1-4, characterized in that AO' is PO.

7. Use in accordance with any of claims 1-6, characterized in that R is from 20 to 26 carbon atoms.

8. Use in accordance with any of claims 1-7, characterized in that M+ is an alkali metal ion, an alkanolamine ion, or an ammonium ion.

9. A method for recovering heavy oil from an underground formation penetrated by at least one injection well and one production well, characterized in that it comprises: i) injecting into an injection well a mixture of steam and a surfactant, the surfactant comprising an alkyl alkoxylated carboxylate salt, wherein the alkyl alkoxylated carboxylate salt has a molecular structure as shown in [I], RO-(AO')n-(AO)mR'-COO-M+ [I] wherein R is a linear, branched, or mixed linear and branched alkyl group having 16 to 36 carbon atoms, AO' is an ethoxy (EO) or propoxy (PO) group, AO is an EO or PO group, R' is a methylene, ethylene, or propylene group, η = 1 - 15, m = 0 - 15, m + n < 20, provided that, in In the case where both PO and EO groups are present, the molar ratio PO / EO is less than 1, and M+ is an alkali metal ion, an alkanolamine ion, an alkylamine ion, or an ammonium ion.ii) increase the apparent viscosity of the vapor, and at the same time decrease the mobility of the vapor, and iii) recover the oil from the underground formation.

10. The method according to claim 9, characterized in that R is a mixture of linear and branched alkyl groups.

11. The method according to claim 9, characterized in that R is a branched alkyl group.

12. The method of claim 10 or 11, characterized in that the branched molecules have an average number of 0.3 to 3.5 branches per molecule, and at least one branch is in the 2-alkyl position.

13. The method of any of claims 9-12, characterized in that both PO and EO are present.

14. The method according to any of claims 9-12, characterized in that AO' is PO. 10 15. The method of any of claims 9-14, characterized in that R is from 20 to 26 carbon atoms.

16. The method according to any of claims 9-15, characterized in that M+ is an alkali metal ion, an alkanolamine ion, or an ammonium ion.