RECOVERY

TECHNICAL FIELD

The present invention relates to the use of a surfactant composition in enhanced oil recovery processes, wherein the surfactant composition generates foam in order to improve conformance (also called profile correction).

TECHNICAL BACKGROUND

Hydrocarbons (such as crude oil) are extracted from a subterranean formation (or reservoir) by means of one or more production wells drilled in the reservoir. Before production begins, the formation, which is a porous medium, is saturated with hydrocarbons.

The initial recovery of hydrocarbons is generally carried out by techniques of“primary recovery", in which only the natural forces present in the reservoir are relied upon. In this primary recovery, only part of the hydrocarbons is ejected from the pores by the pressure of the formation. Typically, once the natural forces are exhausted and primary recovery is completed, there is still a large volume of hydrocarbons left in the reservoir.

This phenomenon has led to the development of enhanced oil recovery (EOR) techniques. Many of such EOR techniques rely on the injection of a fluid into the reservoir in order to produce an additional quantity of hydrocarbons.

The fluid used can in particular be a gas (“gas flooding process"), such as natural gas, methane, nitrogen, carbon dioxide, etc., or an aqueous solution (“ waterflooding process"), such as brine, which is injected via one or more injection wells.

Large amounts of water can also be recovered from the production wells. This is called“produced watef. The produced water can be e.g. discharged to the environment (after treatment) or reinjected into the subterranean formation via the injection wells.

A polymer can also be added to the water to increase its viscosity and increase its sweep efficiency in recovering hydrocarbons (“ polymer flooding process’’). In this case, the produced water contains part of the polymer, which can thus be recovered.

However, in one of the above processes, notably when the subterranean formation comprises low permeability and high permeability zones, the gas or water (due to their high mobility) may by-pass sections of the subterranean formation comprising recoverable oil by entering and moving along other sections or channels (“thief zones") of the subterranean formation, which do not comprise recoverable oil. These thief zones are generally high-permeability zones. The low permeability zones comprising the recoverable oil may therefore remain un-swept. More particularly, as the viscosity of the gas or the water used for oil recovery is low relative to the viscosity of the targeted oil, this may cause viscous fingering and low oil recovery. Furthermore, the low density of gas or the high density of water results in gravity override where the gas rises to the top parts and water sinks to the bottom parts of the porous medium without contacting the targeted oil.

Techniques used to mitigate these issues involve the use of polymer gels (as described for example in document“More than 12 years of experience with a successful conformance-Control polymer gel technology” doi:10.21 18/49315-ms) or cement, which block the thief zones and divert gas or water so that it may flow into the sections comprising the recoverable oil. However, in these cases, the blockage of the thief zones is often permanent and therefore, if the polymer gel or cement enters the sections comprising the recoverable oil, there is a risk that oil production may be permanently shut down.

Furthermore, in order for the polymer gel to be formed, the polymer has to be dissolved in water and to be continuously injected into the subterranean formation. However, this may not be possible in areas where water resources are limited. In addition, another issue that may occur in tight and heterogeneous formations, is that viscous solutions cannot be injected into such formations due to the injectivity limit and the mechanic degradation of the polymer.

Another technique used to limit the issues mentioned above involves the use of surfactants capable of generating foams able to block the thief zones and prevent or limit viscous fingering and gravity override.

However, the selection of appropriate surfactants is difficult.

The article of C. S. Boeije et al. (A methodology for screening surfactants for foam enhanced oil recovery in an oil-wet reservoir), 2017 (doi:10.21 18/185182-pa) describes a surfactant screening methodology for foam enhanced oil recovery in order to rapidly provide a qualitative indication of a surfactant’s foaming potential as well as salinity and oil tolerance at reservoir temperature. Such surfactants include alcohol ethoxy sulfates, alkylpolyglycosides, a-olefin sulfonates, betaines, ethoxylated alcohols, internal olefin sulfonates, ethoxylated nonylphenols.

The article of C. S. Boeije et al. ( SAG foam flooding in carbonate rocks), 2018 (doi: 10.1016/j.petrol.2018.08.017) describes the use of foam in gas injection EOR processes to reduce the mobility of gas, resulting in a greater volumetric sweep preferably by a surfactant alternating gas (SAG) method. The surfactants used are a non-ionic alkylpolyglycoside (APG) surfactant and an anionic alcohol ethoxy sulphate (AES) surfactant.

The article of A. Ocampo et al. ( Successful foam EOR pilot in a mature volatile oil reservoir under miscible gas injection ), 2013 (doi: 10.2523/iptc-16984- ms) describes a field trial of foams as gas injection conformance enhancers by using the SAG method. It was found that an a-olefin sulfonate (AOS) type of surfactant gave the best results.

The article of R. Cao et al. (A new laboratory study on alternate injection of high strength foam and ultra-low interfacial tension foam to enhance oil recovery ), 2015 (doi: 10.1016/j. petrol.2014.1 1 .018) describes a method of alternate flooding through high strength foam and ultra-low interfacial tension foam to enhance oil recovery. According to this method, the high strength foam is generated with a mixture of a petroleum sulfonate surfactant and air while the ultra-low interfacial tension foam is formed with a mixture of non-ionic surfactant, anionic surfactant and air.

The article of J.-X. Shi et al. ( Improved surfactant-alternating-gas foam process to control gravity override) presents a preliminary study in SAG foam processes in order to control gravity override. Simulations of SAG foam processes are described thereof.

The articles of A. Das et al. ( Low tension gas process in high salinity and low permeability reservoirs, 2016, doi: 10.21 18/179839-ms and Laboratory study of injection strategy for low-tension-gas flooding in high salinity, tight carbonate reservoirs, 2018 doi: 10.21 18/190348-ms) describes a low tension gas (LTG) process in tight carbonates which has exhibited good microscopic displacement and mobility control. This method combines interfacial tension reduction with improved mobility control by in-situ generation of foam in low-permeable heterogeneous formations. According to these articles, a first composition comprising an ethoxylated propoxylated carboxylate surfactant, an internal olefin sulfonate (IOS) surfactant, and an ethoxylated sulfonate or a second composition comprising an ethoxylated propoxylated carboxylate surfactant, IOS and an APG surfactant is used to form a “Winsor type III" microemulsion and reduce the interfacial tension while a second composition comprising an APG surfactant or an ethoxylated propoxylated carboxylate surfactant is used to form the foam.

Document WO 2015/135777 concerns the use of foams generated from an aqueous fluid, at least one gas and at least one surfactant in the production of oil and/or gas from subterranean formations. The surfactants are selected from the group of alkyl betains, alkyl N-oxides, amphoteric surfactants, anionically modified alkyl ethers, modified alkyl ethers, alkyl or alkenyl polyglucosides, modified alkyl or alkenyl polyglucosides and alkyl sulfates.

There is still a need for a surfactant composition which makes it possible to generate foam in-situ in a subterranean formation, in a reversible way and under harsh reservoir conditions, notably high temperature, high pressure and a wide salinity range, in order to block specific zones in the subterranean formation and improve hydrocarbon recovery.

SUMMARY OF THE INVENTION

It is the object of the invention to provide the use of a surfactant composition for forming a foam and improving conformance in a subterranean formation, the surfactant composition comprising:

at least one compound of formula (I):

(I) R ¹ -(G)x-0-R ²

wherein:

R ¹ is a hydrogen atom or a linear or a branched alkyl radical having from 1 to 15 carbon atoms;

R ² is a hydrogen atom or a linear or a branched alkyl radical having from 6 to 22 carbon atoms;

G is a sugar unit; and

x is a number from 1 to 10; and

at least one of:

a compound of formula (II):

(II) R ³ -[0-CH ₂ -CH(CH3)]y-(0-CH2-CH2)z-0-CH2-C0 ₂ -M ⁺ wherein:

R ³ is a hydrogen atom or a linear or branched alkyl radical having from 1 to 22 carbon atoms;

y is a number from 0 to 20;

z is a number from 0 to 20; and

M ⁺ is a monovalent cation; and/or a compound of formula (III):

(III)

wherein:

R ⁴ , R ⁵ , R ⁶ , R ⁷ independently are a hydrogen atom or a linear or branched alkyl radical having from 1 to 20 carbon atoms; and

A- is a halogen anion chosen from F Cl-, Br, I-; and wherein the surfactant composition is an aqueous solution which is injected into the subterranean formation.

According to some embodiments, R ¹ is a hydrogen atom.

According to some embodiments, R ² is a linear or branched alkyl radical having from 8 to 20 carbon atoms, and preferably from 8 to 16 carbon atoms.

According to some embodiments, G is chosen from a glucoside unit, a xyloside unit, a sucroside unit and a sorbitan unit, and is preferably a glucoside unit.

According to some embodiments, x is from 1 to 5, and preferably from 1 to 3.

According to some embodiments, R ³ is a linear or branched alkyl radical having from 10 to 20 carbon atoms.

According to some embodiments, y is from 0 to 10.

According to some embodiments, z is from 5 to 15.

According to some embodiments, M ⁺ is selected from H ⁺ , Li ⁺ , Na ⁺ and K ⁺ , and is preferably Na ⁺ .

According to some embodiments, at least one, preferably at least two, and more preferably at least three of the R ⁴ , R ⁵ , R ⁶ , R ⁷ is/are a linear or branched alkyl radical having from 1 to 5 carbon atoms.

According to some embodiments, at least one, preferably at least two, and more preferably at least three of the R ⁴ , R ⁵ , R ⁶ , R ⁷ is/are a methyl radical.

According to some embodiments, at least one of the R ⁴ , R ⁵ , R ⁶ , R ⁷ is a linear alkyl radical having from 10 to 20, and preferably from 10 to 15 carbon atoms.

According to some embodiments, A- is Cl or Br. According to some embodiments, the compound of formula (III) is myristyltrimethylammonium bromide or lauryltrimethylammonium chloride.

According to some embodiments, the surfactant composition comprises an aqueous medium, and the aqueous medium is or derives from produced water, fresh water, aquifer water, formation water and sea water.

According to some embodiments, the aqueous medium has a salinity from 10 to 300 g/L.

According to some embodiments, the concentration of the compound of formula (I) in the surfactant composition is equal to or less than 50000 ppm, preferably equal to or less than 10000 ppm, and more preferably equal to or less than 5000 ppm, by weight.

According to some embodiments, the concentration of the compound of formula (II) in the surfactant composition is equal to or less than 10000 ppm, and preferably equal to or less than 2000 ppm, by weight.

According to some embodiments, the concentration of the compound of formula (III) in the surfactant composition is equal to or less than 10000 ppm, and preferably equal to or less than 2000 ppm, by weight.

According to some embodiments, the foam is formed when the surfactant composition comes into contact with gas injected into the subterranean formation, the gas being preferably chosen from nitrogen, carbon dioxide, natural gas, methane and mixtures thereof.

According to some embodiments, the injection of the gas is carried out simultaneously with the injection of the surfactant composition.

According to some embodiments, the injection of the gas is carried out after the injection of the surfactant composition.

According to some embodiments, the injection of the gas and the injection of the surfactant composition are carried out alternatively more than one time.

According to some embodiments, the surfactant composition is injected into the subterranean formation in a continuous manner.

According to some embodiments, the surfactant composition is injected into the subterranean formation in a discontinuous manner.

According to some embodiments, the surfactant composition is used in a gas flooding process of oil recovery.

According to some embodiments, the surfactant composition is used in a water flooding process of oil recovery.

The present invention makes it possible to address the need mentioned above. In particular, the invention provides a surfactant composition which makes it possible to generate foam in-situ in a subterranean formation, in a reversible way and under harsh reservoir conditions, notably high temperature, high pressure and a wide salinity range, in order to block specific zones in the subterranean formation and improve hydrocarbon recovery.

This is achieved by combining a compound of formula (I) with a compound of formula (II) and/or with a compound of formula (III). In fact, as the solubility of the compound of formula (I) tends to decrease in high temperatures, the use of a second surfactant (compound of formula (II) and/or compound of formula (III)) in combination with the first surfactant (compound of formula (I)) allows an enhancement in the solubility of the compound of formula (I) and therefore allows its use at elevated temperatures.

Furthermore, although the generated foam is strong enough to block thief zones in the subterranean formation, this blockage is not permanent as the foam can be destroyed by injecting compounds such as alcohols. This ensures that the zones comprising the recoverable oil are not at a risk of getting permanently blocked. In fact, the presence of oil may result in the collapse of the foam, which also minimizes the risk of blocking zones comprising high oil saturation.

In addition, the in-situ formation of the foam in the subterranean formation makes it possible to enhance injectivity as the viscous foam is formed directly in the subterranean formation and therefore does not influence the injectivity and the injection of the surfactant composition.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 illustrates the solubility of different surfactants (solutions A to D) as a function of the temperature. The temperature (°C) can be read on the Y-axis.

Figure 2 illustrates the solubility of two surfactant mixtures (solutions E and F) as a function of the temperature. The temperature (°C) can be read on the Y- axis.

DESCRIPTION OF EMBODIMENTS

The invention will now be described in more detail without limitation in the following description.

Surfactant composition

The invention relates to the use of a surfactant composition. The surfactant composition comprises at least one compound of formula (I):

(I) R ¹ -(G)x-0-R ²

R ¹ may be an alkyl radical having from 1 to 15 carbon atoms, and preferably from 1 to 10 carbon atoms. For example, R ¹ may have from 1 to 2 carbon atoms; or from 2 to 4 carbon atoms; or from 4 to 6 carbon atoms; or from 6 to 8 carbon atoms; or from 8 to 10 carbon atoms; or from 10 to 12 carbon atoms; or from 12 to 15 carbon atoms.

R ¹ may be a linear or branched alkyl radical. When R ¹ is branched, it may have a mean degree of branching from 0 to 5. More preferably, R ¹ is linear.

Alternatively, and preferably, R ¹ may be a hydrogen atom.

R ² may be an alkyl radical having from 6 to 22 carbon atoms, preferably from 8 to 20, and even more preferably from 8 to 16 carbon atoms. For example, R ² may have from 6 to 8 carbon atoms; or from 8 to 10 carbon atoms; or from 10 to 12 carbon atoms; or from 12 to 14 carbon atoms; or from 14 to 16 carbon atoms; or from 16 to 18 carbon atoms; or from 18 to 20 carbon atoms; or from 20 to 22 carbon atoms.

R ² may be a linear or branched alkyl radical. When R ² is branched, it may have a mean degree of branching from 0 to 5. More preferably, R ² is linear.

Alternatively, R ² may be a hydrogen atom. However, preferably R ² is an alkyl radical as described above.

In formula (I), G is a sugar unit. The term “sugar unit’ covers monosaccharide units (e.g. based on hexoses or pentoses), disaccharide units, and polyol units. . Preferably, the sugar unit may be chosen from a glucoside unit, a xyloside unit, a sucroside unit and a sorbitan unit. Glucoside is a glycoside derived from glucose. Therefore, when G is a glucoside unit, it has the molecular formula CeHioOs and is a six-membered ring.

When G is a xyloside unit, it is a glycoside derived from xylose which has the molecular formula CsHaCM and may be a five or a six-membered ring.

When G is a sucroside unit, it is a glycoside derived from sucrose which has the molecular formula C ₁₂ H ₂₀ O ₁₀ . Sucrose consists of two monosaccharides: glucose and fructose which are linked together via an ether bond called“glycosidic bond”.

When G is a sorbitan unit, it has the molecular formula C6H ₁₀ O ₄ and is a five-membered ring.

Preferably, G is a glucoside unit.

In formula (I), x may be a number from 1 to 10, preferably from 1 to 5, and more preferably from 1 to 3. Number x corresponds to the number of sugar units. (G)x therefore forms a polysaccharide (preferably a polyglucoside) which is bound to a non-sugar unit.

Number x may be an integer or not (if a mixture of different molecules is used). Therefore, x may be from 1 to 1 .5; or from 1 .5 to 2; or from 2 to 2.5; or from 2.5 to 3; or from 3 to 3.5; or from 3.5 to 4; or from 4 to 4.5; or from 4.5 to 5; or from 5 to 5.5; or from 5.5 to 6; or from 6 to 6.5; or from 6.5 to 7; or from 7 to 7.5; or from 7.5 to 8; or from 8 to 8.5; or from 8.5 to 9; or from 9 to 9.5; or from 9.5 to 10.

The surfactant composition may further comprise at least one compound of formula (II):

(II) R ³ -[0-CH ₂ -CH(CH3)]y-(0-CH2-CH2)z-0-CH2-C0 ₂ -M ⁺

R ³ may be an alkyl radical having from 1 to 22 carbon atoms, and preferably from 10 to 20 carbon atoms. For example, R ³ may have from 1 to 2 carbon atoms; or from 2 to 4 carbon atoms; or from 4 to 6 carbon atoms; or from 6 to 8 carbon atoms; or from 8 to 10 carbon atoms; or from 10 to 12 carbon atoms; or from 12 to 14 carbon atoms; or from 14 to 16 carbon atoms; or from 16 to 18 carbon atoms; or from 18 to 20 carbon atoms; or from 20 to 22 carbon atoms.

R ³ may be a linear or branched alkyl radical. When R ³ is branched, it may have a mean degree of branching from 0 to 5. More preferably, R ³ is linear.

Alternatively, R ³ may be a hydrogen atom. However, preferably R ³ is an alkyl radical as described above.

In formula (II), y may be a number from 0 to 20, and preferably from 0 to 10. For example, y may be from 0 to 2; or from 2 to 4; or from 4 to 6; or from 6 to 8; or from 8 to 10; or from 10 to 12; or from 12 to 14; or from 14 to 16; or from 16 to 18; or from 18 to 20. Number y corresponds to the number of propoxy groups present in the compound of formula (II).

In formula (II), z may be a number from 0 to 20, preferably from 5 to 15. For example, y may be from 0 to 2; or from 2 to 4; or from 4 to 6; or from 6 to 8; or from 8 to 10; or from 10 to 12; or from 12 to 14; or from 14 to 16; or from 16 to 18; or from 18 to 20. Number z corresponds to the number of ethoxy groups present in the compound of formula (II).

Numbers y and z may be integers or not. Namely, if a mixture of different molecules is used, y and/or z correspond to mean degrees of propoxylation and ethoxylation. The mean degree of propoxylation and the mean degree of ethoxylation may be measured by NMR spectroscopy or HPLC/MS.

Preferably, z is higher than y.

M ⁺ is a monovalent cation. M ⁺ may be a hydrogen cation H ⁺ . Alternatively, M ⁺ may be chosen from an alkali metal cation such as Li ⁺ , Na ⁺ , K ⁺ , or an ammonium cation such as NH ₄ ⁺ . Preferably, M ⁺ is chosen from Li ⁺ , Na ⁺ , K ⁺ , and more preferably M ⁺ is Na ⁺ . Therefore, the compound of formula (II) may be present as a free acid or as a salt. Instead of or in addition to the compound of formula (II), the surfactant composition may comprise a compound of formula (III):

(III)

R ⁴ , R ⁵ , R ⁶ and R ⁷ may be independently chosen from a hydrogen atom and an alkyl radical having from 1 to 20 carbon atoms, preferably from 1 to 15 carbon atoms. For example, R ⁴ , R ⁵ , R ⁶ and R ⁷ may independently have from 1 to 2 carbon atoms; or from 2 to 4 carbon atoms; or from 4 to 6 carbon atoms; or from 6 to 8 carbon atoms; or from 8 to 10 carbon atoms; or from 10 to 12 carbon atoms; or from 12 to 14 carbon atoms; or from 14 to 16 carbon atoms; or from 16 to 18 carbon atoms; or from 18 to 20 carbon atoms. Preferably R ⁴ , R ⁵ , R ⁶ and R ⁷ are alkyl radicals.

R ⁴ , R ⁵ , R ⁶ and R ⁷ may be linear or branched alkyl radicals.

In some embodiments, R ⁴ , R ⁵ , R ⁶ and R ⁷ are the same.

According to some preferred embodiments, R ⁴ , R ⁵ , R ⁶ and R ⁷ are different.

According to some embodiments, at least one, preferably at least two, and more preferably at least three of the R ⁴ , R ⁵ , R ⁶ , R ⁷ is/are a linear or branched alkyl radical having from 1 to 5 carbon atoms. This alkyl radical may be for example a methyl radical, or an ethyl radical, or a propyl radical, or an iso-propyl radical, or a butyl radical, or a tert-butyl radical, or an iso-butyl radical, or a pentyl radical or an iso-pentyl group. Preferably, this alkyl radical is a methyl radical.

According to some embodiments, at least one of the R ⁴ , R ⁵ , R ⁶ , R ⁷ is a linear or branched alkyl radical having from 10 to 20 carbon atoms, preferably from 10 to 15 carbon atoms, and more preferably from 12 to 14 carbon atoms. Preferably, it is a linear alkyl radical and more preferably it is a lauryl or myristyl radical (linear C12 or C14 alkyl group).

A- is a halogen anion. A may be chosen from F , Cl-, Brand l . Preferably, A- is Cl or Br. Therefore, the compound of formula (III) may be present as a salt.

According to some preferred embodiments, the compound of formula (III) is myristyltrimethylammonium bromide.

According to other preferred embodiments, the compound of formula (III) is lauryltrimetrylammonium chloride. When the surfactant composition comprises the compound of formula (I) and the compound of formula (II), the weight ratio of the compound of formula (I) to the compound of formula (II) in the surfactant composition may be from 1 :1 to 10 : 1 , and preferably from 3:1 to 6:1 .

When the surfactant composition comprises the compound of formula (I) and the compound of formula (III), the weight ratio of the compound of formula (I) to the compound of formula (III) in the surfactant composition may be from 1 :1 to 10 : 1 , and preferably from 3:1 to 6:1 .

The surfactants described above may be added to and dissolved in an aqueous medium in order to form the surfactant composition. The aqueous medium may be or may derive from produced water, fresh water, aquifer water, formation water and sea water.

According to some embodiments, the aqueous medium may have a salinity from 10 to 300 g/L. For example, the aqueous medium may have a salinity from 10 to 50 g/L; or from 50 to 100 g/L; or from 100 to 150 g/L; or from 150 to 200 g/L; or from 200 to 250 g/L; or from 250 to 300 g/L. Salinity is defined herein as the total concentration of dissolved inorganic salts in water, including e.g. NaCI, CaC , MgCh and any other inorganic salts.

According to some embodiments, the concentration of the compound of formula (I) in the surfactant composition may be equal to or less than 50000 ppm, preferably equal to or less than 10000 ppm, and more preferably equal to or less than 5000 ppm, by weight. The concentration of the compound of formula (I) in the surfactant composition may notably be from 100 to 500 ppm; or from 500 to 1000 ppm; or from 1000 to 5000 ppm; or from 5000 to 10000 ppm; or from 10000 to 15000 ppm; or from 15000 to 20000 ppm; or from 20000 to 25000 ppm; or from 25000 to 30000 ppm; or from 30000 to 35000 ppm; or from 35000 to 40000 ppm; or from 40000 to 45000 ppm; or from 45000 to 50000 ppm, by weight of the surfactant composition.

When the compound of formula (II) is present in the surfactant composition, it may have a concentration in the surfactant composition equal to or less than 10000 ppm, and preferably equal to or less than 2000 ppm, by weight. The concentration of the compound of formula (II) in the surfactant composition may notably be from 50 to 100 ppm; or from 100 to 500 ppm; or from 500 to 1000 ppm; or from 1000 to 1500 ppm; or from 1500 to 2000 ppm; or from 2000 to 2500 ppm; or from 2500 to 3000 ppm; or from 3000 to 3500 ppm; or from 3500 to 4000 ppm; or from 4000 to 4500 ppm; or from 4500 to 5000 ppm; or from 5000 to 5500 ppm; or from 5500 to 6000 ppm; or from 6000 to 6500 ppm; or from 6500 to 7000 ppm; or from 7000 to 7500 ppm; or from 7500 to 8000 ppm; or from 8000 to 8500 ppm; or from 8500 to 9000 ppm; or from 9000 to 9500 ppm; or from 9500 to 10000 ppm, by weight of the surfactant composition.

When the compound of formula (III) is present in the surfactant composition, it may have a concentration in the surfactant composition equal to or less than 10000 ppm, and preferably equal to or less than 2000 ppm, by weight. The concentration of the compound of formula (III) in the surfactant composition may notably be from 50 to 100 ppm; or from 100 to 500 ppm; or from 500 to 1000 ppm; or from 1000 to 1500 ppm; or from 1500 to 2000 ppm; or from 2000 to 2500 ppm; or from 2500 to 3000 ppm; or from 3000 to 3500 ppm; or from 3500 to 4000 ppm; or from 4000 to 4500 ppm; or from 4500 to 5000 ppm; or from 5000 to 5500 ppm; or from 5500 to 6000 ppm; or from 6000 to 6500 ppm; or from 6500 to 7000 ppm; or from 7000 to 7500 ppm; or from 7500 to 8000 ppm; or from 8000 to 8500 ppm; or from 8500 to 9000 ppm; or from 9000 to 9500 ppm; or from 9500 to 10000 ppm, by weight of the surfactant composition.

The surfactant composition may also comprise one or more additives. Such additives may include additional surfactants (other than compounds of formula (I), (II) or (III)), salts, sacrificial agents, mobility control polymers, pH adjustment agents, solvents and mixtures thereof.

Foam formation and hydrocarbon recovery

The surfactant composition described above is used for forming a foam and improving conformance (also called profile correction) in a subterranean formation. Conformance is a measure of the uniformity of the flood front of an injected drive fluid during an oil recovery flooding operation, and the uniformity of the flood front as it is propagated through the subterranean formation.

In other terms, the surfactant composition described above is used to generate a foam, preferably in-situ, in a subterranean formation, which makes it possible to block specific zones (thief zones) in the subterranean formation and improve hydrocarbon recovery.

The subterranean formation comprises zones of high permeability and zones of low permeability. The thief zones are preferably found in the high permeability zones. According to some embodiments, these zones are located proximate to injection well(s).

The subterranean formation may in particular be a carbonate reservoir or a silica reservoir. In case the subterranean formation is a silica reservoir, it is preferable to use the surfactant composition comprising the compound of formula (I) and the compound of formula (II). In case the subterranean formation is a carbonate reservoir, it is preferable to use the surfactant composition comprising the compound of formula (I) and the compound of formula (III).

By "carbonate reservoir ^J ’ is meant a reservoir where the rock mainly comprises CO3 ² minerals, such as calcite, aragonite, dolomite, etc. By "silica reservoir ^J ’ is meant a reservoir where the rock mainly comprises silicate minerals, such as quartz, feldspar, mica, etc.

The foam is generated when the surfactant composition comes into contact with a gas. As the generation of foam preferably occurs in the high permeability zones, the thief zones can be blocked, in order to impede flow of gas or water therethrough. In fact, according to preferred embodiments, the generated foam tends to collapse in low permeability zones comprising recoverable hydrocarbons, therefore ensuring blockage essentially only in high permeability zones.

The gas may be chosen from carbon dioxide, nitrogen, natural gas, hydrocarbons such as methane, ethane, propane or butane, hydrogen sulfide, exhaust gas and mixtures thereof. Preferably the gas is chosen from nitrogen, carbon dioxide, natural gas and methane. More preferably, the gas is chosen from natural gas or methane.

The surfactant composition and the gas are injected into the subterranean formation via one or more injection wells. The surfactant composition and the gas may be injected into the subterranean formation through the same or different injection well(s).

According to some embodiments, the injection of the surfactant composition and the injection of the gas are carried out simultaneously, preferably from the same injection well(s). According to this method, the injection of the surfactant composition and the injection of the gas are carried out in a continuous manner.

According to other embodiments, the injection of the surfactant composition and the injection of the gas are not carried out simultaneously.

Therefore, the surfactant composition may be injected into the subterranean formation continuously for a period of time and then the injection of the surfactant composition may be stopped. After the injection of the surfactant composition is stopped, the gas may be injected continuously into the subterranean formation in order to generate the foam in-situ.

Alternatively, the surfactant composition and the gas are injected alternatively more than one time (surfactant alternating gas). More particularly, a small amount {“slug") of the surfactant composition, may be injected into the subterranean formation, this injection being followed by the injection of a certain amount of gas. Then, another slug of the surfactant composition may be injected into the subterranean formation, also followed by the injection of a certain amount of gas. Therefore, in this case, the alternating injections are carried out in a discontinuous manner.

Alternatively, the foam may be generated before injection, by mixing the surfactant composition with gas before injecting the resulting mixture into the subterranean formation.

The temperature within the subterranean formation, during the generation of foam, may range from 25 to 140°C, preferably from 80 to 140°C and more preferably from 90 to 120°C.

The injection of the surfactant composition may be performed at a pressure from 70 to 300 bar, preferably from 100 to 250 bar.

The injection of the gas may be performed at a pressure from 70 to 300 bar, preferably from 100 to 250 bar.

According to some embodiments, the surfactant composition described above may be used in a waterflooding process. Therefore, once the foam is generated, hydrocarbons may be recovered from the subterranean formation by injecting a brine solution via at least one injection well. As the thief zones are blocked by the foam, the brine solution is forced to flow through the zones devoid of foam, which comprise the recoverable oil, thus improving hydrocarbon recovery ( via one or more production wells).

The brine solution may be or may derive from produced water, fresh water, aquifer water, formation water and sea water.

According to other embodiments, the surfactant composition described above may be used in a gas flooding process. Therefore, once the foam is generated, hydrocarbons may be recovered from the subterranean formation by injecting a gas via at least one injection well. As the thief zones are blocked by the foam, the gas is forced to flow through the zones devoid of foam, which comprise the recoverable oil, thus improving hydrocarbon recovery ( via one or more production wells).

The gas may be chosen from carbon dioxide, nitrogen, natural gas, hydrocarbons such as methane, ethane, propane or butane, hydrogen sulfide, exhaust gas and mixtures thereof. Preferably the gas is chosen from nitrogen, carbon dioxide, natural gas and methane.

In the case of a water or a gas flooding process, as the water or gas flows into the subterranean formation, it comes to contact with the generated foam. After a certain time of contact between the foam and the injected water or gas, the generated foam may have a reduced viscosity compared to the viscosity of the foam when it is generated. Despite its reduced viscosity, the foam is still capable of blocking the thief zones of the subterranean formation.

Therefore, the surfactant composition according to the invention allows to efficiently block the thief zones of a subterranean formation in both water and gas flooding process.

EXAMPLES

The following examples illustrate the invention without limiting it.

In the following examples, several surfactant solutions were prepared by adding a surfactant (500 ppm or 2000 ppm) in a brine solution and agitating this solution to achieve homogeneity. The brine solution used in these examples was sea water comprising 4.84 g/L Na2SC>4, 0.23 g/L NaHCC>3, 1 .89 g/L CaCl ₂ -2H ₂ 0, 14.06 g/L MgCh GHteO and 27.80 g/L NaCI. The surfactant solutions were then heated from 40 to 120°C, with an interval of 10°C in a high-pressure glass tube. The cloudiness of each surfactant solution was examined visually. In case the surfactant solution was as clear as pure water, it was considered that the surfactant was soluble in the solution. Otherwise, the surfactant was considered to be insoluble in the solution. With reference to figures 1 and 2, the surfactant solutions were classified as clear (1 ), slightly hazy (2), hazy (3), cloudy (4) and phase separation (5).

In the following examples, the temperature inside the subterranean formation is considered to be 94°C.

Example 1

With reference to figure 1 , surfactant solution A comprises 2000 ppm of a compound of formula (I), wherein R ¹ is a hydrogen atom, R ² is a C8-C10 linear alkyl radical, and x is 1 .3, surfactant solution B comprises 2000 ppm of a second compound of formula (I), wherein R ¹ is a hydrogen atom, R ² is a C8-C16 linear alkyl radical, and x is from 1 .4 to 1 .5, surfactant solution C comprises 2000 ppm of a compound of formula (II), wherein R ³ is a C16-C18 linear alkyl radical, y is 7, z is 10 and M ⁺ is Na ⁺ , and solution D comprises the brine solution and is devoid of surfactants.

As shown in figure 1 , the solubility of the surfactants decreases in high temperature. None of the surfactants comprised in the surfactant solutions A, B and C is soluble under the conditions of the subterranean formation.

Example 2 In this example, the influence of an additional surfactant on the solubility of the compound of formula (I) was examined. For this reason, and with reference to figure 2, to the surfactant solution B were added 500 ppm of the compound of formula (II) comprised in the surfactant solution C (surfactant solution E), or 500 ppm of a compound of formula (III), wherein R ⁴ is a myristyl group, R ⁵ , R ⁶ and

R ⁷ are methyl groups and A- is Br (surfactant solution F).

As shown in figure 2, the presence of an additional surfactant (compound of formula (II) or compound of formula (III)) makes it possible to increase the solubility of the compound of formula (I) under the conditions of the subterranean formation (solutions E and F compared to solution B) so that it can be used to generate a foam under harsh reservoir conditions.

Example 3

In this example, the surfactant solution E is co-injected with N2 in a porous medium comprising oil. The porous medium has a length of 25 cm and a diameter of 1.0 cm. The experimental conditions and results are listed in the Table below.

Therefore, foam can be generated at reservoir conditions. The foam apparent viscosity was reduced in the gas flooding, but there was still residual foam with 22.4 cP which can block the thief zone.