WO2015135851A1 - Method for co2-flooding using branched c10-alkyl polyalkoxylates - Google Patents

Abstract

The invention relates to a method for extracting crude oil by means of CO₂-flooding, in which a liquid or supercritical CO₂ and at least one branched C₁₀-alkyl polyalkoxylate is injected through at least one injection bore into an oil reservoir and crude oil is extracted from the oil reservoir by means of least one production bore. The branched C₁₀-alkyl polyalkoxylate is preferably dissolved in the CO₂-phase. The invention also relates to a method for extracting crude oil by means of CO₂-flooding in which mixtures of the branched C₁₀-alkyl polyalkoxylates are used with alkyl polyalkoxysulfonates or alkyl polyglucosides.

Description

 C02 flooding process using branched C10-alkyl polyalkoxylates

The invention relates to a method for producing crude oil by means of CO 2 flooding, in which liquid or supercritical CO 2 and at least one branched C 10 -alkylpolyalkoxylate are injected through at least one injection well into a crude oil deposit and the crude oil is removed from the reservoir by at least one production well. The branched Cio-alkylpolyalkoxylate is preferably dissolved in the CO 2 phase. The invention further relates to a process for crude oil production by means of CO 2 flooding, in which mixtures of the branched Cio-alkylpolyalkoxylates with alk (en) ylpolyalkoxysulfonaten and / or alk (en) ylpolyglucosiden used.

In natural oil deposits, petroleum is present in the cavities of porous reservoirs, which are closed to the earth's surface by impermeable cover layers. The cavities may be very fine cavities, capillaries, pores or the like. Fine pore necks, for example, have a diameter of only about 1 μηη. In addition to crude oil, including natural gas, a deposit usually contains more or less saline water. After tapping a petroleum deposit, oil may first flow to the surface by itself through the borehole due to the inherent pressure of the reservoir. The autogenous pressure can be caused by gases present in the deposit such as methane, ethane or propane. This type of promotion is usually referred to as primary oil production. Depending on the type of storage, however, only approx. 5 to 10% of the amount of crude oil available in the deposit can be pumped by means of the primary production, after which the autogenous pressure is no longer sufficient for production. There are also deposits where the autogenous pressure from the beginning is not sufficient for primary production. In order to promote more oil from a deposit, measures of secondary and / or tertiary oil production are used.

In the case of secondary production, in addition to the wells that serve to extract the oil, the so-called production wells, further drillings are drilled into the oil-bearing formation. Through these so-called injection wells water is injected into the reservoir to maintain or increase the pressure. By injecting the water, the oil is slowly forced through the cavities into the formation, starting from the injection well, toward the production well. But this works only as long as the cavities are completely filled with oil and the viscous oil is pushed through the water in front of him. As soon as the thin liquid water passes through cavities breaks, it flows from this time on the path of the least resistance, ie through the channel formed, and no longer pushes the oil in front of him. By means of primary and secondary production, as a rule only about 30-35% of the quantity of crude oil in the deposit can be extracted.

An overview of tertiary oil production can be found, for example, in the "Journal of Petroleum Science of Engineering 19 (1998)", pages 265 to 280. Tertiary oil extraction includes heat processes in which hot water or superheated steam is injected into the reservoir, thereby increasing the viscosity of the oil Tertiary oil extraction also includes processes involving the use of suitable chemicals, such as surfactants or thickening polymers, as an aid to oil production, which can be used to influence the situation towards the end of the flood and thereby promote the capture of crude oil previously held in the rock formation. Furthermore, techniques are known to inject gases such as CO2, N2 or CH ₄ in the formation to increase the oil production.

In so-called C02 flooding, liquid or supercritical CO2 is injected through one or more injection wells into a petroleum formation, flows from there to production wells, and mobilizes existing oil in the formation. The production wells are extracted from mobilized petroleum. This technology is also known as "CO2 enhanced oil recovery (EOR)" or "CO2 improved oil recovery (IOR)" and has great economic importance: Currently, more than 5% of US crude oil production is produced by C02 floods (RM Enick, DK Olsen, "Mobility and Conformance Control for Carbon Dioxide Enhanced Oil Recovery (CO2-EOR) via Thickeners, Foams, Gels - A Detailed Literature Review of 40 Years of Research", page 910, SPE 154122, 18 ^th SPE Improved Oil Recovery Symposium , Tulsa, Oklahoma, USA, April 14 - 18, 2012, Society of Petroleum Engineers, 2012) Several mechanisms account for the increased production of oil by pumping liquid or supercritical CO2 into a deposit: CO2 is soluble in, and therefore low in, petroleum It is self-evident that lower viscous oil can be pumped better than highly viscous oil, and the CO2 dissolved in the oil will continue to swell the oil and make it lean a cohesive oil bank. Another delivery mechanism may be the dissolution of preferably light levels of the crude into the CO2 phase, rather than a type of extraction. Another aspect is the low interfacial tension between crude oil and liquid or supercritical CO2, which helps overcome capillary forces: an oil droplet can more easily deform in a C02 phase and pass through narrow pore necks than it could in a water phase. When pumping CO2 into a reservoir, pressure and temperature determine its physical state. The critical point of CO2 is 30.98 ° C and 73.75 bar. Above these values, CO2 is supercritical, ie it is almost as dense as a liquid but still has a very low viscosity similar to that of a gas. The viscosity of supercritical CO2 is typically several orders of magnitude lower than that of the oil in the reservoir.

The low viscosity of supercritical CO2 is one of the key problems of C02 flooding, making mobility mobility of CO2 in the reservoir much more difficult. To achieve a good de-oiling effect, the CO2 should flow in a uniform front from the injection well towards the production wellbore, flowing through all (still) oil filled areas of the formation. However, this is rarely the case in practice. On the one hand, the porosity of an underground oil deposit is generally not homogeneous, and in addition to fine-pored areas, an underground petroleum formation may also have areas of high porosity, cracks or fractures. Furthermore, even with the same porosity, the flow resistance for CO2 still filled with oil areas of the formation is significantly greater than the flow resistance of already de-oiled areas. Thus, there is a risk that the injected CO2 does not flow through oil-filled areas of the formation at all, but flows largely ineffectively through regions of low flow resistance directly from the injection to the production well. This effect is also called "fingering" and is shown schematically in Figure 1. The "breakthrough" of CO2 to the production well reduces the efficiency of C02 flooding significantly, because a more or less large part of the injected CO2 flows through the formation largely without Effect. Either you have to provide more CO2, or the extracted CO2 must be separated after the extraction of oil or formation water, purified, and compressed again so that it can be re-injected.

On the other hand, the density of liquid or supercritical CO 2 is significantly lower than the density of crude oil and formation water. Therefore, due to buoyancy forces, CO2 preferably accumulates in the upper layers of the formation or preferably flows through the upper layers. The de-oiling is thus preferably carried out in the upper layers of the formation, while deeper layers are not detected by the CO2.

Various approaches have been proposed in the art to achieve CO2 flow through oil reservoirs more uniformly, both horizontally and vertically. For example, it has been proposed to alternately inject water and CO2 into the petroleum formation. The so-called "Water Alternating Gas" process (described by DW Green and GP Willhite in "Enhanced Oil Recovery" SPE Textbook Series Vol. 6 of 1998) is an established process for CO2 flooding.

It has also been proposed to thicken the injected CO2 to adjust the viscosity of the CO2 to the viscosity of the petroleum. For example, US Pat. No. 4,852,651 proposes the addition of certain polysilicon. Huang et al., Macromolecules, 2000, Vol. 33 (15), pages 5437 to 5442, suggest the use of styrene-fluoroacrylate copolymers. However, the moderate solubility of many polymers in CO2 and the high addition of another solvent make the process seem not economical.

In another known technique, suitable surfactants are used to form CC n-water emulsions or CC n-water foams in the deposit of CO 2 and formation water and / or injected water. In CC n-water emulsions, the CO2 is in a discontinuous phase, while water forms the continuous phase. Such emulsions have a significantly higher viscosity than supercritical or liquid CO2 and thus no longer follow only the paths of least flow resistance, but flow much more uniformly through the formation. Mobility control by formation of C02-in-water emulsions allows for increased exploitation of the deposit through macroscopic displacement (mobility control) and microscopic displacement (interfacial tension)

The requirements for surfactants for CO 2 flooding are clearly different from requirements for surfactants for other applications, for example detergent applications; however, they also differ, in particular, from the requirements for surfactants for surfactant flooding, i. an EOR technique that injects aqueous solutions of surfactants but no CO2 into the deposit.

The primary role of surfactants in surfactant flooding is to reduce the interfacial tension between water and petroleum. Thus, petroleum droplets trapped in the formation are mobilized.

The primary role of surfactants in C02 flooding to form C02-in-water emulsions, however, is to stabilize the C02-water interfaces to generate long-term stable CC n-water emulsions in the deposit. The hydrophobic radicals of the surfactants protrude into the liquid or supercritical CO 2 phase and must therefore have good interaction with the CO 2 in order to ensure good stabilization of the CO 2 -water interface. Furthermore, the formation of CC n-water emulsions at the usual reservoir temperatures (typically about 15 ° C to 130 ° C) and in the presence of highly saline water, especially in the presence of high levels of calcium and / or magnesium ions guaranteed be. If the highly viscous CC n-water emulsion collapses, the low-viscosity supercritical CO 2, as described above, preferably follows the paths of lowest flow resistance and / or accumulates in the upper regions of the formation.

In addition, suitable surfactants must also be sufficiently soluble and sufficiently stable in reservoir water and / or injected water. The water is acidic due to dissolved CO2 (pH values of approx. 3). Suitable surfactants must therefore be soluble in an acidic environment and have sufficient long-term stability against hydrolysis. Surfactants such as alkyl sulfates or alkyl ether sulfates which are popular for surfactant flooding are therefore less suitable for CO 2 flooding since, on the one hand, they become less soluble by protonation and the sulfate group can be split off hydrolytically under the conditions mentioned. Amide group-containing compounds also tend to hydrolyze under the conditions mentioned.

Finally, the adsorption tendency of the surfactants on the rock should be as low as possible in order to minimize the loss of surfactant.

The prior art has already proposed a large number of surfactants for various techniques of CO 2 flooding. US 3,342,256 describes the improvement of oil production with the aid of CO2 and a surfactant for mobility control. The surfactant may optionally be injected via the CO2 phase or via the water phase. Suitable surfactants include octylphenol ethoxylates, dioctylsulfosuccinate sodium salt, laurylsulfate sodium salt or isopropylnaphthalenesulfonate sodium salt.

US Pat. No. 4,113,011 1 describes a process for oil extraction with injection of CO2 and an aqueous surfactant solution. The surfactant disclosed is an alkyl ether sulfate of the RO-EO sulfate type, which is composed of an alcohol having 9 to 11 carbon atoms and 1 to 5 EO units. Reference is made to a higher salt tolerance compared to the use of alkyl sulfates. However, sulfates are not sufficiently stable in the long term to hydrolysis under the conditions of CO 2 flooding.

No. 4,380,266 describes a process for the extraction of crude oil by injection of a mixture of CO 2 and EO-PO block polymers or alkyl ethoxylates or alkylphenol ethoxylates or alkyl alkoxylates, the conditions being selected so that the CO 2 is liquid under the reservoir conditions. As an example, Polytergent ^® Called SL-62. This is a linear alcohol of 6 to 10 carbon atoms, which is propoxylated and ethoxylated.

US 4,637,466 describes the use of alkyl ether carboxylates of the type RO- (AO) x R'COOM for CO 2 flooding, wherein R is a linear or branched alkyl radical having 8 to 24 carbon atoms, AO ethylene oxide or propylene oxide, R 'is a methylene or ethylene radical and x is a number from 3 to 1 1 stands.

US 5,033,547 discloses a process for oil recovery by injecting a mixture of CO 2 and a surfactant into a petroleum formation, forming an emulsion of CO 2, water and the surfactant in the formation together with formation water. The surfactants are alkyl ethoxylates or alkylphenol ethoxylates which have a hydrophobic group having 7 to 15 carbon atoms and a degree of ethoxylation of 4 to 8.

DE 30 454 26 A1 discloses the improvement of oil production by the injection of gaseous CO2 and surfactant to form a foam.

US 5,046,560 discloses a method for oil production with injection of a gas selected from the group of hydrocarbons, inert gases, steam or carbon dioxide and an aqueous Alkylarylpolyalkoxysulfonat solution. The sulfonate group is located on the aryl radical.

DE 32 086 62 A1 discloses a process for oil extraction by injection of a formulation comprising water, CO2 and nonionic surfactants. As examples of surfactants, alcohol ethoxylates based on octylphenol, nonylphenol or C 12 -C 15 -alcohol are mentioned.

US Pat. No. 7,842,650 describes a process for producing crude oil, which comprises producing foams from liquids using a surfactant mixture from a foaming agent (a) selected from the group of sulfates, sulfonates, phosphates, carboxylates, sulfosuccinates, betaines, quaternary ammonium salts, amine oxides, amines - Nethoxylaten, amide ethoxylates, acid ethoxylates, alkyl glucosides, EO-PO block copolymers and long-chain fatty alcohol ethoxylates and a cosurfactant (b) of the general formula RO- (AO) _y -H or RO- (AO) _y -Z, where R is a hydrocarbon radical with 6 to 12 carbon atoms, (AO) _{y is} an alkyleneoxy block, y is a number from 5 to 25 and Z is an anionic group (eg sulfate, sulfonate or carboxylate). As an example of a formulation with increased foaming, mention is made of the mixture of cocoamidopropylbetaine with Cio-Guerbet alcohol - 14 EO. The process is preferably a process of tertiary mineral oil extraction. WO 2010/044818 A1 describes a process for producing oil by C0 ₂ fl ows by injecting a nonionic surfactant having a CO 2 Philicity of 1.5 to 5.0 into the formation, wherein the surfactant is to form a stable foam with formation water but not an emulsion with crude oil. Preferably, the nonionic surfactant has the formula RO- (AO) x- (EO) _y -H, where AO is an alkoxy group having 3 to 10 carbon atoms and EO is ethoxy groups, wherein for R, AO, x and y are the following can be selected:

 R AO x y branched alkyl, alkylaryl or cycloalkyl C3 1, 5 - 1 1 6 - 25th

Rest with 3 to 1 1 carbon atoms C ₄ to C10 1 - 2 6 - 25 linear alkyl residue with 3 to 6 carbon atoms C3 4 - 1 1 6 - 25

Particularly preferred is the use of surfactants selected from the group of C ₈ Hi7- (PO) ₅ - (EO) ₉ -H, C ₈ Hi ₇ - (PO) ₅ - (EO) ii -H, C ₈ Hi7- ( PO) 9- (EO) ₉ -H,

C ₆ Hi3- (PO) ₅ - (EO) ii-H, C ₆ Hi3- (PO) ₅ - (EO) ₃ -H i, C Hi _{9 9} - (PO) ₄ - (EO) ₈ -H or Mixtures thereof.

RM Enick, DK Olsen, "Mobility and Conformance Control for Carbon Dioxide Enhanced Oil Recovery (CO2-EOR) via Thickeners, Foams, Gels - A Detailed Literature Review of 40 Years of Research", page 910, SPE 154122, 18 ^th SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, April 14-18, 2012, Society of Petroleum Engineers, 2012, pages 71-73, cites a study to determine the C02 solubility of various surfactants, including one more ethoxylated with 8 or 9 EO units Cio-guerbet alcohol.

WO 201 1/005246 A1 describes surfactants for crude oil production, which can be injected with C0 ₂ and water into a deposit. The nonionic surfactants are glycerol derivatives, two of the alcohol groups of the glycerol being blocked by a hydrocarbon radical which may comprise from 4 to 18 carbon atoms. The third alcohol group can be ethoxylated, propoxylated or butoxylated and have a degree of alkoxylation of 9-40.

WO 201 1/152856 A1 discloses a method for oil production with the aid of supercritical CO2 and a surfactant which is injected into a CO 2 stream and dissolved in the CO 2. The reservoir is made up of reservoir water, surfactant and CO2 to form an emulsion. For example, nonionic surfactants (eg, alkylphenol ethoxylates), cationic surfactants (such as ethoxylated tallow fatty amine), anionic surfactants (eg, alkyl ether sulfates), or betaine surfactants are used. WO 2012/170835 A1 claims a process in which a nonionic surfactant formulation having a pour point of from -3 to -54 ° C. is used, dissolved in CO 2 and dissolved in CO 2 the formation is injected with water to form emulsions. To lower the pour point, alcohols such as methanol, ethanol, glycol or glycol ethers are proposed. WO 2013/043838 A1 describes an oil production process with liquid or supercritical surfactant and an alkoxylated amine which is based on a secondary alkyl radical having 4 to 30 carbon atoms.

WO 2013/048860 A1 describes a process for crude oil production which claims the use of CO 2 and an alkyl alkoxylate which is based on a branched alkyl radical having 3 to 9 carbon atoms and the alkoxylation by means of double metal cyanide catalysis

Tertiary oil production by means of C02 flooding is a large-scale process. Although the surfactants are only used as dilute solutions in water or CO2, the volumes injected per day are high and the injection is typically continued for months to several years. The surfactant requirement for an average oil field can be about 2000 to 3000 t / a. Even a slightly better surfactant can significantly increase the efficiency of C02 flooding.

As described above, the CO 2 flooding is said to form a viscous C02-in-water emulsion. In the C02-in-water emulsion, water forms the continuous phase and thus acts as a buffer between discrete CO 2 phases. If the CO 2 -in-water emulsion loses water, eventually it will cause the discrete CO 2 phases to unite, i. the C02-in-water emulsion breaks down. Deterioration of the emulsion in the petroleum formation is highly undesirable because the higher viscosity of the emulsion compared to a pure CO 2 phase is required to avoid "fingering." It was an object of the invention to provide an improved process for CO 2 flooding for petroleum - To provide stores where the most stable C02-in-water emulsions are formed.

Surprisingly, it has been found that this goal can be achieved by the use of branched Cio-alkylpolyalkoxylaten for CO 2 flooding.

Accordingly, a process for oil production by means of C02 flooding has been found, in which liquid or supercritical CO2 and at least one nonionic surfactant (I) or a surfactant mixture comprising at least one nonionic surfactant (I) is injected through at least one injection well into an oil reservoir and the deposit by at least one production well extracts crude oil, wherein the at least one surfactant (I) or the surfactant mixture comprising at least one surfactant (I) is dissolved in liquid or supercritical CO2 and injected and / or dissolved in an aqueous medium and injected, and wherein the deposit has a shelf temperature of 15 ° C to 140 ° C and the deposit water has a salinity of 20,000 ppm to 350000 ppm, and that it is the at least one nonionic surfactant is a branched alkylpolyalkoxylate of the general formula

R - (OCR ² R ³ CR ⁴ R ⁵⁾ x (OCH ₂ CH R ⁶⁾ _y - (OCH ₂ CH 2) z-OH (I) acts, wherein

R ^{1 is} a branched alkyl radical of the formula C 5 Hn-CH (C 3 H ₇ ) -

CH 2 -, and wherein at least 70 mol% of the radicals C 5 H 11 - is an n-CsHu radical,

R ² , R ³ , R ⁴ , R ^{5 are} each H or a linear or branched alkyl radical

From 1 to 8 carbon atoms, with the proviso that the sum of the carbon atoms of the radicals R ² + R ³ + R ⁴ + R ^{5 is} 2 to 8,

R ⁶ for methyl,

 x for a number from 0 to 5

 y is a number from 1 to 15

z is a number from 1 to 30 wherein the radicals -OCR ² R ³ CR ⁴ R ⁵ -, -OCH 2 CHR ⁶ - and -OCH ² CH ² - are arranged in the order given in formula (I), and wherein the sum of x + y + z stands for values from 5 to 35, with the proviso that z> (x + y).

List of pictures:

Figure 1: Schematic representation of fingering in C02 flooding.

Figure 2: Schematic representation of the high pressure reactor with viewing windows used for the examples and comparative examples.

Figure 3: View through the viewing window of the high-pressure reactor before mixing: C02 phase and water phase (schematic representation).

Figure 4: View through the inspection window of the high-pressure reactor after the see: CX phase, CC n-water emulsion and water phase (schematic representation).

More specifically, the following is to be accomplished for the invention:

In the process according to the invention for crude oil production by means of CO 2 flooding, liquid or supercritical CO 2 and at least one nonionic surfactant (I) are injected into a crude oil deposit. In addition to the at least one nonionic surfactant (I), other surfactants and other components can be used. In a preferred embodiment of the invention, the nonionic surfactants (I) are used in combination with various nonionic surfactants (II) and / or anionic surfactants (III) thereof.

Nonionic surfactants (I)

The nonionic surfactants (I) are branched alkylpolyalkoxylates of the general formula (I)

R - (OCR ² R ³ CR ⁴ R ⁵⁾ x (OCH ₂ CHR ⁶⁾ _y - (OCH ₂ CH 2) z-OH (I).

R ¹ is a branched alkyl radical of the formula

C5Hii-CH (C3H ₇₎ -Cl-L2, where it is an n-CsHu residue at least 70 mol% of the pentyl C5H11-. The substituent in 2-position, the propyl radical C3H7- may be in an n-C3H ₇ group or an i-C3H ₇ act radical. It is preferably an n-C3H ₇ radical. The pentyl radicals which are not n-pentyl radicals are preferably branched 1-alkyl radicals, preferably a 2-methyl-1-butyl radical C2H ₅ CH (CH 3) Cl-12 and / or a 3-methyl radical. 1-butyl radical

In one embodiment of the invention, 70 to 99 mol% of the C5H11- radicals are n-C5Hn radicals, and from 1 to 30 mol% of the C5H11 radicals are C ₂ H ₅ CH (CH ₃ ) CH ₂ radicals and / or CH ₃ CH (CH ₃ ) CH ₂ CH ₂ radicals.

In a further embodiment of the invention, R ¹ is a 2-propyl-n-heptyl radical

In the formula (I), furthermore, the radicals R ² , R ³ , R ⁴ and R ⁵ are each independently H or a linear or branched alkyl radical having 1 to 8 carbon atoms, for example methyl, ethyl or propyl radicals, with the proviso in that the sum of the carbon atoms of the radicals R ² + R ³ + R ⁴ + R ^{5 is} 2 to 8, preferably 2 or 3 and particularly preferably 2. In one embodiment of the invention is the Sum R ² + R ³ + R ⁴ + R ⁵ = 2, wherein at least 70 mol%, preferably at least 80 mol% and particularly preferably at least 95 mol% of the units -OCR ² R ³ CR ⁴ R ⁵ - R ² , R ³ and R ^{4 are} H and R ^{5 is} ethyl. Preference is given to -OCR ² R ³ CR ⁴ R ⁵ - that is, a butoxy group, particularly preferably a butoxy group, which is derived essentially from 1, 2-butene oxide.

R ⁶ is methyl, -OCH 2 CHR ⁶ - is thus a propoxy group and -OCH 2 CH 2 - an ethoxy group. The index x stands for a number from 0 to 5, preferably 0, the index y for a number from 1 to 15, in particular 1 to 9, preferably 3 to 9, for example 4 to 6 and the index z for a number from 1 to 30, preferably 2 to 20, more preferably 5 to 18, for example 8 to 16, wherein the sum of x + y + z is 5 to 35, preferably 8 to 29, for example 10 to 25.

The indices x, y and z are furthermore selected with the proviso that z> (x + y), preferably z> (x + y) and particularly preferably z> 2 (x + y). Thus, not less ethoxy groups should be present than alkoxy groups and propoxy groups if they are present.

It will be clear to one skilled in the art of polyalkoxylates that some distribution of chain lengths will be obtained upon alkoxylation, and that x, y and z will therefore be averages over all molecules, hence x, y and z are not natural Numbers but rational numbers. A distribution of chain lengths can be described in a manner known in principle by the so-called polydispersity D. D = M _w / M _n is the quotient of the weight average molecular weight and the number average molar mass. The polydispersity can be determined by means of the methods known to the person skilled in the art, for example by means of gel permeation chromatography.

It is further clear to the person skilled in the art that the orientation of the propoxy and / or butoxy groups depends on the reaction conditions -OCR ² R ³ CR ⁴ R ⁵ - or -OCH 2 CHR ⁶ - or else -OCR ⁵ R ⁴ CR ³ R ² -b. -OCHR ⁶ CH ₂ - can be. The representation in formula (I) makes no statement as to the orientation of the alkoxy units.

In the above formula (I), the radicals -OCR ² R ³ CR ⁴ R ⁵ -, -OCH 2 CHR ⁶ - and -OCH ² CH ² - are arranged in the order given in formula (I), the transition between the blocks being abrupt or gradual can. However, it is known to the person skilled in the art that small residues of alkylene oxides can remain in the course of an alkoxylation. After addition of the next alkylene oxide, these can then in the second As a rule, at least 90% of the above radicals are arranged in the order indicated in formula (I), ie at least 90% of the radicals are also present in the " right "block.

The preparation of the surfactants (I) is carried out by alkoxylation of branched, aliphatic alcohols R ¹ OH with -soof existing alkylene oxides having 4 to 10 carbon atoms, preferably butylene oxide, propylene oxide and ethylene oxide, wherein the alkylene oxides are used in the order mentioned.

If butylene oxide is used, in principle all isomers, 1, 2-butene oxide, 2,3-butene oxide or isobutene oxide can be used. Preference is 1, 2-butene oxide. It is also advantageous to use technical mixtures which comprise, as main component 1, 2-butene oxide and, in addition, further butene oxide isomers. In particular, mixtures may be used which comprise at least 70 mol%, preferably at least 80 mol% and particularly preferably at least 95 mol% of 1,2-butene oxide.

Alcohols R ¹ OH have the general formula C5HnCH (C3H ₇₎ CH20H, wherein C5H11- C3H7- and have the abovementioned meaning, including the above preferred definition.

Alcohols R ¹ OH are obtainable by methods known in the art. They can be prepared by aldol condensation of valeraldehyde and subsequent hydrogenation. The preparation of valeraldehyde and the corresponding isomers is carried out by hydroformylation of butene, as described for example in US 4,287,370; Beilstein E IV 1, 32 68, Ullmann's Encyclopedia of Industrial Chemistry, 5th Edition, Volume A1, pages 323 and 328 f. The subsequent aldol condensation is described, for example, in US Pat. No. 5,434,313 and Römpp, Chemie Lexikon, 9th edition, keyword "aldol addition" on page 91. The hydrogenation of the aldol condensation product follows general hydrogenation conditions.

Alcohols R ¹ OH can furthermore be prepared from 1-pentanol by means of the Guerbet reaction. For this purpose, technical 1-pentanols can be used, which usually contain certain amounts of methyl-1-butanols. In the Guerbet reaction, the 1-pentanols are reacted in the presence of KOH at elevated temperatures, see eg Marcel Guerbet, CR. Acad Sei Paris 128, 51 1, 1002 (1899), Rompp, Chemie Lexikon, 9th edition, Georg Thieme Verlag Stuttgart, and the literature mentioned there and Tetrahedron, Vol 23, pages 1723-1733. In one embodiment of the invention is used as the alcohol R ¹ OH C ₅ HiiCH (C3H ₇ ) CH20H, wherein for 70 to 99 mol% of the alcohol C5H11- has the meaning n-CsHn- and for 1 to 30 weight percent of the alcohol C5H11- the Meaning C2H ₅ CH (CH ₃ ) CH ₂ - and / or CH ₃ CH (CH ₃ ) CH ₂ CH ₂ - has. Such alcohols are commercially available.

In a further embodiment of the invention, R ¹ OH is 2-propylheptanol-1 HsCCHzCHzCHzCHzCHtn-CsH ^ CHzOH. The execution of the abovementioned alkoxylation is known in principle to the person skilled in the art. It is also known to the person skilled in the art that the reaction conditions, in particular the choice of catalyst, can influence the molecular weight distribution of the alkoxylates. Thus, the surfactants according to the general formula (I) can be prepared, for example, by base-catalyzed alkoxylation. In this case, the alcohol R ¹ OH in a pressure reactor with alkali metal hydroxides, preferably potassium hydroxide, sodium hydroxide, alkaline earth metal or with alkali metal, such as sodium methylate, are added. By reducing the pressure (for example <100 mbar) and / or increasing the temperature (30 to 150 ° C.), water or methanol still present in the mixture can be removed. The alcohol is then partly present as the corresponding alkoxide. The mixture is then inertized with inert gas (for example nitrogen) and the alkylene oxide (s) is added stepwise at temperatures of 90 to 180 ° C up to a maximum pressure of 10 bar. According to one embodiment, the alkylene oxide is initially metered in at 120.degree. In the course of the reaction, the temperature rises up to 170 ° C due to the released heat of reaction. The delay between injection of the various alkylene oxides can be shortened in one embodiment, so that the last injected alkylene oxide is not fully reacted and formed by the newly injected alkylene oxide mixing blocks with small amounts of previously added alkylene oxide. If present, butylene oxide can be added first at a temperature in the range of 125 to 145 ° C, then the propylene oxide at a temperature in the range of 125 to 145 ° C and then the ethylene oxide at a temperature in the range of 120 to 155 ° C. In the case of the absence of butyleneoxy units in the molecule, first propylene oxide and then ethylene oxide are metered in. At the end of the reaction, the catalyst can be neutralized, for example by addition of acid (for example acetic acid, citric acid or phosphoric acid) and filtered off if necessary.

The alkoxylation of the alcohols R ¹ OH can of course be carried out by other methods, for example by acid-catalyzed alkoxylation. Furthermore, for example, double hydroxide clays, as described in DE 4325237 A1, or double metal cyanide (DMC) catalysts can be used. Suitable DMC catalysts are disclosed, for example, in DE 10243361 A1, in particular in sections [0029] to [0041] and in the literature cited therein. For example, Zn-Co type catalysts can be used. To carry out the reaction, the alcohol R ¹ OH is admixed with the catalyst, the mixture is dehydrated as described above and reacted with the alkylene oxides as described. It is usually not more than 1000 ppm catalyst used with respect to the mixture and the catalyst may remain in the product due to this small amount. The amount of catalyst may typically be less than 1000 ppm, for example 250 ppm or 100 ppm or less.

Nonionic Surfactants (II) In addition to the surfactants (I), various nonionic surfactants (II) can optionally be used for the process according to the invention. The nonionic surfactants (II) are alk (en) ylpolyglucosides of the general formula (II)

In formula (II) R ^{7 is} a linear or branched, saturated or unsaturated aliphatic hydrocarbon radical having 8 to 22, preferably 8 to 18 and particularly preferably 8 to 14 carbon atoms, R ^{8 is} a sugar unit having 5 or 6 carbon atoms, ie residues derived from pentoses or hexoses and p is a number from 1 to 5.

Examples of hexoses include allose, altrose, glucose, mannose, gulose, idose, galactose or talose, examples of pentoses ribose, arabinose, xylose or lyxose. Glucose or xylose are preferred, glucose is particularly preferred.

The subscript p of the formula (II) represents a number from 1 to 5 and the index indicates the degree of polymerization. It is clear to the person skilled in the art that p is an average over different single molecules, p is accordingly a rational number. The index p is preferably 1 to 2, for example 1.2 to 1.7.

In a preferred embodiment of the invention, the radicals R ⁷ are linear alkyl and / or alkenyl radicals having 8 to 22, preferably 8 to 18 and particularly preferably 8 to 14 carbon atoms. The surfactants according to the general formula (II) can in a manner known in principle by acid-catalyzed reaction of corresponding alcohols R ⁴ OH with Be made sugar with removal of the water of reaction. The preparation is known in principle to the person skilled in the art. Exemplary descriptions can be found inter alia in US 3,547,828 or US 5,898,070 again. In a preferred embodiment, fatty alcohols, ie alcohols derived from natural fats or oils, can be used to prepare the surfactants (II). This is often a mixture of different alcohols and, accordingly, the surfactants (II) are a mixture of surfactants with different R ⁷ residues.

In one embodiment, alk (en) yl polyglucosides (II) in which the radicals R ^{7 are} derived from coconut oil. In this case, n-dodecyl and n-tetradecyl are the main components, besides also octyl, decyl, hexadecyl and Oleylres- te are present in smaller quantities. Anionic surfactants (III)

In addition to the surfactants (I), it is also possible optionally to use anionic surfactants (III) for the process according to the invention. The anionic surfactants (III) are alk (en) ylpolyalkoxysulfonates of the general formula

R ⁹ - (OCR ² R ³ CR ⁴ R ⁵⁾ i (OCH ₂ CHR ⁶⁾ _m - (OCH ₂ CH 2) n OR ¹⁰ -SO3- V _a M ^{a +} (III).

In the formula (III), R ² , R ³ , R ⁴ , R ⁵ and R ^{6 have} the abovementioned meaning and the preferred ranges given.

R ⁹ is a branched or linear, saturated or unsaturated aliphatic hydrocarbon radical having 8 to 22 carbon atoms, preferably 8 to 18 carbon atoms, particularly preferably 8 to 14 carbon atoms. In one embodiment of the invention, R ^{9 has} the same meaning as R ¹ , including the preferred ranges of R ¹ .

R ¹⁰ is an alkylene radical having 2 to 4 carbon atoms, in particular a linear 1, ω-alkylene radical, which may optionally be substituted by an OH group. It is preferably a group selected from the group of 1, 2-ethylene groups -CH ₂ -CH ₂ -, 1, 2-propylene groups -CH ₂ -CH (CHs) - or -CH (CH ₃ ) -CH ₂ -, 1, 3-propylene groups -CH ₂ -CH ₂ -CH ₂ - or a substituted 1, 3-propylene group -CH ₂ -CH (OH) -CH ₂ -. Furthermore, I is a number from 0 to 5, preferably 0, m is a number from 0 to 15, preferably 0 to 9 and n is a number from 5 to 30, preferably 5 to 20 and the sum of I + m + n is from 5 to 35, preferably from 8 to 29. The indices I, m and n are furthermore selected with the proviso that n> (l + m), preferably n> (l + m) and particularly preferably n> 2 (l + m). Thus, not less ethoxy groups should be present than alkoxy groups and propoxy groups if they are present. The values I, m and n are of course average values. Please refer to the illustration for surfactant (I).

The radicals -OCR ² R ³ CR ⁴ R ^{5 "} , -OCH ₂ CHR ³ - and -OCH ₂ CH ₂ - are arranged blockwise in the order given in formula (III), wherein the transitions between the blocks - as already elsewhere described continuously or abruptly.

In the case of the cation M ^{a +} , a is 1, 2 or 3, preferably 1 or 2. Particularly preferred is a = 1, ie it is a monovalent cation, for example alkali metal ions, ammonium ions, the ammonium ions also having organic radicals can. Examples of monovalent cations include Na ⁺ , K ⁺ , NH ₄ ⁺ , NMe ₄ ⁺ or NBu ₄ ⁺ .

In a preferred embodiment of the invention, R ^{9 has} the same meaning as R ¹ , including the preferred ranges of R ¹ and for the indices I, m, and n holds I = x, m = y and n = z, where x, y and z can take the values defined above, including the preferred ranges.

Examples of preferred anionic surfactants (III) include R ¹ - (EO) i ₄ -CH ₂ CH ₂ CH ₂ -SO ₃ M, R - (PO) ₅ - (EO) i ₅ -CH ₂ CH ₂ CH ₂ -SO ₃ M, RMPO) ₃ - (EO) 8 -CH ₂ CH ₂ CH ₂ -SO ₃ M, R ¹ - (PO) ₃ - (EO) 9-CH ₂ CH ₂ CH ₂ -SO ₃ M, R - (PO) ₅ - (EO) 9 -CH ₂ CH ₂ CH ₂ -SO 3 M,

R ¹ - (EO) io-CH ₂ CH ₂ CH2-S03M, iCi ₃ H27- (EO) io-CH 2 CH ₂ CH2-S03M,

iCi ₃ H27- (EO) i ₅ -CH 2 CH 2 CH 2 -SO ₃ M, iCi ₃ H 27- (EO) i 8 -CH ₂ CH 2 CH ₂ -SO ₃ M,

iCi ₃ H ₂ 7- (EO) 25 -CH 2 CH ₂ CH 2 S0 ₃ M, iCi ₃ H27- (EO) ₃ O-CH ₂ CH ₂ CH 2 S0 ₃ M,

iCi ₃ H ₂ 7- (EO) ₃ 7 -CH ₂ CH ₂ CH ₂ -SO ₃ M, n (Ci ₂ H ₂ 5Ci ₄ H29) - (EO) 7 -CH ₂ CH ₂ CH ₂ -SO ₃ M, n (Ci ₂ H ₂ 5 / Ci ₄ H29) - (EO) i ₅ -CH ₂ CH ₂ CH ₂ -SO ₃ M or

n (Ci2H ₂ 5 / C ₄ H29) - (EO) 28 -CH 2 CH ₂ CH 2 S0 ₃ M.

The preparation of the surfactants (III) is carried out by methods known in the art by first alkoxylating an alcohol R ⁹ OH and then sulfonating the alkoxylated alcohol. Linear or branched, saturated or unsaturated aliphatic alcohols R ⁹ OH are known.

Linear alcohols may, for example, be fatty alcohols. However, linear alcohols can also be prepared by the oligomerization of ethylene followed by functionalization (e.g., Ziegler process). Branched alcohols can be obtained, for example, by means of the oxo process. The preparation of branched aliphatic alcohols by means of aldol condensation and hydrogenation or by means of the Guerbet reaction has already been presented above.

The alkoxylation can be carried out according to the methods described for surfactant (I). The resulting alkoxylated alcohols R ⁹ - (OCR ² R ³ CR ⁴ R ⁵ ) i- (OCH ₂ CHR ⁶ ) _m - (OCH ₂ CH ₂ ) n -OH are then sulfonated by methods known in principle. The sulfonation can be carried out, for example, by substitution of the OH group of the alkoxylate for Cl using phosgene or thionyl chloride. The reaction can be carried out in the presence of a solvent such as chlorobenzene. HCl liberated as well as liberated C0 ₂ or SO2 can advantageously be removed from the system by stripping with nitrogen, so that ether cleavage is prevented. The alkylalkoxychlor compound is then reacted with an aqueous solution of sodium sulphite, the chloride being substituted by sulphite and the alkyl ether sulphonate being obtained. The substitution may be carried out in the presence of a phase mediator (eg Cr to Cs alcohols) at a temperature of 100-180 ° C and pressure. This gives a terminal group -CH 2 CH 2 -SO 3 M, ie R ¹⁰ is an ethylene group -CH 2 CH 2 -. An alternative to chlorination is the sulfation of the alkyl alkoxylates with SO3 in a falling film reactor and subsequent neutralization with NaOH. The alkyl ether sulfate formed can be converted into the alkyl ether sulfonate by nucleophilic substitution of the sulfate group by sodium sulfite analogously to the above description. The alkyl ether sulfonates (III) can alternatively be obtained by addition of vinyl sulfonic acid to the alkyl alkoxylate. Details of this are described for example in EP 31 1 961 A1. In this case, an alkyl ether sulfonate having a terminal group -CH 2 CH 2 -SO 3 M is obtained. Alkyl ether sulfonates having a terminal group -CH 2 -CH 2 -CH 2 -SO 3 M (ie, R ¹⁰ = -CH 2 CH 2 CH 2 - can be obtained by reacting the alkyl alkoxylate with 1,3-propane sultone.

In a preferred embodiment of the invention, the alcohol R ⁹ OH is an alcohol R ¹ OH. This is first alkoxylated in the manner described and then sulfonated. This procedure gives an alkyl alkoxy sulfonate in which R ^{9 has} the same meaning as R ¹ . In a further preferred embodiment of the invention, the alcohol R ⁹ OH is also an alcohol R ¹ OH. This is first alkoxylated in the manner described and then sulfonated, but only partially, ie it remains non-sulfonated, terminal OH groups. In this procedure, a mixture of an alkylpolyalkoxylate (I) and an alkylpolyalkoxysulphonate (III) is obtained, for which R ⁹ = R ¹ , 1 = x, m = y and n = z.

Other cosurfactants In addition to the nonionic surfactants according to the general formula (I) and, if appropriate, the surfactants (II) and / or (III), it is also possible optionally to use further surfactants. Examples of additional cosurfactants include anionic surfactants such as paraffin sulfonates, alkylarylsulfonates or olefinsulfonates (alpha-olefinsulfonates or internal olefinsulfonates), nonionic surfactants such as alkyl ethoxylates other than the surfactants (I) or polyalkoxylates composed of propylene oxide and ethylene oxide or surfactants which are permanently cationic (with alkyl or alkylalkyl quaternized alkylamines such as Ν, Ν, Ν-trimethyldodecylammonium chloride) or cationic under the conditions of the deposit (eg alkylamine alkoxylates which are cationic at a pH of 3).

Formulation (F) of the surfactants

For the process according to the invention, the surfactants (I), optionally further surfactants, in particular the surfactants (II) and (III) and optionally further components can be used as such, for example, the surfactants mentioned and / or other components directly in liquid or supercritical CO2 be solved.

In a preferred embodiment of the invention, however, the components mentioned are used in the form of a suitable aqueous formulation (F). This aqueous formulation (F) can be metered into liquid or supercritical CO2 and injected or the aqueous formulation can be injected as such or after further dilution into the formation.

The stated formulation (F) can be, in particular, an aqueous concentrate which can be produced on site or else in a chemical production plant remote therefrom. The total concentration of all surfactants in such an aqueous concentrate is chosen by the skilled person depending on the desired properties. It may be 20 to 90 wt .-% with respect to all components of the concentrate. The concentrate may be diluted prior to injection with liquid or supercritical CO2 and / or other aqueous solvents to the desired use concentration as will be described below. In addition to water, the formulations (F) may optionally also comprise water-miscible or at least water-dispersible organic solvents. Such additives serve in particular to stabilize the Tensidlosung during storage or transport to the oil field. However, the amount of such additional solvents should as a rule not exceed 50% by weight, preferably 20% by weight. Examples of water-miscible solvents include in particular alcohols such as methanol, ethanol and propanol, butanol, sec-butanol, methoxypropanol, pentanol, ethylene glycol, diethylene glycol, propylene glycol, methylpropylene glycol, dipropylene glycol, methyldipropylene glycol, butyl ethylene glycol, butyldiethylene glycol or butyltriethylene glycol. In a particularly advantageous embodiment of the invention, only water is used for formulation.

In addition to the surfactants, the aqueous formulations (F), in particular the aqueous concentrates, may also comprise further components, for example scale inhibitors, biocides, radical scavengers, stabilizers, tracers or pour-point depressants. Particularly suitable pour point depressants are the abovementioned alcohols.

Process for oil production by means of CQ2 floods

For the method according to the invention for CO 2 flooding, at least one injection well and at least one production well removed therefrom are drilled into a crude oil deposit. As a rule, a deposit is provided with multiple injection wells and multiple production wells.

In the oil reservoirs, in which the method according to the invention is used, it can in principle be any deposits, for example, formations comprising carbonate rocks or formations comprising sandstone. The oil reservoirs include oil and saline reservoir water, with petroleum, reservoir water and possibly natural gas stored in pores, crevices or interstices of the formation.

The storage temperature is usually at least 10 ° C, in particular 15 ° C to 140 ° C, preferably 31 ° C to 120 ° C, more preferably 31 ° C to 100 ° C, most preferably 35 ° C to 75 ° C and, for example, 40 ° C to 70 ° C.

It will be clear to those skilled in the art that the reservoir temperature may have a certain distribution around an average, with large deviations generally less due to natural circumstances, but mainly due to human interference, eg prolonged water flooding or prolonged steam flooding. The total salinity of the reservoir water can be up to 350,000 ppm, for example 20,000 ppm to 350,000 ppm. The method may preferably be applied to deposits having a total salinity of 20,000 ppm to 160,000 ppm, preferably 30,000 ppm to 120,000 ppm, more preferably 30,000 ppm to 100,000 ppm, for example 35,000 ppm to 80,000 ppm.

The salts in the reservoir water may be in particular alkali metal salts and alkaline earth metal salts. Examples of typical cations include Na ⁺ , K ⁺ , Mg ²⁺ or Ca ²⁺ and examples of typical anions include chloride, bromide, bicarbonate, sulfate or borate. As a rule, at least one or more alkali metal ions, in particular at least Na ^{+, are present} in the reservoir water. In addition, alkaline earth metal ions may also be present, the weight ratio of alkali metal ions / alkaline earth metal ions generally being> 5, preferably> 8. As anions, at least one or more halide ions, in particular at least Ch, are generally present. As a rule, the amount of Ch is at least 50% by weight, preferably at least 80% by weight, with respect to the sum of all anions.

Liquid or supercritical CO2 and at least one nonionic surfactant (I) or a surfactant mixture comprising at least one nonionic surfactant (I) are injected into the petroleum formation through the at least one injection well and petroleum is taken from the deposit through at least one production well, the at least one surfactant ( I) or the at least one surfactant (I) comprising surfactant mixture is dissolved in liquid or supercritical CO2 and injected and / or dissolved in an aqueous medium and injected.

The term "petroleum" in this context, of course, not only pure phase oil means, but the term also includes the usual crude oil-water emulsions.Produced also on the production well-depending on the stage of the process- also injected CO2.

When pumping CO2 into a reservoir, pressure and temperature determine the physical state of CO2. The phase diagram of CO2 is known to the person skilled in the art. CO2 can be liquefied in the temperature range of -56.6 ° C to 30.98 ° C using a pressure of at least 5.2 bar. At less than 5.2 bar, depending on the temperature, only solid or gaseous CO2 exists. The critical point of CO2 is 30.98 ° C and 73.75 bar. At pressures and temperatures above these values, CO2 is supercritical, ie the liquid-gas phase boundary disappears and the CO2 is nearly as dense as a liquid but still has a very low viscosity similar to that of a gas. To generate liquid or supercritical CO2, gaseous CO2 can be compressed on-site, for example from CO2 produced, or CO2 can already be delivered in a compressed state. The minimum pressure required for injection results from the reservoir temperature and is selected such that the injected CO2 is in a liquid or supercritical state at the respective reservoir temperature. It has proven useful to adjust the CO 2 flooding the density of CO2 under reservoir conditions to 0.65 g / ml to 0.95 g / ml, preferably 0.70 g / ml to 0.90 g / ml. The density of CO2 as a function of pressure and temperature can be found in relevant tables.

Injecting the at least one nonionic surfactant (I) or the surfactant mixture comprising at least one nonionic surfactant (I) can be carried out by various techniques. In a first embodiment (A) of the process according to the invention, the surfactants or surfactant mixtures used as well as optionally further components are dissolved in liquid or supercritical CO 2 and the CO 2 solution is injected into the subterranean crude oil deposit. Such processes are also referred to as surfactant-in-gas (SinG) processes.

In the embodiment (A), the surfactant (I) or the surfactant (I) comprising surfactant mixture can be mixed as such with the CO2, dissolved and injected, or it can be a suitable formulation of the surfactants used. In particular, the formulations (F) described above, in particular as concentrates having a surfactant content of from 20 to 90% by weight with respect to the sum of all components, can be used and metered into a stream of liquid or supercritical CO 2 and mixed with the stream.

The amount of the surfactants or of the formulation (F) or of the concentrate is so determined that the amount of all surfactants together is 0.02 to 2% by weight, preferably 0.02 to 0.5% by weight, based on the total all components of the solution of surfactants in liquid or supercritical CO2.

After entering the formation, the CO2 flows in the direction of the production well or the production wells, mobilizing oil according to the mechanisms described above. If the liquid or supercritical CO2 with the dissolved surfactants hits deposit water after being injected into the formation, CO2-in-water emulsions are formed which comprise mixtures comprising the surfactant (I) or surfactant (I) and optionally further surfactants be stabilized. Since no phase boundary between gaseous and liquid phase is present in supercritical CO2, such CC n-water emulsions are occasionally referred to in the literature as CC n-water foams, and the term C02-in-water dispersions can also in the literature can be found. In the following, however, the term CC n-water emulsion is to be used uniformly.

The C02-in-water emulsions have a significantly higher viscosity than the CO2 itself, and thus the difference between the viscosity of the CC n-water emulsion and the petroleum is lower, usually much less than the difference between the viscosity of liquid or supercritical CO2 and petroleum. C02-in-water emulsions also flow towards production wells or production wells. Liquid or supercritical CO2, which is incorporated in the emulsion, can also mobilize the oil in the same way as already mentioned when it encounters oil. Advantageously, the surfactants (I) and optionally further surfactants also lower the interfacial tension between oil and CO2 and thus also facilitate the miscibility of these two phases.

The injected liquid or supercritical CO2 naturally flows first into the higher permeable zones. As soon as more viscous C02-in-water emulsions form on the water, flow through the permeable zones becomes much more difficult, so that pumped-up CO2 can find its way through low-permeability zones and mobilize previously unreachable oil. This increases the oil production rate. If the capillary pressure in the very low-permeable zones becomes too high, the CO2-water aggregate may collapse. However, this is not a disadvantage since the very low-permeability zones would have been barely accessible to the CO2 if flooded alone with CO2 or in the water-alternating gas process.

In a second embodiment (B) of the method according to the invention, initially water or saline water, such as, for example, seawater or produced deposit water, is injected into the deposit through the injection well.

Subsequently, analogously to embodiment (A), a solution of the surfactants or surfactant mixtures used and optionally further components is injected in liquid or supercritical CO2.

The amount of the surfactants or of the formulation (F) or of the concentrate is such that the amount of all surfactants together 0.02 to 2 wt .-%, preferably 0.02 to 0.5 wt .-% with respect to the sum of all components the solution of surfactants in liquid or supercritical CO2. The sequence of these two process steps can be repeated once or several times. At the contact points of the water phase and the CO 2 phase, CO2-in-water emulsions are formed. Such processes are also referred to as water-aging surfactant-in-gas (WAGS) processes.

In a third embodiment (C) of the process according to the invention, an aqueous formulation of the surfactants (I) or surfactants (I) comprising surfactant mixtures is injected into the formation and separately liquid or supercritical CO2. For injecting, in particular, the above-described concentrates of formulation (F) may be mixed with water or saline water and injected into the formation.

The amount of surfactants is calculated so that the concentration of all surfactants together is 0.02 to 2 wt .-%, preferably 0.02 to 0.5 wt .-% with respect to the sum of all components of the injected aqueous solution.

Thereafter, liquid or supercritical CO2 is injected into the deposit. The sequence of these two process steps can be repeated once or several times. At the contact points of the water phase and the CO 2 phase, CC n-water emulsions form. Such processes are also referred to as Surfactant in Water Alternating Gas (SAG) processes.

To further improve the mobility control in embodiments (B) and (C), the water phase may be thickened with a water-soluble, thickening polymer such as polyacrylamide, partially hydrolyzed polyacrylamide, acrylamide-containing copolymers, acrylamide and sulfonate group-containing copolymers or biopolymers such as xanthan , It is preferred to inject the surfactants (I) as well as optionally further surfactants and components dissolved in liquid CO2 or supercritical CO2 (embodiments (A) and (B)). These variants have the advantage that the surfactant (I) and optionally further surfactants and components are present when the liquid or supercritical CO2 hits formation water after injection into the formation so that the rapid formation of CC n-water emulsions is possible becomes.

If the surfactant according to embodiment (C) injected separately from the CO2 by means of an aqueous solution, then water and CO2 can also take (partially) different flow paths due to their different properties in the formation. There is thus the danger that part of the surfactant remains unused. The person skilled in the art is familiar with details of the technical implementation of "C02 flooding", "Water Alternating Gas" flooding and the SinG, WAGS and SAG process and applies a corresponding technique depending on the nature of the deposit. Of course, further embodiments of the method according to the invention are possible. For example, the described CC n-water emulsions can be formed before injection from liquid or supercritical CO2, tensides (I) and optionally further surfactants, and the CC n-water emulsions injected.

The main effect of the surfactants (I) used according to the invention lies in the stabilization of the CO 2 -water interface and thus in long-term stable CC n-water emulsions. The surfactants (I) stabilize the CC n-water emulsions better than surfactants according to the prior art. The CC n-water emulsions remain stable much longer than is the case with known surfactants.

Selection of surfactants

The person skilled in the art selects at least one surfactant (I) for carrying out the process according to the invention, depending on the nature of the deposit. Optionally, the surfactants (I) may be used in admixture with other surfactants (I), at least one surfactant (II) and / or at least one surfactant (III). Optionally, other surfactants and other components can be used. The type of surfactant (I) to be used and possibly other surfactants depends on the conditions of the reservoir, in particular on the temperature of the reservoir and the salinity of the reservoir water. The skilled person will make an appropriate choice depending on the reservoir conditions. As a rule, the cloud point of the surfactant used or of the surfactant mixture used should be at least 1 ° C., preferably at least 3 ° C., above the reservoir temperature under reservoir conditions. If the deposit has a distribution of store temperatures, this means the highest store temperature in the area through which the liquid or supercritical CO2 or the C02-in-water emulsion flows.

The cloud point of a nonionic surfactant is the temperature at which the solution becomes cloudy. The reason for this is that the surfactant becomes dehydrated with increasing temperature and thus becomes insoluble. This separates the solution into a cloudy surfactant and a clear, low-surfactant phase. This phase behavior is found not only in nonionic surfactants, but also in surfactants which have a nonionic hydrophilic moiety, for example, a polyalkoxy group and an anionic group. Cloud points are thus also measurable with the anionic surfactants (III) of this invention. The cloud point is measured by slowly heating a clear aqueous solution of the surfactant in water. The cloud point of a surfactant depends on the concentration of the surfactant and the salt content of the aqueous solution. A specific measurement instruction for the cloud point is contained in the example part of this application. The term "under reservoir conditions" as defined above means that the cloud point of the surfactant (I) or surfactant (I) surfactant mixture in reservoir water at the concentration intended for injection, ie the concentration of surfactant in the aqueous medium to be injected or the concentration in the liquid or supercritical CO2 to be injected.

The cloud point of the surfactants of the formula employed in this invention (I) R - (OCR ² R ³ CR ⁴ R ⁵⁾ x (OCH ₂ CHR ⁶⁾ _y - (OCH ₂ CH 2) z-OH can be xylierungsschemas by the type of alcohol adapt well to the conditions in the deposit. The greater the number x of the alkoxy groups -OCR ² R ³ CR ⁴ R ⁵ - and the number y of the propoxy groups -OCH ² CHR ⁶ -, the lower the cloud point and the higher the number z of ethoxy groups, the higher the cloud point.

In one embodiment of the process according to the invention, a surfactant of the general formula (I) is used in which x = 0, y = 2 to 4 and z = 7 to 11 and the radicals R ¹ to R ^{6 have} the meaning defined above , Such surfactants are particularly suitable for deposits with a temperature of 30 to 55 ° C and a salinity of the deposit water from 20,000 ppm to 100,000 ppm. Examples include surfactants R ¹ - (OCH ₂ CHR ⁶ ) 2- (OCH ₂ CH ₂ ) 9 -OH, R - (OCH ₂ CHR ⁶ ) 3- (OCH ₂ CH ₂ ) 9 -OH, R - (OCH ₂ CHR ⁶ ) ₃ - (OCH ₂ CH ₂ ) io-OH and R ¹ - (OCH ₂ CHR ⁶ ) ₃ - (OCH ₂ CH ₂ ) ii -OH. The surfactant may preferably be used alone or in combination with other surfactants.

In one embodiment of the process according to the invention, a surfactant of the general formula (I) is used in which x = 0, y = 4 to 6 and z = 7 to 11 and the radicals R ¹ to R ^{6 have} the meaning defined above , Such surfactants are particularly suitable for deposits with a temperature of 30 to 55 ° C and a salinity of the deposit water from 20,000 ppm to 50,000 ppm. Examples include surfactants R ¹ - (OCH ₂ CHR ⁶ ) ₅ - (OCH ₂ CH ₂ ) ₉ -OH, R - (OCH ₂ CHR ⁶ ) ₅ - (OCH ₂ CH ₂ ) i ₀ -OH and R ¹ - (OCH ₂ CHR ⁶ ) 5- (OCH ₂ CH ₂ ) n -OH. The surfactant may preferably be used alone or in combination with other surfactants. In one embodiment of the process according to the invention, a surfactant of the general formula (I) is used in which x = 0, y = 4 to 6 and z = 12 to 18 and the radicals R ¹ to R ^{6 have} the meaning defined above. Such surfactants are particularly suitable for deposits having a temperature of 40 to 80 ° C, in particular 40 ° C to 65 ° C and a salinity of the reservoir water of 20,000 ppm to 160,000 ppm, in particular 20,000 ppm to 100,000 ppm and more preferably 30,000 ppm up to 60000 ppm. Examples include surfactants R ¹ - (OCH ₂ CHR ⁶ ) ₅ - (OCH ₂ CH ₂ ) i4-OH, R - (OCH ₂ CHR ⁶ ) ₅ - (OCH ₂ CH ₂ ) i 5-OH, R - (OCH ₂ CHR ⁶ ) ₅ - (OCH ₂ CH ₂ ) i ₆ -OH and R ¹ - (OCH ₂ CHR ⁶ ) ₅ - (OCH ₂ CH ₂ ) i7-OH. The surfactant may preferably be used alone or in combination with other surfactants.

In a further embodiment of the process according to the invention, a mixture of at least one surfactant (I) and at least one surfactant (II) is used. Combinations of nonionic surfactants of the formula (I) with likewise nonionic alk (en) ylpolyglucosides of the general formula (II) are particularly advantageous for use in deposits of high salinity and / or high temperature. Alk (en) ylpolyglucosides of the general formula (II) have high cloud points but do not cause as good a stabilization of the C0 ₂ -in-water emulsions as the surfactants of the formula (I). The combination of the surfactants (I) with the alk (en) ylpolyglucosiden (II) a mixture is obtained, which has a higher turbidity temperature than the surfactant (I) alone and still good stabilization of the C0 _{2 in} water emulsion causes.

The weight ratio of surfactants of the formula (I) to (II) is selected by the skilled person depending on the requirements. As a rule, the weight ratio (I) / (II) is 19: 1 to 1:19, preferably 4: 1 to 1: 9, more preferably 2: 1 to 1: 9 and for example 1: 1 to 1: 4. Preferred total amounts for the amount of all surfactants have already been mentioned. A mixture of the surfactants (I) and (II) can be formulated as above and injected both as an aqueous formulation or dissolved in liquid or supercritical C0 ₂ in the deposit.

The mixture of the surfactants (I) and (II) is still very soluble in water even at high salinity and also the solubility in C0 ₂ is good.

Due to the contact with C0 ₂ , the aqueous phases have a pH of typically 2 to 4 in the case of C0 ₂ fl uids. Surprisingly, it has been found that surfactants of the general formula (II) are nevertheless sufficiently stable under the acidic conditions of the C0 ₂ -fluid, although they may be sensitive to hydrolysis due to their acetal structure. Surprisingly, it has also been found that a mixture of surfactants (I) with surfactants (II) has synergistic effects with respect to emulsifying ability. The mixture of (I) and (II) binds more salty water in the CC n-water emulsion than would have been expected on the basis of the measurements for the tesides (I) alone and (II) alone.

The adsorption of the mixture is low on both carbonate rock and sandstone. In one embodiment of the process according to the invention, a surfactant mixture comprising at least one surfactant of the general formula (I) in which x = 0, y = 4 to 6 and z = 12 to 18 and the radicals R ¹ to R ^{6 are} the have at least one surfactant of the general formula (II) R ⁷ -O- (R ⁸ ) _p (II), wherein R ^{8 is} glucose, p is a number from 1 to 2 and R ^{8 is} a saturated or unsaturated aliphatic hydrocarbon radical having 8 to 22, preferably 8 to 14 carbon atoms. Such surfactant mixtures are particularly suitable for deposits with a temperature of 40 to 80 ° C, in particular 40 to 65 ° C and a salinity of the deposit water from 50000 ppm to 160000 ppm, preferably 50,000 ppm to 100,000 ppm.

In a further embodiment of the process according to the invention, a mixture of at least one surfactant (I) and at least one surfactant (III) is used.

Combinations of nonionic surfactants of the formula (I) and with the alk (en) ylpolyalkoxysulfonaten of the general formula (III) are like the combination of (I) and (II) particularly advantageous for use in deposits of high salinity and / or high temperature.

Alkylpolyalkoxysulfonates of the general formula (III) have high cloud points, but cause not quite as good stabilization of the CC n-water emulsions as the surfactants of the formula (I). The combination of the surfactants (I) with the alkyl polyalkoxysulphonates (III) gives a mixture which has a higher turbidity temperature than the surfactant (I) alone and which effects good stabilization of the CC.sub.n water emulsion.

The weight ratio of surfactants of the formula (I) to (III) is selected by the skilled person depending on the requirements. In general, the weight ratio (I) / (III) is 19: 1 to 1:19, preferably 4: 1 to 1: 9, more preferably 2: 1 to 1: 9 and for example 1: 1 to 1: 4. Preferred total amounts have already been mentioned. A mixture of the surfactants (I) and (III) may be formulated as above and is preferably injected as an aqueous formulation into the deposit, followed by the injection of liquid or supercritical CO2 (embodiment (C)). The mixture of the surfactants (I) and (III) is still very soluble in water even at high salinity and also the solubility in CO2 is good.

Surprisingly, it has furthermore been found that a mixture of surfactants (I) with surfactants (III) has synergistic effects with regard to emulsifying ability. The mixture of (I) and (III) binds more salty water in the CC n-water emulsion than would have been expected from the measurements for the surfactants (I) alone and (III) alone.

The adsorption of the mixture is low on sandstone.

In a particularly preferred embodiment of the invention, the surfactant (III) used is a surfactant for which R ^{9 is} equal to R ¹ and I = x, m = y and n = z. In one embodiment of the process according to the invention, a surfactant mixture comprising at least one surfactant of the general formula (I) in which x = 0, y = 2 to 6 and z = 12 to 18 and the radicals R ¹ to R ^{6 are} the have initially defined meaning and at least one surfactant of the general formula (III)

R ⁹ - (OCR ² R ³ CR ⁴ R ⁵ ) i- (OCH ₂ CHR ⁶ ) _m - (OCH ₂ CH ₂ ) n OR ¹⁰ -SO 3 - V _a M ^{a +} , where the radicals R ² to R ⁶ , R ⁹ and R ^{10 have} the same meaning as above. Preferably, R ^{9 has} the same meaning as above. Furthermore, in the preferred surfactant (III) I and m are each 0 and n is a number from 12 to 18. Such surfactant mixtures are particularly suitable for deposits with a temperature of 40 to 70 ° C and a salinity of the reservoir water from 100,000 ppm to 160,000 ppm.

The following examples are intended to explain the invention in more detail: Part I: Synthesis of the Surfactants Used 1-1: Synthesis of Alkyl Polyalkoxylates (Surfactant I and Comparative Stylides)

For the synthesis, the following alcohols were used as starting materials.

General rule:

In a 21 autoclave, the alcohol (1, 0 eq) to be alkoxylated is optionally mixed with an aqueous KOH solution containing 50% by weight of KOH. The amount of KOH is 0.2 wt .-% of the product to be produced. With stirring, the mixture is dehydrated at 100-120 ° C. and 20 mbar for 2 h. Then it is rinsed three times with N2, a pre-pressure of about 1.3 bar N2 is set and the temperature is increased to 130.degree. The alkylene oxides are then metered in succession in the respectively desired amount, so that the temperature remains between 135 to 145 ° C. The mixture is then stirred for 1 h at 135 to 145 ° C, rinsed with N2, cooled to 80 ° C and the reactor emptied. The basic crude product is neutralized with acetic acid. Alternatively, the neutralization can be carried out with commercially available Mg silicates, which are then filtered off. The bright product is characterized by means of a 1 H-NMR spectrum in CDCl 3, a gel permeation chromatography and an OH number determination, and the yield is determined.

In accordance with the general procedure, various nonionic surfactants were synthesized for the performance tests. The formula of the synthesized products are given in the following tables. I-2: Synthesis of alkyl (poly) alkoxysulfonates (surfactants (III))

1 . Step:

In a first stage of the synthesis, an alkyl alkoxylate was first synthesized according to the above general procedure. 2nd stage:

 In a second synthesis stage, that in FIG. In a 500 ml planoidal glass reactor with three-stage bar stirrer and flow breakers, the alkyl alkoxylate (1, 0 eq) to be sulfonated is mixed with KOH flakes (1.1 eq) and stirred at 60 ° C. under N 2. Now within 1 h propane sulphone (1, 0 eq) was added at 60 ° C and stirred for a further 3 h at 60 ° C. Unreacted propane sultone is destroyed by boiling with water. The basic crude product is neutralized at 60 ° C with the aid of hydrochloric acid. Ethanol may be added to the reaction mixture to lower the viscosity of the mixture.

Alternatively, it can be converted into the free sulfonic acid with an excess of HCl (1 .5 eq) and a phase separation at 60-80 ° C. can be carried out by addition of water and a volatile hydrophobic alcohol such as pentanol. The organic phase is then freed from the solvent and converted by means of base MOH (1 eq) into the corresponding sulfonate. The bright product is characterized by means of a 1 H-NMR spectrum in CDCl ₃ and MeOD, a ¹ H-TAI-NMR, an Epton titration and an OH number determination and the yield is determined.

In accordance with the general procedure, various nonionic surfactants were synthesized for the performance tests. The formula of the synthesized products are given in the following tables. I-3 Further surfactants used

Furthermore, the following commercially available surfactants were used for the tests:

Part II: Application studies ll-l: Measurement of the cloud point in water

In a first series of experiments, the cloud point of the surfactants or mixtures of different surfactants was determined. General measuring instruction:

50 ml of the respective aqueous surfactant solution are heated in a test tube over a Bunsen burner. The solution is stirred with a spatula. The temperature of the solution is determined by means of a thermometer submerged in the solution. After the haze has appeared, the bunsen burner is removed so that the solution can slowly cool and continue to stir until the solution is clear again. The cloud point is the change from cloudy to clear and is usually in a temperature range of 1 ° C.

Carrying out the measurements

The measurements were carried out with aqueous surfactant solutions both in fresh water and in salt water of various salt concentrations. The salt water used was aqueous solutions containing NaCl and CaC in a ratio of 9 to 1 (by weight). The salinity ranges from 0 to 250,000 ppm TDS (total dissolved salt).

The respective salinity, the type and amount of the surfactants used in each case and measured cloud points are summarized in Tables 1 a to 1 c.

Table 1 a shows the influence of the structure of the surfactants (I) used according to the invention and the salinity on the measured cloud points.

 Table 1 b compares the cloud points of three comparison surfactants with cloud points of the surfactants (I) used according to the invention.

Table 1 c shows the influence of cosurfactants on the cloud point of mixtures of the surfactants (I) used according to the invention with said cosurfactants.

Table 1 a: Influence of structure and salinity on cloud points in water (PO = propoxy, EO = ethox

Table 1 b: Comparison of the cloud points of various surfactants (I) to be used according to the invention with comparative surfactants according to the prior art.

Table 1 c: Effect of cosurfactants on the cloud point of the nonionic surfactants (I) at a total salinity of 160,000 ppm.

Table 1 a shows the influence of the alkoxylation on the cloud point. With a constant number of propoxy groups, the clouding temperature increases as the number of ethoxy groups increases. The surfactant 2PH- 5 PO-15 EO has a cloud point which is about 30 ° C higher than the surfactant 2PH- 5 PO-9 EO with the respective salinity. With increasing salinity the cloud points decrease.

Experiments 13 and 14 furthermore show that the cloud point of the surfactants used according to the invention only insignificantly depends on the concentration when surfactants of the formula (I) are used alone. If the concentration is reduced by a factor of 20, the cloud point at 1600000 ppm TDS only falls back from 46 ° C to 43 ° C. This is important for use in CC ^ flooding because the injected surfactants can mix in the formation with formation water, thereby reducing the concentration. A significant reduction in the cloud point would be extremely undesirable in terms of application technology.

The experiments V1 to V5 in Table 1 a were carried out with inverse block arrangement surfactants. The comparative experiments show that with surfactants with inverse block arrangement (at the selected salinity), the cloud points are significantly lower than with surfactants with the block arrangement according to the invention.

Table 1 b shows a comparison of the cloud points of various surfactants (I) to be used according to the invention with various prior art surfactants at different salinities. Alkylphenolethoxylates are considered ecologically questionable and their use has already been banned in several countries. If surfactants (I) with similar degrees of ethoxylation are selected, similar cloud points can also be obtained.

Table 1c shows with the aid of Examples 24 to 26 that the cloud point of the surfactants used according to the invention based on 2-PH can be markedly improved by adding the cosurfactants (II) and (III). The surfactant 2-PH - 3 PO - 9 EO (Example 18) has a cloud point of only 18 ° C at a salinity of 160000 ppm, so it can only be used in cold reservoirs. The mixture with a surfactant (III) has a cloud point of 47 ° C which is useful for many deposits. II-II solubility in supercritical CO2

Thereafter, the solubility of the surfactants in supercritical CO2 was investigated. The apparatus used was a 280 ml high-pressure reactor with two viewing windows in the lower region of the reactor. The structure of the apparatus is shown schematically in Figure 2. The reactor comprises a CO 2 inlet (1), a manometer (2), a CO2 Pressure relief valve (325 bar) and two, opposite viewing window (4) mounted in the lower reactor area. The reactor can be stirred via a stirrer.

For solubility determination, different pressures and temperatures were set. First, surfactant was added with stirring with CO2 and at a certain temperature, the pressure changed. If turbidity sets in - compared to the surfactant-free CO 2 phase under the same conditions - the conditions were noted.

Next, conditions were chosen which can often be found at a corresponding reservoir depth (lithostatic and hydrostatic pressure as well as reservoir temperature as a function of depth). The density of the CO2 was under the selected conditions (175 bar at 40 ° C or 300 bar at 65 ° C) about 0.78 to 0.82 g / ml. Surfactant concentrations of 0.1 and 0.5% by weight with respect to the CO 2 phase were investigated.

The results are summarized in Table 2. The evaluation of solubility was as follows:

Ex. Surfactant surfactant pressure Tempe solubility

 Concentration

 tration [%] [° C]

 27 2-PH - 3 PO - 9 EO 0.1 175 40 very good

28 2-PH - 5 PO - 15 EO 0.1 175 40 very good

29 2-PH - 5 PO - 15 EO 0.5 175 40 good

30 2-PH - 5 PO - 15 EO 0.1 300 65 very good

31 Cs / M-alkylpolyglucoside 0.5 175 40 moderate

32 Cs / M-alkyl polyglucoside 0.1 175 40 moderate

33 2-PH-14-EO-C ₃ H ₆ -SO ₃ K 0.1 175 40 very good

V13 2-EH - 5 -PO - 9 EO 0.1 175 40 good

V14 2-EH - 5 -PO - 9 EO 0.5 175 40 moderate

V15 4-nonylphenol - 9 EO 0.5 175 40 very good

V16 4-nonylphenol - 9 EO 0.1 175 40 very good

V17 4-Octylphenol - 16 EO 0.1 175 40 very good

V18 4-Octylphenol - 16 EO 0.1 300 65 very good

Table 2: Solubility in supercritical CO2

Table 2 shows the inventive surfactant of the formula (I) even at concentrations of 5000 ppm (0.5%) in C0 ₂ readily soluble. The surfactant 2-EH - 5 -PO - 9 EO, on the other hand, is only moderately soluble at 5000 ppm. The alkylphenol alkoxylates known from the prior art have a very good CO 2 solubility. The sulfonate 2-PH-14-EO-C ₃ H ₆ -SO ₃ K (a surfactant (III)) is very soluble. The C ₈ / i ₄ -alkylpolyglucoside is only moderately soluble at a concentration of 5000 ppm and at 1000 ppm.

II-III emulsifying ability

Furthermore, the ability of various surfactants and surfactant blends to stabilize C02-in-water emulsions was tested.

The above reactor was used. Surfactant was prepared at the concentrations shown in the tables below and made up to 40 ml with saline water. The saline water was a solution of NaCl and CaC in water (weight ratio NaCl: CaC = 9: 1). It has been tested at various total salinity levels. These are given in the following tables.

The high pressure apparatus was filled with the aqueous solution exactly to the middle of the viewing window. The reactor was then filled with supercritical CO2 to 280 ml up. The water phase and the CX phase are clear and the viewing window shows clearly the phase boundary between CO2 and water. This is shown schematically in Figure 3a. Then the mixture is stirred. Through the viewing window, the formation of CC n-water emulsions can now be observed. The formed CC n-water emulsions are not as clear as the C02 phase and the water phase, but cloudy to opaque. Depending on the degree of conversion of the water phase into the CO 2 -in-water emulsion, only the CO 2 -in-water emulsion can be seen through the viewing window or all 3 phases, namely water, CC n water emulsion and CO2. This is shown schematically in Figure 4.

The proportion of water bound in the CC n-water emulsion can be determined by determining the level of the water in the viewing window compared to the level of the water do in the viewing window before mixing (center of the viewing window) according to the relation [% ] = 100 ^* (do-di) / do. The proportion of the visible part of the CO2 in the window, which is bound in the emulsion can be determined in an analogous manner. After stopping the stirrer, observe how fast the CC n-water emulsion decays again by observing the fill levels as a function of time through the viewing window.

Table 3 shows the test parameters as well as the proportions of water and CO2 that can be seen 1 hour after the stirrer has been switched off in the viewing window.

Table 4 shows the time course of the breakdown of the emulsion for two surfactants after stopping the stirrer.

Table 3: C02-in-water emulsions at different salinities. The proportions of bound water and bound CO 2 were determined as described above by means of the ratio [%] = 100 ^* (do-di) / do.

Table 3 (cont.): C02-in-water emulsions at different salinities. The proportions of bound water and bound CO 2 were determined as described above by means of the ratio [%] = 100 ^* (do-di) / do.

TABLE 4 Time course of the emulsion breakdown for a surfactant according to the invention and a comparison surfactant

The experiments were carried out at 40 ° C and 175 bar. The CO 2 density was 0.78 g / ml.

 The concentration of the surfactant was in each case 0.1% by weight and the salinity of the aqueous phase

50000 ppm (weight ratio NaCl / CaC 9: 1).

Comments on the experiments carried out:

In the CC n-water emulsion, water forms the continuous phase and thus acts as a buffer between discrete CO 2 phases. When the CC n-water emulsion loses water, it eventually causes the discrete CO 2 phases to unite, i. the CC n-water emulsion breaks down. Deterioration of the emulsion in the petroleum formation is highly undesirable because the emulsion has a significantly higher viscosity than the supercritical CO2 (see above) and this higher viscosity is needed to avoid "fingering." It is therefore advantageous if the CC n Water emulsion in a given amount of CO2 binds the largest possible amount of water in the emulsion to keep the emulsion stable for as long as possible.The more water is bound, the more water can lose the emulsion without the emulsion decomposes, and accordingly, it takes longer for the emulsion to disintegrate.

Comparative experiments V20 and V23 to V26 show the importance of the cloud point for the formation of CC n-water emulsions. If the cloud point of the surfactant in water at the respective salinity is below the measurement temperature, then no CC n-water emulsions are formed.

The nonylphenol-9EO surfactant known from the prior art (Comparative Example V19) binds only a small amount of water (13%) even at a low salinity of 35,000 ppm (corresponding approximately to the salinity of seawater) and is no longer usable at higher salinities. The surfactant 2 PH - 3 PO - 9 EO (Example 34) has a cloud point of 43 ° C at a salinity of 50,000 ppm. Comparative surfactant 2 EH-5PO-9EO known from the prior art (comparative example V21) has a very similar cloud point, namely 45 ° C. Surprisingly, the surfactant 2 PH-3 PO-9 EO used according to the invention (Example 34) binds significantly more water in the CO 2 -in-water emulsion than the comparative V21 (41%) at 54%.

The comparative surfactant octylphenol-16 EO with a cloud point of 79 ° C binds at a salinity of 50,000 ppm 57% water (Comparative Experiment V22). Surprisingly, the surfactant 2-PH-5 PO-15 EO according to the invention surprisingly binds 74% water despite a cloud point which is about 15 ° C. (example 35). The remainder of 2-PH is quite obviously a hydrophobic part which is particularly suitable for the synthesis of surfactants for CO 2 flooding, in particular in comparison to the very similar radical 2-EH known from the prior art.

Furthermore, the stability of the emulsions with surfactants based on 2 PH is better. Table 4 shows that the emulsion decomposes much more slowly with the surfactant 2 PH - 3 PO - 9 EO used according to the invention than with the comparative surfactant 2 EH - 5 PO - 9 EO, although both surfactants have virtually the same cloud point (43 ° C. or 43 ° C.). 45 ° C). The C8 / i4-Alkypolyglucosid still has a cloud point> 100 ° C even at a high salinity of 160000 ppm (Example 36) and binds even at 160000 ppm and 50 ° C still 22% water in the emulsion. The surfactant 2 PH - 5 PO - 15 EO has a cloud point of 43 ° C at 160000 ppm (comparative experiment V25). At 50 ° C, it no longer binds any CO2 in a CC n-water emulsion. Surprisingly, the combination of both surfactants but forms both at 50 ° C and at 62 ° C CC n-water emulsions, namely 40% and 38% water in the CC n-water emulsion bound.

The alkylalkoxysulphonate 2-PH-14-EO-C ₃ H 6 -SO ₃ K still has excellent cloud points of> 95 ° C., even with high salinity of 160000 ppm (Experiments 21 to 23). Furthermore, it binds at 50 ° C and a salinity of 160000 ppm 60% water in the CC n-water emulsion. It is therefore ideal for C02 floods.

The disadvantage of Alkylpolyalkoxysulfonate is their complex and therefore expensive production. For their preparation, first of all alkylpolyalkoxylates have to be prepared, which then have to be converted into alkylpolyalkoxysulphonates in a one- or two-stage process. Details of this have already been described above. The sulphates which are chemically similar to the sulphonates would be easier to prepare from the alkypolyalkoxylates. In CO 2 flooding, however, the aqueous phase is highly acidic due to CO2 (about pH 3), and under the acidic conditions, the sulfates hydrolyze. Therefore, sulfonates should be used for CO2 flooding and not sulfates.

The use of alkyl polyalkoxylates described here is therefore cheaper in each case, ie the use of Alkylpolyalkoxysulfonaten. As the experiments show, it is particularly advantageous to use mixtures of alkylpolyalkoxylates and alkylpolyalkoxysulphonates. The surfactant 2-PH - 5 PO - 15 EO has a cloud point of 43 ° C at 160000 ppm salinity and is therefore no longer suitable for use at 50 ° C. The combination with the surfactant 2-PH-14-EO-C ₃ H ₆ -SO ₃ K (ratio 1: 1) has a cloud point of 53 ° C. (Experiment 39) and binds 62% water in the CO 2 -in. water emulsion. By mixing with alkyl polyalkoxy sulfonates, the cheap alkypolyalkoxylates used according to the invention can therefore also be used at higher salinities and higher temperatures.

Claims

claims

A process for the production of crude oil by means of C02 flooding, in which liquid or supercritical CO2 and at least one nonionic surfactant (I) or a surfactant mixture comprising at least one nonionic surfactant (I) are injected through at least one injection well into a crude oil deposit and the deposit through at least one production well crude oil takes, where

 the at least one surfactant (I) or the surfactant mixture comprising at least one surfactant (I) is dissolved in liquid or supercritical CO2 and injected and / or dissolved in an aqueous medium and injected,

 characterized in that the deposit has a deposit temperature of 15 ° C to 140 ° C and the deposit water has a salinity of 20,000 ppm to 350,000 ppm and that the at least one nonionic surfactant is a branched alkyl polyalkoxylate of the general formula

R - (OCR ² R ³ CR ⁴ R ⁵⁾ x (OCH ₂ CHR ⁶⁾ _y - (OCH ₂ CH 2) z-OH (I) acts, wherein

R ^{1 is} a branched alkyl radical of the formula C 5 Hn-CH (C 3 H 7) -CH 2 -, and wherein at least 70 mol% of the radicals C 5 H 11 - is an n-C 5 Hn radical,

R ² , R ³ , R ⁴ , R ^{5 are} each H or a linear or branched alkyl radical having 1 to 8

Carbon atoms, with the proviso that the sum of the carbon atoms of the radicals R ² + R ³ + R ⁴ + R ^{5 is} 2 to 8,

R ⁶ for methyl,

 x for a number from 0 to 5,

 y for a number from 1 to 15,

z is a number from 1 to 30, wherein the radicals -OCR ² R ³ CR ⁴ R ⁵ -, -OCH ₂ CHR ⁶ - and -OCH ₂ CH ₂ - are arranged blockwise in the order indicated in formula (I), and wherein the sum of x + y + z stands for values from 5 to 35, with the proviso that z> (x + y).

2. The method according to claim 1, characterized in that it is at

• 70 to 99 mol% of C5H11- residues around n-CsHu residues, and at

• 1 to 30 mol% of the radicals C ₅ Hn- to C2H ₅ CH (CI-l3) Cl-l2 radicals and / or CH ₃ CH (CH ₃ ) CH ₂ CH ₂ radicals. A method according to claim 1 or 2, characterized in that in the radicals C3H7- to n-C3H ₇ radicals.

A method according to claim 1, characterized in that R ¹ is a 2-propyl-n-heptyl radical HsCC ^ C ^ C ^ C ^ CH vCsH ^ Ch -.

Method according to one of claims 1 to 4, characterized in that z> 2 (x + y). 6. The method according to any one of claims 1 to 5, characterized in that x = 0. 7. The method according to any one of claims 1 to 6, characterized in that the cloud point of the surfactant (I) used or at least one surfactant (I) comprising surfactant mixture is at least 1 ° C above the reservoir temperature, wherein the cloud point in reservoir water at the concentration of the surfactant in the aqueous medium to be injected or the concentration in the liquid or supercritical CO2 to be injected is determined.

8. The method according to claim 7, characterized in that the cloud point of the surfactant used (I) or the surfactant used at least one surfactant (I) comprising at least 3 ° C above the deposit temperature.

9. The method according to any one of claims 1 to 8, characterized in that the deposit temperature is 31 ° C to 120 ° C.

A method according to any one of claims 1 to 8, characterized in that the deposit temperature is 35 ° C to 100 ° C. 1 1 process according to one of claims 1 to 10, characterized in that it is a surfactant mixture comprising at least one nonionic surfactant (I) and a different nonionic surfactant (II) of the general formula

R ^{7 is} -O- (R ⁸ ) _P -H (II), wherein

R ^{7 is} a linear or branched, saturated or unsaturated aliphatic

Hydrocarbon radical having 8 to 22 carbon atoms,

R ^{8 represents} a sugar moiety having 5 or 6 carbon atoms, and

 p is a number from 1 to 5.

12. The method according to claim 11, characterized in that the weight ratio of surfactant (I) / surfactant (II) in the surfactant mixture is 19: 1 to 1:19.

13. The method according to claim 1 1, characterized in that the weight ratio of surfactant (I) / surfactant (II) in the surfactant mixture is 4: 1 to 1: 9.

Method according to one of claims 1 to 10, characterized in that it is a surfactant mixture comprising at least one nonionic surfactant (I) and an anionic surfactant (III) of the general formula

R ⁹ - (OCR ² R ³ CR ⁴ R ⁵ ) i- (OCH ₂ CHR ⁶ ) _m - (OCH ₂ CH ₂ ) n OR ¹⁰ -SO 3 - V _a M ^{a +} (III) where

R ² , R ³ , R ⁴ , R ⁵ , R ^{6 have} the meaning given above, and

R ^{9 is} a branched or linear, saturated or unsaturated aliphatic hydrocarbon radical having 8 to 22 carbon atoms,

R ^{10 is} an alkylene radical having 2 to 4 carbon atoms, which may optionally be substituted by an OH group,

 I for a number from 0 to 5

 m for a number from 0 to 15

 n for a number from 5 to 30, and

M ^{a + are} an a-valent cation, where a is 1, 2, or 3, wherein the radicals -OCR ² R ^{3 are} CR ⁴ R ⁵ -, -OCH ₂ CHR ⁶ - and -OCH ₂ CH ₂ - block-like in the in formula (III), and wherein the sum of I + m + n is from 5 to 35, with the proviso that n> (l + m).

15. The method according to claim 14, characterized in that R ^{9 is} equal to R ¹ .

16. The method according to claim 14, characterized in that R ^{9 is} equal to R ¹ and I = x, m = y and n = z.

17. The method according to any one of claims 14 to 16, characterized in that the weight ratio of surfactant (I) / surfactant (III) in the surfactant mixture is 19: 1 to 1: 19. 18. The method according to any one of claims 14 to 16, characterized in that the weight ratio of surfactant (I) / surfactant (III) in the surfactant mixture is 4: 1 to 1: 9.

19. The method according to any one of claims 1 to 18, characterized in that the surfactant or the surfactant mixture is injected as a solution in water in the deposit, wherein the concentration of all surfactants together 0.02 to 2 wt .-% with respect to the aqueous Solution amounts.

20. The method according to claim 19, characterized in that the concentration of all surfactants together 0.02 to 0.5 wt .-% with respect to the aqueous solution.

21. A method according to any one of claims 1 to 18, characterized in that the surfactant used or the surfactant mixture as a solution in liquid or supercritical

CO2 is injected into the deposit, the concentration of all surfactants together amounting to 0.02 to 2 wt .-% with respect to the solution of liquid or supercritical CO2.

22. The method according to claim 21, characterized in that the concentration of all surfactants together 0.02 to 0.5 wt .-% with respect to the solution of liquid or supercritical CO2.