WO2015135855A1

WO2015135855A1 - Method for co2-flooding using c12-14-alk(en)yl polyalkoxylates

Info

Publication number: WO2015135855A1
Application number: PCT/EP2015/054767
Authority: WO
Inventors: Christian Bittner; Benjamin Wenzke; Günter OETTER; Sebastian Alexander WEISSE
Original assignee: Basf Se
Priority date: 2014-03-12
Filing date: 2015-03-06
Publication date: 2015-09-17
Also published as: AR101151A1

Abstract

The invention relates to a method for extracting crude oil by means of CO₂-flooding, in which a liquid or supercritical CO₂and at least one C_12-14-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 at least one production bore. The C_12-14-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 C_12-14-alkyl polyalkoxylates are used with alkyl polyalkoxysulfonates or alk(en)yl polyglucosides.

Description

C02 flooding process using Ci2-i4-alk (en) ylpolyalkoxylaten

The invention relates to a method for producing crude oil by means of C02 flooding, in which liquid or supercritical CO2 and at least one C12-14-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 C 12-14 alkyl polyalkoxylate 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 Ci2-i4-alkylpolyalkoxylates with alk (en) ylpolyalkoxysulfonaten 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 deposit, however, only 5 to 10% of the oil in the deposit can be pumped by means of 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 lowers petroleum Viscosity It goes without saying 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 easier to form a related oil bank. Another delivery mechanism may be the dissolution of preferably light levels of crude oil into the C02 phase rather than a type of extraction. Another aspect is the low interfacial tension between crude oil and liquid or supercritical CO2, which helps to overcome capillary forces: an oil drop can more readily 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 need more CO2 now or the pumped CO2 has to be separated, cleaned and recompressed after it has been extracted from oil or formation water 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, CO2 (buoyancy) accumulates preferentially 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 flours, are therefore less suitable for CO 2 flooding since, on the one hand, they are insoluble by protonation and the sulfate group can be split off hydrolytically under the abovementioned conditions. 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.

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 glycerin derivatives wherein two of the alcohol groups of the glycerol are capped with a hydrocarbon group which may include 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 injected into the formation to form emulsions with water. 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 CC n-water emulsion. In the CC n-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. A breakdown of the emulsion in the petroleum formation is highly undesirable because it is precisely the higher viscosity of the emulsion compared to a pure C02 phase is required to avoid the "fingering".

The object of the invention was to provide an improved process for CO 2 flooding for oil refineries, in which the most stable CC n-water emulsions are formed.

It has surprisingly been found that this goal can be achieved by using C 12-14-alk (en) ylpolyalkoxylates for CO 2 flooding.

Accordingly, a process for crude oil production by means of C02 flooding was 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 a crude oil deposit and the Deposits by at least one production well crude oil takes, characterized in that the at least one surfactant (I) or at least one surfactant (I) comprising dissolved surfactant mixture in liquid or supercritical CO2 and is injected and / or dissolved in an aqueous medium and injected the deposit has a shelf temperature of 15 ° C to 140 ° C and the deposit water has a salinity of 20,000 ppm to 350,000 ppm, and wherein the at least one nonionic surfactant is a branched alk (en) ylpolyalkoxylate of the general formula R is - (OCR ² R ³ CR ⁴ R ⁵ ) x- (OCH ₂ CH R ⁶ ) _y - (OCH ₂ CH ₂ ) z -OH (I) wherein R ^{1 is} a saturated or unsaturated, linear aliphatic

Hydrocarbon radical having 12 to 14 carbon atoms,

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 blockwise in the formula (I) order, and wherein the Sum of x + + z stands for values from 5 to 35, with the proviso that z> (x + y).

List of pictures

Schematic representation of "fingering" in C0 ₂ flutes.

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: C0 ₂ phase and water phase (schematic representation).

Figure 4: View through the viewing window of the high-pressure reactor after mixing: C0 ₂ phase, C0 _{2 in} 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 oil production by means of C0 ₂ -fluid liquid or supercritical C0 ₂ and at least one nonionic surfactant (I) is injected into a Erdöllagerstätte. In addition to the at least one nonionic surfactant (I), other surfactants and other components can be used. In a 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) is branched alkyl polyalkoxylates of the formula (I) R ¹ - (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 saturated or unsaturated, linear aliphatic hydrocarbon radical having 12 to 14 carbon atoms. Examples of such radicals R ¹ include n-dodecyl, n-tridecyl and n-tetradecyl radicals.

It may also be surfactants (I) comprising mixtures of different radicals R ¹ . Particularly noteworthy here are mixtures which derive from the use of natural fatty alcohols as starting material for the surfactants (I). For example, it may be a mixture of n-dodecyl and n-tetradecyl radicals.

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 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, the sum of R ² + R ³ + R ⁴ + R ⁵ = 2 is, wherein at least 70 mol%, preferably at least 80 mol% and particularly preferably at least 95 mol% of 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 subscript x stands for a number from 0 to 5, preferably 0, the index y for a number from 1 to 15, preferably 1 to 9, for example 2 to 8 and the index z for a number from 1 to 30, preferably 2 to 20, particularly 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 is obtained upon alkoxylation, and that x, y, and z are averages over all molecules, 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 -OCR ⁵ R ⁴ CR ³ R ² - respectively. -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 blockwise in the order given in formula (I). 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 be copolymerized into the second block so that small amounts of an alkylene oxide are in the "wrong" block. [. In] As a rule, at least 90% of the above radicals are arranged in the order given in formula (I), ie at least 90% of the radicals are also found in the "right" block.

The preparation of the surfactants (I) is carried out by alkoxylation of 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 are at least 70 mol%, preferably at least 80 mole% and more preferably at least 95 mole% of 1,2-butene oxide.

Suitable alcohols R ¹ OH are known to the person skilled in the art and are commercially available. For example, linear alcohols can be fatty alcohols or mixtures of different fatty alcohols. However, linear alcohols can also be prepared by oligomerization of ethylene and subsequent functionalization (eg Ziegler process). For the synthesis of surfactants with branched hydrocarbon radicals Oxoalkohole or Guerbet alcohols can be used.

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 reduced 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. In one embodiment, the alkylene oxide is initially metered in at 120 ° C. 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 form by the newly injected alkylene oxide mixing blocks with small amounts of the 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.

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 be prepared in a manner known in principle by acid-catalyzed reaction of corresponding alcohols R ⁴ OH with sugars with removal of the water of reaction. The production 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 alkylalkoxysulphonates 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, preferably 8 to 18 and 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, co-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> (lm), 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 further arranged at least 90% blockwise in the order given in formula (III).

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 such as, for example, alkali metal ions, ammonium ions, where the ammonium ions may also have organic radicals. 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 oligomerization of ethylene and subsequent functionalization (eg 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 described 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 -CH2CH2-SO3M 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 he remain not yet 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 optionally the surfactants (II) and / or (III), it is optionally possible 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 cationically (with alkyl alkylated quaternized or hydroxyalkyl groups such as Ν, Ν, Ν-trimethyl-dodecylammonium chloride) or cationic under the reservoir conditions (eg alkylamine alkoxylates which are cationic at pH3).

Formulation (F) of the Surfactants For the process according to the invention, it is possible to use the surfactants (I), optionally further surfactants, in particular the surfactants (II) and (III) and optionally further components as such, for example the surfactants mentioned and / or further components be dissolved directly in liquid or supercritical CO2. 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) may in particular be 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. Derar- These additives serve, in particular, to stabilize the surfactant solution 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 may 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 and most preferably 35 ° C to 75 ° C and for example 40 ° C to 70 ° C. It will be appreciated by those skilled in the art that the reservoir temperature may have some distribution around an average, with large deviations generally less due to natural circumstances, but mainly due to human intervention, 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 used in storage with 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 are used. 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. Suitable anions are usually at least one or more of halide ions, in particular at least Cl ^"available. In general, the amount of Ch is at least about 50 wt.%, Preferably at least 80 wt.% Relative to the total 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.

Of course, the term "petroleum" in this context does not only mean phase-pure oil, but also includes the usual crude oil-water emulsions, and also injects injected CO2 into the production well, depending on the stage of the process.

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, i. the phase boundary liquid-gaseous disappears and the CO2 is almost 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 necessary for injecting Minimum pressure results from the reservoir temperature and is chosen so that the injected CO2 is in 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 accomplished 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 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.

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 supercritical CO2 no longer has a phase boundary between gaseous and liquid phase, such CC n-water emulsions are occasionally also referred to in the literature as CC n-water foams, and the designations CC n-water dispersions can be found in the literature. 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 included 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, water or saline water, such as, for example, seawater or produced deposit water, is first injected into the deposit through the injection well.

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

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 Depending on the nature of the deposit, the person skilled in the art selects at least one surfactant (I) for carrying out the process according to the invention. 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. Insofar as the deposit has a distribution of storage temperature, this means the highest deposit temperature in the range through which the liquid or supercritical CO2 or the CO 2-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 with nonionic surfactants, but also with surfactants which have a nonionic, hydrophilic moiety, for example a polyalkoxy group and an anionic group. Cloud points are 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 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) and likewise with nonionic alkylpolyglucosides of the general formula (II) are particularly advantageous for use in deposits of high salinity and / or high temperature. Alkylpolyglucosides of the general formula (II) have high cloud points, but do not cause as good stabilization of the CC n-water emulsions as the surfactants of the formula (I). The combination of the surfactants (I) with the alkylpolyglucosides (II) gives a mixture which has a higher turbidity temperature than the surfactant (I) alone and which nevertheless effects a good stabilization of the CC.sub.n-water emulsion.

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) may be formulated as above and injected into the reservoir both as an aqueous formulation or dissolved in liquid or supercritical CO2. The mixture of the surfactants (I) and (II) is still very soluble in water even at high salinity and also the solubility in CO2 is good.

Due to the contact with CO2, the aqueous phases have a pH of typically 2 to 4 during CO 2 flooding. Surprisingly, it has been found that surfactants of the general formula (II) are nevertheless sufficiently stable under the acidic conditions of CO 2 flooding, although they may be sensitive to hydrolysis due to their acetal structure. Surprisingly, it has furthermore 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 saline water in the CC n-water emulsion than would have been expected from the readings for the tesides (I) alone and (II) alone.

The adsorption of the mixture is low on both carbonate rock and sandstone.

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 alkylalkoxysulphonates 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.

The following examples are intended to explain the invention in more detail:

Part I: Synthesis of the surfactants used

1-1: Synthesis of Alk (en) ylpolyalkoxylates (Surfactants (I))

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% by weight 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. Subsequently, the mixture is 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, nonionic surfactants were synthesized for the performance tests. The formula of the synthesized products are given in the following tables.

1-3 Further surfactants used

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

Cs / M polyglucoside alkyl polyglucoside ((surfactants II)) based on linear, saturated alkyl groups having 8, 10, 12 and 14 carbon atoms (based on co kosfettöl), (Glucopon ^® 425 N / NH)

Part II: Application Testing

11-1: 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 immersed 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 surfactants used and measured cloud points are summarized in Tables 1.

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

11-2 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 construction of the apparatus is shown schematically in Figure 2. The reactor comprises a CO 2 inlet (1), a manometer (2), a CO 2 pressure relief valve (325 bar) and two opposing viewing windows (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:

Table 2: Solubility in supercritical CO2

Table 2 shows that the C 12/14 alkoxylates used according to the invention have a very good CO 2 solubility.

11-3 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 charged to 280 ml with supercritical CO2. The water phase and the C02 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 C02-in-water emulsions can now be observed. The C02-in-water emulsions formed are not as clear as the CO2 phase and the water phase, but cloudy to opaque. Depending on the degree of conversion of the water phase to 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, CO 2-in-water emulsion and CO2. This is shown schematically in Figure 4.

The proportion of water which is bound in the C02-in-water emulsion, by determining the level of the water di in the viewing window compared to Level of water do in the window before mixing (center of the viewing window) according to the relation proportion [%] = 100 ^* (do-di) / do. The proportion of visible in the window portion of the CO2, 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 in the viewing window 1 hour after the stirrer has been switched off.

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.

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. A breakdown 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 just this higher viscosity is required to avoid the "fingering".

It is therefore advantageous if the CC n-water emulsion binds a large amount of water in the emulsion at a given amount of CO2 in order to have the emulsion stable for as long as possible. The more water that is bound, the more water the emulsion can lose, without the emulsion breaking down, and consequently, it takes longer for the emulsion to disintegrate.

The surfactants used according to the invention alone already show a significant stabilization of the CO 2 -in-water emulsions.

The combination of alkyl polyglucosides gives an emulsion of excellent stability. After 1 h, the emulsion has not lost any water.

With a branched iCi3-alkylpolyalkoxylate no stable emulsions are obtained.

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, characterized in that

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, the deposit has a storage temperature of 15 ° C to 140 ° C and the reservoir water has a salinity of 20,000 ppm to 350000 ppm, and wherein the at least one nonionic surfactant is an alk (en) ylpolyalkoxylat 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 saturated or unsaturated, linear aliphatic hydrocarbon radical having 12 to 14 carbon atoms,

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 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).

2. The method according to claim 1, characterized in that R ¹ is a mixture comprising n-dodecyl and n-tetradecyl radicals.

3. The method according to any one of claims 1 or 2, characterized in that z> 2 (x + y).

4. The method according to any one of claims 1 to 3, characterized in that x = 0.

5. The method according to any one of claims 1 to 4, characterized in that the cloud point of the surfactant used (I) or the surfactant used at least one surfactant mixture (I) is at least 1 ° C above the deposit 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.

6. The method according to claim 5, characterized in that the cloud point of the surfactant used (I) or the at least one surfactant (I) used

Surfactant mixture is at least 3 ° C above the reservoir temperature

7. The method according to any one of claims 1 to 6, characterized in that the deposit temperature is 31 ° C to 120 ° C.

8. The method according to any one of claims 1 to 6, characterized in that the deposit temperature is 35 ° C to 100 ° C.

9. The method according to any one of claims 1 to 8, 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 18 carbon atoms,

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

p is a number from 1 to 5.

10. The method according to claim 9, characterized in that the weight ratio of surfactant (I) / surfactant (II) in the surfactant mixture is 19: 1 to 1: 19.

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

12. The method according to any one of claims 1 to 8, 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 -SO3- V _a M ^{a +} (III) is, 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 18 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 +} for an a-valent cation, where a is 1, 2, or 3,

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 I + m + n for Values from 5 to 35, with the proviso that n> (l + m).

13. The method according to claim 12, characterized in that R ^{9 is} equal to R ¹ .

14. The method according to claim 12, characterized in that R ^{9 is} equal to R ¹ and I = x, m = y and n = z.

15. The method according to any one of claims 12 to 14, characterized in that the weight ratio of surfactant (I) / surfactant (III) in the surfactant mixture is 19: 1 to 1: 19.

16. The method according to any one of claims 12 to 14, characterized in that the weight ratio of surfactant (I) / surfactant (III) in the surfactant mixture is 4: 1 to 1: 9.

17. The method according to any one of claims 1 to 16, characterized in that the used 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 the solution is.

18. The method according to claim 17, characterized in that the concentration of all surfactants together 0.02 to 0.5 wt .-% with respect to the solution.

19. The method according to any one of claims 1 to 16, characterized in that the surfactant used or the surfactant mixture is injected as a solution in liquid or supercritical C0 ₂ in the deposit, the concentration of all surfactants together 0.02 to 2 wt. % with respect to the solution of liquid or supercritical CO2. A method according to claim 19, 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.