WO2022101081A1 - Method of mineral oil production from underground carbonate deposits - Google Patents

Abstract

A method of producing mineral oil from underground mineral oil deposits comprising oilbearing carbonate rocks, in which an aqueous composition comprising at least one alkoxylated amine is injected into a mineral oil deposit through at least one injection well and mineral oil is withdrawn from the production well, wherein the pH of the aqueous composition is chosen such that the molar ratio of protonated alkoxylated amines to nonprotonated alkoxylated amines is 1:10 to 10:1. Aqueous composition for production of mineral oil from underground mineral oil deposits comprising oilbearing carbonate rocks, comprising at least one alkoxylated amine, wherein the pH is adjusted as just described.

Description

Process for oil extraction from underground carbonate deposits

The present invention relates to a method for extracting crude oil from underground, oil-wetted carbonate rocks containing crude oil deposits, in which an aqueous composition comprising at least one alkoxylated amine is injected through at least one injection well into a crude oil deposit and the crude oil is removed from the production well, the pH being determined the aqueous composition is chosen so that the molar ratio of profaned alkoxylated amines to non-profanated alkoxylated amines is 1:10 to 10:1. It also relates to an aqueous composition for extracting petroleum from underground petroleum deposits comprising oil-wetted carbonate rocks, which comprises at least one alkoxylated amine and the pH of which is adjusted as just described.

Limestone, dolomite, chalk or other deposits based on carbonate rocks usually have a predominantly positive surface charge in the presence of the existing deposit water. Because of the surface charge, oppositionally charged constituents found in natural crude oils can interact with the electrostatically charged rock surface. These components have predominantly acidic but also basic groups. In addition to electrostatic effects, polar interactions, the precipitation of crude oil components and acid/base reactions contribute to the rewetting of the rock surface. The state of wetting of the rock surface changes from water-wetted to at least partially oil-wetted. If there are oil-wetted surfaces, the crude oil present in the rock pores can no longer be sufficiently displaced by the penetrating aqueous fluid due to the lower capillary pressure.

It is known to use surfactants to make oil-wetted surfaces water-wettable and thus increase oil production. In particular, the use of cationic surfactants such as quaternized amines to improve oil recovery is known.

Stadnes and Austad describe the use of quaternary alkyltrimethylammonium compounds (linear C, C12, C14 and Cie alkyl groups) to change the wettability of chalk reservoirs (Colloids and Surfaces A: Physicochem. Eng. Aspects 216, 2003, 243-259).

\NC) 2014/118084 A1 discloses the use of quaternized amines [R ¹ -NR ² R ³ R ⁴ ] ⁺ X ^_ for treating oil formations containing carbonate rocks, where R ¹ represents an aliphatic C10-C22 group, which optionally may have an OH group, the groups R ² , R ³ and R ⁴ are Ci to C4 alkyl groups, OH-substituted Ci to C4 alkyl groups or alkyl ether groups -CH2CH2OCH2CH2OH and -CH2CH2OCH2CH2OCH2CH2OH, and where the surfactants have a total of 1 bis Have 3 OH groups.

WO 2019/010179 A1 discloses the use of quaternary dialkyldimethylammonium compounds together with amphoteric surfactants to improve oil recovery. CN 106590572 A and CN 103740354 A disclose the use of quaternary amines in conjunction with anionic surfactants to improve oil recovery.

AI Sofi et al. also report being able to alter the wettability of oil-wetted carbonate rocks with quaternary ammonium salts Investigation of Wettability Alteration Processes for Carbonates using the Washburn Contact Angle Method with two Sorption Fluids", 19622-MS International Petroleum Technology Conference Paper - 2020).

It is also known to use amines for rewetting in carbonate reservoirs. In principle, greater economic efficiency can be achieved with this method, since the additional step of quaternizing the amines can be avoided.

Thus, Standnes and Austad describe the use of n-decylamine, n-dodecylamine and mixtures thereof to alter the wettability of carbonate rocks ("Nontoxic low-cost amines as wettability alteration chemicals in carbonates", Journal of Petroleum Science and Engineering 39 (2003 ) 431-446, see also Dag C. Stadnes, "Enhanced Oil Recovery from Oil-Wet Carbonate Rock by Spontaneous Imbibition of Aqueous Surfactant Solutions", Thesis, Department for Petroleum Technology, Stavanger, Sep. 17, 2001). Austad, however, short-chain alkylamines such as decylamine do not lead to a significant improvement in oil production.Dodecylamine works at lower temperatures, but is not sufficiently soluble in salt systems with increased salinity at slightly acidic pH values and elevated temperatures to be used as an imbibition enhancer.

Peila Chen, Kishore K. Mohanty, The University of Texas at Austin, describe in SPE-169125-MS "Wettability Alteration in High Temperature Carbonate Reservoirs" a process for oil production from carbonate deposits at high temperatures. An ethoxylated tallow fatty amine of the Formula RN-[(CH2CH2Ö) _X H]2, where R is alkyl radicals derived from tallow fat, ie essentially Cw and C radicals Table 2 shows the data for the dolomite core flood test SD-18, in which a 1% solution of the tenside in synthetic seawater and a pH of 7. The tests were carried out at 100°C (Section 3.1, page 4).

Surprisingly, it has now been found that in carbonate reservoirs with a high salinity (at least 30,000 ppm), the oil discharge can be improved with alkoxylated amines if the pH of the aqueous composition is chosen so that the molar ratio of profaned alkoxylated amines to non-profanated alkoxylated amines is 1 :10 to 10:1. The decrease in imbibition with increasing temperature, as described with non-alkoxylated amines, does not occur with alkoxylated amines.

Accordingly, the present invention relates to a method for extracting crude oil from underground crude oil deposits containing oil-wetted carbonate rocks, comprising at least one injection well and at least one production well, the method comprising at least the following steps: • Injecting an aqueous composition comprising at least one surfactant through at least one injection well into at least part of the oil reservoir, with the aqueous composition flowing from the at least one injection well in the direction of the at least one production well due to the injection pressure and thereby interacting with the oil-wetted surfaces the carbonate rocks mobilize petroleum, as well as

• Removal of crude oil through the at least one production well, and wherein the deposit has a deposit temperature in the range from 10°C to 130°C, and the deposit water has a salinity> 30000 ppm, and the aqueous composition has a pH of 5 to 9, and wherein at least one of the surfactants is an alkoxylated amine of general formula

R ¹ -N(R ² )R ³ (I), where the radicals R ¹ , R ² and R ³ have the following meanings:

R ¹ is a hydrocarbon radical having 8 to 22 carbon atoms,

R ² is a radical selected from the group consisting of H, hydrocarbon radicals having 8 to 22 carbon atoms, or a group -(CH2C(R ⁴ )HO) _X H and

R ³ is a group -(CH ₂ C(R ⁴ )HO) _X H, where R ⁴ and x have the following meanings

R ⁴ is independently H or an alkyl radical having 1 to 3 carbon atoms, x is independently a number from 1 to 80, and the pH of the aqueous composition is chosen so that the molar ratio of protonated alkoxylated amines R ¹ -N ⁺ H(R ² )R ³ to non-profanated alkoxylated amines R ¹ -N(R ² )R ³ is 1:10 to 10:1.

In a further embodiment, the present invention relates to an aqueous composition for extracting petroleum from underground petroleum deposits containing oil-wetted carbonate rocks, comprising at least one surfactant, the aqueous composition having a pH of 5 to 9, and at least one of Surfactants around at least one alkoxylated amine of the general formula

R ¹ -N(R ² )R ³ (I), where the radicals R ¹ , R ² and R ³ have the following meanings: R ¹ is a hydrocarbon radical having 8 to 22 carbon atoms,

R ² is a radical selected from the group consisting of H, hydrocarbon radicals having 8 to 22 carbon atoms, or a group -(CH20(R ⁴ )HO) _X H and

R ³ is a group -(CH ₂ C(R ⁴ )HO) _X H, where R ⁴ and x have the following meanings

R ⁴ is independently H or an alkyl radical having 1 to 3 carbon atoms, x is independently a number from 1 to 80, and the pH of the aqueous composition is chosen so that the molar ratio of protonated alkoxylated amines R ¹ -N ⁺ H(R ² )R ³ to non-profanated alkoxylated amines R ¹ -N(R ² )R ³ is 1:10 to 10:1. List of illustrations:

Figure 1 : Schematic representation of an Amott cell

Figure 2: Schematic representation of a core flooding system

Figure 3: Results of test series 1: oil saturation after flooding with reservoir water III and solutions of the comparison surfactants A3, A4 and A5 in LI 11

Figure 4: Results of test series 2: Reduction of oil saturation with L III and

A6 (10g/L) in LI II in FG308 saturated nuclei.

Figure 5: Results of test series 3, comparison of amine A 6; according to the invention) and comparative surfactant AO (not according to the invention).

FIG. 6: Results of test series 4, effect of the alkoxylated amines used according to the invention on aged cores

Figure 7 Results of Experimental Series 4 (cont.)

Figure 8: Results of test series 5; Flooding of the core with and without the addition of the alkoxylated amines used according to the invention

Figure 9: Results of test series 6; Behavior of the alkoxylated amines used according to the invention at different temperatures.

Figure 10: Schematic representation of the contact angle measurement. Figure 11: Oil detachment from an oil-wetted calcite plate in contact with reservoir water.

Figure 12: Oil detachment from an oil-wetted calcite plate in contact with a tenside solution (10 g/l tenside A6).

Figure 13: Sequence of contact angle measurements (from left to right) on a calcite slab after different treatment steps.

The following is to be explained in detail with regard to the invention:

To carry out the method according to the invention, an aqueous composition is used which comprises surfactants, where at least one of the surfactants is an alkoxylated amine.

Alkoxylated amines used

The alkoxylated amines used have the general formula (I).

R1 ^-N (R2 ^{) R3} (I).

Here, R ¹ is a hydrocarbon radical having 8 to 22, preferably 12 to 22, carbon atoms, for example having 14 to 20 or 16 to 18 carbon atoms. This can be a linear or branched, saturated or unsaturated, aliphatic and/or aromatic hydrocarbon radical.

R ¹ is preferably saturated or unsaturated aliphatic hydrocarbon radicals, in particular linear, saturated or unsaturated aliphatic hydrocarbon radicals.

Examples of hydrocarbyl groups R ¹ include alkylbenzyl, ethylhexyl, propylheptyl, decyl, lauryl, cetyl, stearyl or oleyl. Preferred examples include decyl, lauryl, cetyl, stearyl or oleyl groups. Of course, several different radicals R ¹ can also be present, such as products derived from natural products such as coconut oil. Examples of suitable hydrocarbon radicals R ¹ include oleyl, stearyl and lauryl groups, oleyl groups being particularly preferred.

R ² is a radical selected from the group consisting of H, hydrocarbon radicals having 8 to 22 carbon atoms, or a group -(CH2C(R ⁴ )HO) _X H.

If R ² is a hydrocarbon radical, it can be a linear or branched, saturated or unsaturated, aliphatic and/or aromatic hydrocarbon radical. act hydrogen radical, preferably saturated or unsaturated aliphatic hydrocarbon radicals, in particular linear, saturated or unsaturated aliphatic hydrocarbon radicals. The hydrocarbon radicals contain 8 to 22, in particular 12 to 22, carbon atoms, for example 14 to 20 or 16 to 18 carbon atoms. Examples of such hydrocarbon radicals, including preferred hydrocarbon radicals, have already been mentioned under R ¹ and we refer to the statements above. Hydrocarbon radicals R ² and R ¹ can be the same or different.

The group -(CH2C(R ⁴ )HO) _X H is a polyalkoxy group. The groups R ⁴ here represent H or an alkyl radical having 1 to 3 carbon atoms. In one embodiment, R ⁴ is H or a methyl group.

Thus, the group -(CH2C(R ⁴ )HO) _X H may include ethyleneoxy groups (EO), propyleneoxy groups (PO) or higher alkoxy groups (AO). If different radicals R ⁴ are present, EO, PO and AO groups can be arranged randomly, alternately or in blocks.

At least 50 mol % of the R ⁴ radicals present are preferably H, in particular at least 70 mol %, particularly preferably at least 85 mol %, and in one embodiment R ⁴ is H, ie only ethyleneoxy groups (EO) are present .

In the group --(CH2C(R ⁴ )HO) _X H, x is a number from 1 to 80, in particular 1 to 20 and for example 2 to 10 or 2 to 8.

In one embodiment of the invention, R ² is a radical selected from the group consisting of H or a group -(CH2C(R ⁴ )HO) _X H.

The group R ³ represents a -(CH2C(R ⁴ )HO) _X H as previously defined.

At least one -( _CH2C (R ⁴ )HO)XH group is present in the amines of the formula (I) used. R ² is preferably also a group —-(CH 2 C(R ⁴ )HO) _X H, it being possible for such a group to be the same as or different from R ³ .

The amines of the formula (I) are preferably those in which R ¹ is an aliphatic, saturated or unsaturated hydrocarbon radical having 12 to 22 carbon atoms and R ² and R ³ are independently groups —-( ^CH2C (R4)HO ) _X H, where x is 1 to 80, preferably 1 to 20.

In one embodiment of the invention, R ¹ represents at least one group selected from oleyl, stearyl and lauryl groups, preferably an oleyl group, and R ² and R ³ independently represent groups -(CH2C(R ⁴ )HO) _X H, where x is 1 to 20, in particular 2 to 10, preferably 2 to 8. Other surfactants

In one embodiment of the invention, the aqueous composition comprises further surfactants in addition to the alkoxylated amines of the formula (I). Other surfactants can be used, for example, to reduce the interfacial tension between oil and water in order to be able to ensure even better oil removal from the reservoir. In addition, the addition of other surfactants can improve the solubility of the alkoxylated amines, particularly in the presence of highly saline reservoir water.

Further surfactants can be cationic, amphoteric, nonionic or anionic surfactants, preferably cationic, anionic or amphoteric surfactants. Betaines and anionic saturated or unsaturated aliphatic alkoxy sulfates and alkoxy carboxylates are particularly preferred.

Other surfactants can in principle be used in any ratio to the alkoxylated amines of the formula (I). In general, however, the amount of other surfactants should not exceed 50% by weight, based on the amount of all surfactants in the aqueous composition. In further embodiments, the amount of other surfactants does not exceed 30% by weight, based on the amount of all surfactants in the aqueous composition. In one embodiment only one or more surfactants of general formula (I) are present. While the interfacial tension between salty water and crude oil can typically be reduced to values of about 2 to 0.1 mN/m by the alkoxylated amines of the formula (I) alone, this can be further reduced by adding further surfactants to the extent that an additional Oil discharge from the rock becomes possible (e.g. reduction to 0.02 mN/m by mixing with a Ci6/18 propoxysulphate).

Other components

The aqueous composition can optionally include further components.

In one embodiment of the invention, the aqueous formulation used comprises at least one complexing agent. Examples of suitable complexing agents are mentioned in WO 2015/086468 A1, page 38, lines 8 to 23.

In a further embodiment, the aqueous formulation used comprises thickening polymers, for example polysaccharides such as xanthan or schizophyllan, or copolymers of acrylamide and acrylic acid sodium salt, acrylamide and 2-acrylamido-2-methylpropanesulfonic acid sodium salt, acrylamide and acrylic acid sodium salt and N-vinylpyrrolidone , acrylamide and acrylic acid sodium salt and 2-acrylamido-2-methylpropanesulfonic acid sodium salt, acrylamide and acrylic acid sodium salt and 2-acrylamido-2-methylpropanesulfonic acid sodium salt and N-vinylpyrrolidone. Alternatively, the polymers mentioned above can also contain other groups which, for example, lead to further associative thickening through hydrophobic-hydrophobic interactions. Suitable polymers are, for example, in WO 2015/086468 A1 enumerated. If present, the concentration of polymer in the aqueous composition is usually 0.02 to 2% by weight, based on the sum of all components of the aqueous formulation. The amount is preferably 0.05 to 1% by weight, particularly preferably 0.1 to 0.8% by weight and for example 0.1 to 0.4% by weight.

Other additives such as biocides, stabilizers, free-radical scavengers and inhibitors can be added to stabilize the polymers.

In one embodiment of the invention, the aqueous composition used comprises at least one oxygen scavenger in addition to the polymer. Examples of suitable oxygen scavengers are mentioned in WO 2015/086468 A1, page 37, lines 13 to 17.

In a further embodiment of the invention, the aqueous composition used comprises at least one radical scavenger in addition to the polymer. Examples of suitable free-radical scavengers are listed, for example, in WO 2015/086468 A1, page 37, lines 19 to 40.

In a further embodiment of the invention, the aqueous composition used comprises at least one sacrificial reagent in addition to the polymer. Examples of suitable sacrificial reagents are listed, for example, in WO 2015/086468 A1, page 38, lines 1 to 6.

The aqueous composition used can also include bases, where the proportion of calcium ions in the formation water should not be too high when using bases in order to avoid the precipitation of carbonates. Optionally, complexing agents can be used to prevent precipitation.

Aqueous composition

The aqueous composition for carrying out the process according to the invention comprises at least water and alkoxylated amines of the formula (I). Preferred alkoxylated amines (I) have already been mentioned.

The concentration of the alkoxylated amines (I) in the aqueous composition is preferably from 0.05 to 2% by weight, based on the sum of all the components of the aqueous composition. The concentration of the alkoxylated amines is preferably from 0.06 to 1% by weight, particularly preferably from 0.08 to 0.5% by weight.

The water can be fresh water, river water, sea water, water from an aguifer near the reservoir, reservoir water or production water. Of course, mixtures of the waters mentioned can also be involved. It can also be saline water which has been obtained from saline water, for example by partial desalination, depletion of multivalent cations or by dilution with fresh water or drinking water. In one embodiment of the invention, the aqueous composition contains at least one organic cosolvent. Cosolvents are preferably completely water-miscible solvents, but solvents which are only partially water-miscible can also be used. As a rule, the solubility in water should be at least 0.5 g/l, preferably at least 1 g/l. Examples include aliphatic C4 to Cs alcohols, preferably C4 to Ce alcohols, which can be substituted with 1 to 5, preferably 1 to 3, ethyleneoxy units to achieve sufficient water solubility. Further examples include aliphatic diols having 2 to 8 carbon atoms, which can optionally also be further substituted. For example, it can be at least one cosolvent selected from the group consisting of 2-butanol, 2-methyl-1-propanol, butyl glycol, butyl diglycol or butyl triglycol.

The pH of the aqueous composition is 5 to 9, in particular 5 to 8, preferably 6 to 8, and for example pH 5, pH 5.5, pH 6, pH 6.5, pH 7, pH 7.5, or pH 8th.

The pH can be adjusted using various methods.

In one embodiment of the invention, the pH of the ready-mixed aqueous composition is provided in a mixing tank prior to injection into the wellbore. An acid or base can be used to adjust the pH. A suitable buffer system can also be used.

In another embodiment, at least one alkoxylated amine (I) or an aqueous solution thereof is added to an aqueous composition not already containing the alkoxylated amine (I) while flowing through the conduit to the wellbore. The alkoxylated amines (I) mix with the aqueous phase as it flows through the line and the pH adjusts accordingly. The pH of the solution of the alkoxylated amine (I) or of the aqueous composition may have to be adjusted beforehand so that the desired pH results after mixing.

According to the invention, the pH of the aqueous composition is chosen so that in the aqueous composition the alkoxylated amines are present in the profaned form R ¹ -N ⁺ H(R ² )R ³ as in the non-profaned form, the molar ratio of profaned to non-profaned form ranges from 1:10 to 10:1. The ratio can easily be calculated if the pKß value of the alkoxylated amines is known. The pKß value can be determined in a manner known in principle via a titration. Details are shown in the example section.

The aqueous composition for carrying out the method according to the invention is obtained by mixing the components. In one embodiment of the invention, the alkoxylated amines (I) can be provided as an aqueous concentrate which, for production reasons, can also contain salt. Such an aqueous concentrate may comprise, for example, 10% to 80% by weight of the alkoxylated amines of formula (I). Oil extraction process

The method according to the invention is used for the extraction of petroleum from underground petroleum deposits containing oil-wetted carbonate rocks.

The composition of carbonate rocks can vary. In addition to calcite and/or dolomite, these typically also contain other components such as ankerite, feldspar, quartz, clay minerals (e.g. kaolin, illite, smectite, chlorite), halite, iron oxides, pyrite, gypsum and/or Epsom salt. Exemplary compositions of carbonate rocks can be found, for example, in Table 2 of Colloids and Surfaces A: Physicochem. Closely. Aspects 450 (2014) 1- 8 or in example 5 on page 17 of WO 2015/173 339 A1. For example, it can be a carbonate rock which comprises about 82% by weight of calcite and also about 9% by weight of quartz, 4% by weight of ankerite, 1% by weight of pyrite and about 4% by weight. % clay minerals or a carbonate rock comprising 71% by weight calcite, 16% by weight quartz, 1% by weight potassium feldspar, 1% by weight siderite, 2% by weight pyrite and 9% by weight clay minerals. The quantities mentioned relate to the sum of all components of the carbonate rock.

Deposits with a carbonate rock which has a high proportion of calcite (>80% by weight, preferably>90% by weight, particularly preferably>95% by weight) and a low quartz content are particularly suitable for carrying out the method according to the invention (<10% by weight, preferably <5% by weight, particularly preferably <2% by weight) and a small proportion of clay minerals (<10% by weight, preferably <5% by weight, particularly preferably < 2% by weight). One embodiment of the invention relates to a deposit which comprises carbonate rock which contains approximately 98% by weight of calcite, approximately 1% by weight of dolomite and approximately 1% by weight of halite.

The temperature of the deposit can be 10°C to 130°C, in particular 30°C to 120°C, preferably 30°C to 100°C, in particular 40°C to 70°C.

The salinity of the reservoir water is >30,000 ppm, in particular >70,000 ppm, and preferably >100,000 ppm (weight fraction of dissolved salts (TDS) based on the total weight of the reservoir water). Salinity can be determined by inductively coupled plasma mass spectrometry (ICP-MS). The salts in the reservoir water can in particular be alkali metal salts and alkaline earth metal salts. Examples of typical cations include Na ⁺ , K ⁺ , Mg ²⁺ and/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 addition, alkaline earth metal ions can also be present, the weight ratio of alkali metal ions to alkaline earth metal ions generally being >2, preferably >3. At least one or more halide ions, in particular at least Cl′, are generally present as anions. In general, the amount of CI' is at least 50% by weight, preferably at least 80% by weight, based on the sum of all anions. in a According to the invention, the reservoir water has at least 100 ppm of divalent cations, in particular alkaline earth metal ions. The amount of alkaline earth metal ions can be 100 to 53000 ppm, for example! 20 ppm to 20000 ppm or 150 to 6000 ppm.

The pH value of the formation water of the carbonate deposit is 5 to 9. The pH value of the deposit is influenced, among other things, by dissolved CO2.

The method according to the invention can be used in particular in petroleum deposits with an average permeability of ⁵ mD (5* ^10'15 m2) to 1 D (1* ^10'12 m2), preferably ⁵ mD ( ⁵ * ^10'15 m2) to 500 mD (500 * 10' ¹⁵ m ² ) can be applied. The permeability of a petroleum formation is given by the expert in the unit "Darcy" (abbreviated "D" (10 ^-12 m ² ) or "mD"(10' ¹⁵ m ² ) for "millidarcy") and can be calculated from the flow rate of a liquid Phase can be determined in the petroleum formation depending on the applied pressure difference. The flow rate can be determined in core flood tests with drill cores taken from the formation. Details on this can be found, for example, in K. Weggen, G. Pusch, H. Rischmüller in "Oil and Gas", pages 37 et seq., Ullmann's Encyclopedia of Industrial Chemistry, online edition, Wiley-VCH, Weinheim 2010. For the person skilled in the art It is clear that the permeability in an oil reservoir does not have to be homogeneous, but generally shows a certain distribution and that the permeability of an oil reservoir is therefore an average permeability.

To carry out the method according to the invention, at least one production well and usually also at least one injection well are drilled into the oil deposit. As a rule, a deposit is provided with several injection wells and several production wells. There may be vertical and/or horizontal wells or slant wells.

The aqueous composition described is injected into at least one part of the oil deposit through at least one injection well, with the aqueous composition flowing from the at least one injection well in the direction of the at least one production well due to the injection pressure and thereby mobilizing crude oil through interaction with the oil-wetted surfaces of the carbonate rocks. The mobilized crude oil can be extracted from the deposit through at least one production well. Alternatively, it is also possible to inject through a hole and produce from the same hole after the injection (huff-and-puff technique).

In this context, the term “petroleum” does not of course mean only phase-pure oil, but the term also includes the usual crude oil-water emulsions.

The aqueous composition can be injected using conventional devices. The formulation can be injected into one or more injection wells using conventional pumps. The injection wells are usually cemented in Lined with steel tubes, and the steel tubes are perforated at the desired location. The formulation enters the petroleum formation through the perforation from the injection well. The flow rate of the formulation and thus also the shear stress with which the aqueous formulation enters the formation is determined in a manner known in principle via the pressure applied by means of the pumps. The shear stress when entering the formation can be calculated by a person skilled in the art in a manner known in principle on the basis of the Hagen-Poiseuille law using the area through which flow occurs when entering the formation, the average pore radius and the volume flow. The average permeability of the formation can be determined in a way that is known in principle, as described.

In one embodiment of the invention, the aqueous composition used comprises at least one base and optionally a complexing agent, such as a polyacrylate, in addition to the alkoxylated amines (I). This embodiment can be used in particular when the proportion of polyvalent cations in the reservoir water is low (100-400 ppm). An exception is sodium metaborate, which can be used as a base even without complexing agents in the presence of significant amounts of polyvalent cations.

In a further embodiment of the invention, the aqueous composition used comprises, in addition to the alkoxylated amines (I), polymers and surfactants other than the alkoxylated amines (I), for example anionic, cationic or amphoteric surfactants. In this embodiment, preferably no bases such as Na2COs are used.

Wasserfluten. The method according to the invention can of course include further method steps. In particular, the method can be combined with further flooding steps. In one embodiment of the invention, the method comprises at least water flooding as an additional method step. In principle, the water flooding is carried out in the same way as the process according to the invention, only water is used as the flooding medium instead of the aqueous composition described. The water can be fresh water or saline water such as sea water or reservoir water, or mixtures thereof. Various combinations of process steps are possible, such as water flooding -> process according to the invention, water flooding process according to the invention or water flooding process according to the invention

water floods.

In one embodiment of the invention, the aqueous composition used can also be foamed. Similar to aqueous compositions thickened with the help of polymers, foams serve to control mobility. Foams can be generated at the surface using gases and injected, or they can be generated in-situ in the reservoir after injecting the aqueous composition by additionally injecting gases into the reservoir. Examples of gases include nitrogen, carbon dioxide, or gaseous hydrocarbons such as methane, ethane, or propane, or mixtures thereof. For generation and stabilization of the foam, suitable foam-forming surfactants, such as betaines, can be used in addition to the alkoxylated amines (I) used according to the invention.

advantages

The alkoxylated amines (I) used in the present invention improve oil release from differentially wetted carbonate rocks by improving the imbibition of an aqueous medium into the rock.

According to an existing theory, the petroleum components adsorbed on the carbonate surfaces are mobilized by the formation of ion pairs. The alkoxylated amines (I) are profaned by the mixing water and/or reservoir water and can now interact in their cationic form with negatively charged crude oil components. The rock surface becomes more water-wettable again. The capillary forces that develop again allow a watery fluid, which displaces the crude oil, to penetrate into the rock pores.

In addition, the reduction in interfacial tension by the alkoxylated amines (I) used according to the invention in their cationic form can promote gravity-driven deoiling as the water level rises in fissured carbonate deposits. The reduction in interfacial tension between crude oil and aqueous fluid also leads to a reduction in crude oil saturation in the rock, which results from the truncation or splitting of coherent oil ganglia and droplets, and the entrapment of individual, immobile oil droplets in the aqueous phase within the rock pores. The particular suitability of the alkoxylated amines used according to the invention for this purpose results from their low adsorption on the rock and the high availability of the surfactant based on this when small amounts of the substance used are used.

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

used material

1 . Investigated amines

The following amines were used for the examples and comparative examples:

2. Preparation of the salt solutions used for the tests

Different aqueous salt solutions were prepared to simulate the conditions in the reservoir. For this purpose, salts were weighed into distilled water and dissolved by stirring at 20°C. Finally, the desired pH value was adjusted with acid or base, the saline solution was stored closed and checked for clarity for several days. The following salt solutions were prepared:

Synthetic sea water (SSW) with 43,910 ppm TDS containing 30.53 g/l NaCl, 2.11 g/l CaCl ₂ x 2 H ₂ O, 13.97 g/l MgCl ₂ x 6 H ₂ O, 5.03 g /l Na ₂ SO ₄ , 0.21 g/l NaHCO ₃ - pH adjusted to 8.0

Exemplary synthetic reservoir water I (L1) with 30,0000 ppm TDS containing 18.38 g/l NaCl, 10.58 g/l CaCl ₂ x 2 H ₂ O, 4.7 g/l MgCl ₂ x 6 H ₂ O, 0, 15 g/l Na ₂ SO ₄ - pH adjusted to 6.6

Exemplary synthetic reservoir water II (L2) with 48,500 ppm TDS containing 33.99 g/l NaCl, 12.98 g/l CaCl ₂ x 2 H ₂ O, 5.85 g/l MgCl ₂ x 6 H ₂ O, 0.55 g/l KCl, 0.54 g/l SrCl ₂ x 6 H ₂ O, 1.1 g/l Na ₂ SO ₄ - pH adjusted to 6.6

Exemplary synthetic reservoir water III (L3) with 210,0000 ppm TDS containing 164.15 g/l NaCl, 48.24 g/l CaCl ₂ x 2 H ₂ O, 16.97 g/l MgCl ₂ x 6 H ₂ O, 1 , 15 g/l Na ₂ SO ₄ - pH adjusted to 6.6

Accomplished tests

1. Determination of solubility

The solubility of the above-mentioned (alkoxylated) amines or mixtures of the amines with other surfactants was determined in synthetic reservoir water (LI, LH, or L III) at a concentration of 10 g/1 (total concentration of surfactants and optionally other surfactants). The amines were stirred in the selected reservoir water at 20-30° C. for 30 minutes. Thereafter, the pH was adjusted to 7 and heated to the desired target temperature (see Table 1).

In the case of mixtures, the amine was dissolved in a first vessel. Additional surfactants were dissolved in a second vessel. Both solutions were then combined at 20-30° C., the pH adjusted to 7 and then heated to the target temperature.

To assess the solubility, the appearance of the solutions after 24 h storage at the target temperature was noted. The following solutions were considered acceptable:

• Clear solutions

• Solutions that are slightly scattering, but lighten up again just by shaking them slightly (but do not cream over time (form two phases)).

The results are summarized in Table 1:

Table 1: Solubilities in salt water with amine mixtures of the general formulas (I) and (II) and any other ionic surfactant at pH 7 (the ratios given are weight ratios).

2. Determination of chemical stability

10 g of amine were stirred into 1 l of reservoir water III at 20-30° C. for 30 min and the pH of the solution was adjusted to 6 with hydrochloric acid. In order to avoid degradation of the amines by oxygen at high temperatures, NaMBT and Na2SO3 were used as radical scavengers and as oxygen scavengers (1 percent by weight based on the content of surfactants in the aqueous salt solution containing 50 ppm Na2SO3 and 20 ppm sodium 2-mercaptobenzothiazole). In addition, an argon atmosphere was used and the aqueous solutions were freed of oxygen by introducing argon for 30 minutes. A glass vessel with a screw cap was used, which is approved for absolute pressures of up to 5 bar.

Thereafter, the sealed glass vessels were heated to 125°C. Several jars of each mixture were prepared with said solution and all stored at 125°C. After 0, 2, 4, 8 and 12 weeks, a jar containing the solution was cooled to 20°C and opened. The stored solution was then examined by HPLC chromatography in gradient mode with solvent A [1900 ml water + 100 ml 0.1M ammonium acetate] and solvent B [methanol/acetonitrile 8/2 V/V], light scattering detector) and the percentage of intact starting compound was determined . The measurement inaccuracy was +1-2 to +/- 4%.

Table 2: Percentage of intact surfactant as a function of storage time

3. Reduction of oil saturation in rock by imbibition

Experiments on spontaneous imbibition were carried out in comparison with various salt solutions (sols) and solutions of protonated amines, optionally with the addition of other surfactants based on these same salt solutions.

The spontaneous imbibition test carried out in Amott cells (Amott, Aime, Petr. Trans. SPE-1167-G, 1959) aims to determine the proportion of oil that can be produced purely by capillary and/or gravitational forces from rock cores of defined dimensions and known mineralogical shear composition. In a figurative sense, a fissured (carbonate) oil deposit is simulated, with the rock core representing a relatively poorly permeable rock matrix and the surrounding fluid in the Amott cell simulating the injected flood medium in a fissure. The structure of the glass cells used for temperatures up to 70 °C is shown in Figure 1. A rock core (1) saturated with brine and crude oil is immersed in an aqueous solution. The bottom of the core is held above the glass bottom by spacers (2) to allow ingress of the aqueous solution and exit of crude oil. The capillary force driven imbibition is unidirectional. The crude oil exiting the core rises due to the difference in density and is collected (4) in a graduated riser (3). The amount of oil can be read with an accuracy of ±0.1 ml. For improved temporal resolution, a camera can be used that records the filling levels at defined time intervals.

Rock cores consisting mainly of calcite were used to measure the spontaneous imbibition. The properties are summarized in Table 3.

Table 3: Properties of the rocks used in the imbibition tests

*Bimodal pore radius distribution

Preparation of the rock cores for the imbibition

Imbibition tests were performed on cores with and without initial water saturation. All rock cores drilled from a rock block were first dried at 105 °C.

To create an initial water saturation, the rock cores were then evacuated in the desiccator (approx. 1 mbar) and saturated under vacuum with the appropriate salt solution at room temperature. Based on this, the porosity and the pore volume of the respective sample is determined on the basis of the rock masses before and after saturation, the fluid density and the geometric sample dimensions.

The cores were then saturated with oil, with part of the water being displaced by oil. Methods for oil saturation of rock cores are known in principle. Ultimately, the decisive factor for the further course of the test is not the way of preparation, but the saturation value achieved for crude oil and aqueous salt solution as well as the properties of the fluids used. Saturation with oil can, for example, be carried out directly in a flood cell. A flood cell is shown schematically in Figure 2. The abbreviations have the following meanings: double piston pump (A), piston accumulator with crude oil (B), reservoir with brine or white oil (C), flood cell with core holder (D), manual pump for jacket pressure (E), autosampler (F), back pressure regulator (G ) and vacuum pump (H). Pi , P2 and Pc are pressure sensors for inlet, outlet and shell pressure.

In the core holder (D), the porous rock core sits in a rubber sleeve, to which jacket pressure is applied from the outside in order to avoid edge leakage. Using the double piston pump (A), crude oil is injected from the piston accumulator (B) into the rock core at a constant volume flow in order to dynamically displace the saline solution there. The water and oil saturation set in this way in the rock core was determined volumetrically and gravimetrically. Rock cores without initial water saturation were first saturated with white mineral oil under vacuum in a flood cell (see Figure 2Error! Reference source could not be found.) and then flooded with crude petroleum against atmospheric pressure. Porosity and pore volume were then determined by weighing.

Tests in Amott cells

In some of the tests, the oil-saturated rock cores were then transferred directly to Amott cells with the appropriate salt or amine solution (10 g/l active substance).

Other rock cores were first aged by being surrounded with crude oil and stored at 70 °C in a pressure-tight autoclave under an argon atmosphere for a certain period of time. Before being transferred to Amott cells, aged cores were first cooled to room temperature in an autoclave, then weighed and photographed.

The filled Amott cells were stored in a heating cabinet at 70°C or 120°C and the amount of crude oil produced was determined volumetrically at fixed time intervals via a graduated riser pipe above the rock core. The duration of the test was between one day and 100 days, depending on the preparation method, the crude oil used and the salt or amine solution used.

Salt and amine solutions were tested on rock samples with different wetting behavior. The wetting preference was adjusted via the wetting properties of the crude oil used.

A crude oil with 33°API from a German storage cavern was used for the tests, which is referred to as FG308 in the following. The viscosity of the oil was 8.5 mPas at 20 °C and 2.6 mPas at 70 °C. Due to its low acid number/neutralization number (specified as TAN - total acid number in rngKon/goi), it is characterized by low wetting properties compared to the model rock used (Outcrop Estaillade, Limestone). The TAN is < 0.2 rngKon/goi. Observed wetting changes in the rock are caused by deposits/precipitations of petroleum components. The content of n-heptane-insoluble components (mainly asphaltenes) is approx. 2%. The wetting properties of FG308 were also modified by the addition of carboxylic acids (octadecanoic acid and 2-ethylhexanoic acid). For some of the tests, 1.5 g/kg of octadecanoic acid (also stearic acid, hence FG308/SA) was added to FG308. For another part of the tests, FG308 was modified with a mass fraction of 0.76 g/kg 2-ethylhexanoic acid (FG308/2-EHA). Both modifications lead to a TAN of 0.4 rngKon/göi, but show a different degree of wetting tendency. According to the increasing tendency towards oil wetting, the result is: FG308 < FG308/2-EHA < FG308/SA. This enabled the preparation of oil wetted and mixed-wet (MXW) core samples.

Samples that were 100% oiled with pure FG308 (S _w ,i = 0) showed the imbibition behavior of a predominantly water-wetted porous medium.

The following results were obtained:

All aqueous solutions were adjusted to pH 7 ± 0.5 before use. Unless otherwise stated, the imbibition tests were carried out at 70°C.

Test series 1:

Use of the amines A3, A4 and A5 (not according to the invention)

Three cores were completely saturated with reservoir water III (pH 7±0.5). The cores were then flooded with FG308 crude oil and aged in an autoclave at 70 °C for 14 days. The initial oil saturation was between 50 and 70%. The cores were first imbibed with reservoir water III in an Amott cell until no more oil was produced. The subsequent imbibition with a solution of the amines A3 (n-propylamine), A4 (dipropylamine) and A5 (tripropylamine) in a concentration of 10g/kg in reservoir water L III did not allow a significant reduction in the oil saturation in the core.

The results are shown in Figure 3:

Test series 2:

Use of the amine A6 (according to the invention)

Two rock samples were prepared as described above. The samples were then aged in FG308 for 14 days. The initial oil saturations (crude oil FG308) of 56 and 59% differ only slightly. A rock core was imbibed with reservoir water L III. The second rock core was imbibed directly with amine solution A6. The rock sample Contact with the amine solution produces significantly more oil in a short time (one day) than the rock sample in contact with reservoir water L III.

The results are shown in Figure 4.

Test series 3:

Use of the amine A6 (according to the invention) compared to the amine A0 (not according to the invention)

Two rock samples were prepared as described above. The samples were then aged in FG308 for 14 days. The initial oil saturations (crude oil FG308) were 56 and 60%. Both rock cores were initially imbibed with reservoir water L III (not shown in Figure 5) until no more oil was produced. The oil saturation was then at 49 or 53%. A rock sample was then imbibed with 10 g/l of the comparison surfactant A0 and the second rock sample with 10 g/l of the alkoxylated amine A6 to be used according to the invention (both in reservoir water L III). Both rock samples show an almost identical course of the additional de-oiling.

The result is shown in Figure 5.

Test series 4:

Use of the amine A6 (according to the invention) and crude oil FG308/2-EHA

Four core samples were prepared as described above. Rock samples were aged in FG308/2-EHA crude oil at 120°C for different periods of 0, 1, 7, and 14 days. Subsequently, three of the samples (aging 0, 1 and 14 days) were imbibed with reservoir water L III. A sample (aging 7 days) was imbibed directly with 10 g/l amine A6 in reservoir water L III (see Figure 6). The first three samples show a clear trend in relation to the aging period. As the aging period increases, the production rate and the amount of oil produced decreases (residual oil saturation is lower). In contrast, the rock core exposed to Amin A6 produces significantly more oil despite aging for seven days.

Replacing L III with 10 g/l A6 in L III for the first three samples also results in further de-oiling (see Figure 7). Here, too, the production rate and the residual oil saturation achieved are still strongly dependent on the original wetting condition (or the aging period) of the rock sample.

The results are shown in Figures 6 and 7.

Test series 5:

Use of the amine A6 (according to the invention) in comparison to reservoir water L III without the addition of amine Two core samples were prepared using FG308 crude oil as described above and then aged for 14 days in the same crude oil. In these samples, the outermost 2 mm of the lateral and frontal surfaces were also cleanly turned on a lathe after aging in crude oil in order to remove any precipitation of poorly soluble components from the oil on these surfaces, which initially prevent imbibition. In fact, these nuclei show a very fast imbibition process driven by capillary forces. The first sample was imbibed with L III, the second sample with 10 g/l A6 in L III. Figure 8 shows the curves. In the case of samples, the maximum reduction in oil saturation is already achieved after one day at the latest, whereby the oil production of the sample in contact with A6 begins earlier and also leads to maximum de-oiling earlier (after approx. 5 hours). In addition, the overall saturation of this sample was reduced more.

The results are shown in Figure 8.

Test series 6:

Behavior of the amine A6 (according to the invention) at two different temperatures

Standnes and Austad (Standnes, DC ; Austad, T.: Wettability Alteration in Chalk: 1. Preparation of Core Material and Oil Properties. In: Journal of Petroleum Science and Engineering 28 (2000), No. 3, pp. 111-121 ¹ Standnes, DC Austad, T.: Nontoxic low-cost amines as wettability alteration chemicals in carbonates In: Journal of Petroleum Science and Engineering 39 (2003), 3-4, pp. 431-446 Standnes, DC: Enhanced Oil Recovery from Oil-Wet Carbonate Rock by Spontaneous Imbibition of Aqueous Surfactant Solutions University of Stavanger, Department of Petroleum Technology Dissertation, 2001) describe that the effectiveness of primary amines (especially Cw-amine or C10NH2) increases with increasing temperature decreases. Thus, no satisfactory solubility could be achieved with n-dodecylamine under the chosen experimental conditions. In distilled water, there was an increase in deoiling with a reduction in temperature from 70°C to 40°C in oil-wetted chalk rock cores. With 1 percent by mass of n-decylamine in salt solution, the de-oiling of mixed-wetted and oil-wetted dolomite rock cores increases significantly when the temperature is reduced from 70 °C to 40 °C or reduced to room temperature (20 °C). This is different when using the alkoxylated amines according to the invention.

Two rock samples were prepared using Preparation Method 1 with reservoir water L III and FG308 crude oil and aged for 14 days in FG308 crude oil. The saturated and aged rock samples were then imbibed with reservoir water III at 70°C until no more oil was produced. The first sample was then imbibed at 20° C. and the second sample at 70° C. with 10 g/l amine A6 in reservoir water III. Despite the slightly different initial saturation states, the production rates are almost identical and, in particular, the final residual oil saturations are the same. This confirms what was previously described and allows the alkoxylated amines of this invention to be used over a wider temperature range than the primary amines used by Austad and Standnes. The results are shown in Figure 9.

4. Determination of the interfacial tension

Interfacial tensions of crude oil in relation to the above-mentioned saline waters, each containing 10 g/L of the amines or amine/surfactant solutions to be tested, were determined at the indicated temperatures using a spinning-drop method using an SVT20 tensiometer from DataPhysics. For this purpose, a drop of oil was injected into a capillary filled with a salt-containing amine solution and, after reaching the measurement temperature, the expansion of the drop was observed at around 4500 revolutions per minute, and the development of the interfacial tension over time was noted. The interfacial tension IFT (or sn) is calculated according to the following formula from the cylinder radius r _z , the speed w, and the density difference (di-d2) (AM Seifert, JH Wendorff, Colloid Polym Sei, 1992, 270, 963): s H = 0.25 ■ r _z ³ ■ w2 ■ (di-d2).

Crude oils with different densities, described by their API grade, were used for the investigations. The API degree (American Petroleum Institute degree) is a conventional unit of density for crude oil used in the USA. It is used worldwide to characterize and measure the quality of crude oil. API gravity is the specific gravity of crude oil at 60°F (15.56°C) based on water

API degree = (141.5 / p _rei ) - 131.5.

An additional solubilization due to a reduction in the interfacial tension of crude oil usually results from values of less than 0.1 mN/m. The values given for amine/surfactant mixtures are the minimum values obtained for testing between 0:10 and 10:0 (measured in increments of 1 or 0.5).

The results are given in Table 4 below. The lowest interfacial tension achieved within one hour is given in each case.

Table 4: Results of the I FT measurements

The surfactants of the general formula (I) serve to rewet the surfaces of carbonate rocks. However, they also have the advantage of reducing the interfacial tension of crude oil compared to saline water, with the reduction in interfacial tension being comparable to that of other surfactants. The blending of the surfactant A6 with various anionic alkyl polyalkoxylates (T1, T2 and T3) leads to a significant reduction in the interfacial tension compared to the use of A6 alone. This can be seen, for example, by comparing experiments 1 and 3, 4 and 5, or 6 and 8.

5. Oil release and contact angle measurements

The measurements were carried out on calcite slabs which, as a result of aging in reactive crude oil (FG308 as described above), show significant wettability for crude oil.

Calcite plates aged for 24 hours at 70 °C in crude oil were brought into contact with a salt or surfactant solution heated to 70 °C. The behavior of the oil detachment was documented with a camera.

Contact angle measurements of an oil drop (“captive drop” method) through the aqueous phase (saline solution) were carried out under atmospheric conditions on calcite plates. The measurements were taken in the following order: reference measurements after cleaning the calcite plates, after aging the calcite plates in oil for 24 h at 70°C, after placing the calcite plates in the tenside solution preheated to 70° C for 15 minutes. The results show a clear trend towards increasing water wetting of the calcite plates after treatment with surfactant solution.

The considered contact angle 0 is shown in Figure 10. The figure shows the measured contact angle between the oil drop and the calcite plate. The oil drop is deposited in the aqueous phase from below on the plate using a capillary.

Comparison: Oil detachment with reservoir water III

About 10 ml of reservoir water III were heated to 70 °C in a screw-top jar whose bottom is covered with glass marbles. The fresh split piece of a calcite crystal (“Iceland Spar”) measuring 0.2 x 1 x 2 cm was aged in K308/SA crude oil for 24 h at 70 °C and then transferred to the screw-top jar with the salt solution. The detachment of the crude oil was documented by means of video and photo recordings. When in contact with a salt solution, hardly any oil detachment can be observed even after four months of standing and the calcite plate is clearly wet with oil.

The result is shown in Figure 11.

Oil removal with reservoir water III and surfactant A6

10 g/l of surfactant A6 were dissolved in reservoir water III. About 10 ml of this solution were heated to 70° C. in a screw-top jar whose bottom is covered with glass marbles. The fresh split piece of a calcite crystal (“Iceland Spar”) measuring 0.2 x 1 x 2 cm was aged in K308/SA crude oil for 24 h at 70 °C and then transferred to the screw-top jar with the tenside solution. The detachment of the crude oil was documented by means of video and photo recordings. Immediately after contact with the tenside solution, the oil film wetting the plate tears, the oil coagulates into larger droplets that quickly separate. After a contact time of approx. 40 seconds, only a few small oil droplets remain, the shape of which reflects a clear wetting of the plate with water. If the contact time is longer, the fine oil droplets also detach and rise. The oil is also stripped from the underside of the plate.

The result is shown in Figure 12.

Contact angle measurement with surfactant A6

10 g/l of surfactant A6 were dissolved in reservoir water III. About 10 ml of this solution were heated to 70° C. in a screw-top jar whose bottom is covered with glass marbles. The fresh split piece of a calcite crystal ("Iceland Spar") measuring 0.2 x 1 x 2 cm was ground and polished on one side to create an ideally smooth surface and to minimize the influence of surface roughness on the contact angle. The plate was washed with isopropyl cleaned and dried with charcoal and deionized water. The plate was installed in the measuring cell, surrounded with reservoir water III and a small drop of FG308 oil was deposited below the plate with the help of a capillary. The contact angle was determined after waiting five minutes. The panel was removed, rinsed with deionized water, dried and aged for 24 h at 70°C in FG308/SA crude oil. The plate was then removed from the oil, excess oil briefly rinsed off with toluene and n-heptane, dried and reinstalled in the measuring cell, surrounded with reservoir water III, a drop of oil FG308 deposited below and the contact angle determined after a waiting time of 5 minutes. The plate was removed from the measuring cell, rinsed with deionized water, dried and placed in the surfactant solution with A6 at 70° C. for 15 minutes. The plate was removed from the tenside solution, rinsed with deionized water, dried and surrounded in the measuring cell with reservoir water III. A drop of FG308 oil was then deposited underneath the plate and the contact angle was determined after waiting 5 minutes.

Before aging in crude oil, the contact angle is 83° ± 5°. The plate is in the transition from non-wetting (< 90°) to wetting (> 90°). After aging in crude oil, the contact angle is 120° ± 5°. The plate is in the condition of heavy oil wetting due to adsorbed crude oil components. After treatment with surfactant solution, the contact angle is 55° ± 5°. The plate shows a clear tendency towards non-wettability for crude oil (preferably water-wetted) due to the detachment of the adsorbed oil components and the resulting change in wetting due to surfactant contact.

The result is shown in Figure 13.

6. Determination of the degree of protonation

The following equilibrium reaction applies to the base reaction using the example of the tertiary amines (NR3) as weak bases:

NR ₃ + H ₂ O (HNR ₃ ) ⁺ + (OH)'

The equilibrium constant KB describes the ratio of the components per molar concentration to one another using the following equation:

KB = ( [(HNR ₃ ) ⁺ ] « [(OH)-] ) / [NR ₃ ]

Converting the above equation to the negative logarithm of the decade, when the molar concentrations of (HNR ₃ ) ⁺ and NR ₃ are equal, the pOH is equal to the pKß. If the molar concentrations of (HNR ₃ ) ⁺ and NR ₃ are the same, this is referred to as the half-equivalence point in the case of a titration. This point is recognized as the turning point of a titration curve.

The surfactant A6 (ethoxylated N-oleylamine with an average of 12 EO units) was dissolved in distilled water, a pH value of pH=13 at 20° C. was set by adding sodium hydroxide solution and the amount of NaOH added was noted. Then with hydrochloric acid titrated at 20°C. The titration yields the known titration value for the strong base (NaOH) and the titration value for the weak base (surfactant A6). The half-equivalence point of the weak base was determined and showed that the pKß value at 20°C in water of surfactant A 6 is pKß = 7.8.

The deprotonation of the profaned amine in water is described using the lower equilibrium, for which the acid constant Ks is used to describe the equilibrium analogously to the above statements.

(HNR ₃ ) ⁺ + H ₂ O - - NR ₃ + (H ₃ O) ⁺

The acid constant and base constant are related to each other via the equation K _w = Ks • KB or 14 = pKw = pKs + pKß (Kw is the ion product of water).

pH and pOH are related by Equation 14 = pH + pOH. If one now considers an aqueous solution of 10 g of surfactant A6 in one liter of water at 20° C. and a pH of 6.2 (pOH=7.8), the molar ratio of ethoxylated amine to profaned ethoxylated amine is 1:1. At pH 7.2 the molar ratio of ethoxylated amine to profaned ethoxylated amine is 10:1. At pH 5.2 the molar ratio of ethoxylated amine to profaned ethoxylated amine is 1:10.

Analogously to the above procedure, the pKß value for surfactant A 6 was determined in water at 50° C., in a 5% aqueous NaCl solution at 20° C. and in a 5% aqueous NaCl solution at 50° C. by titration . The values can be found in Table 5 below.

Table 5: Results of the titration experiments with surfactant A6

As can be seen from the examples in the table above, an increase in temperature from 20 to 50°C with the same salinity leads to an increase in the pKß value (from 7.8 to 8.0 in the case of water or from 6. 4 to 7.6 in the case of the 5% NaCl solution). A raise the salinity at the same temperature, on the other hand, leads to a reduction in the pKß value (from 7.8 to 6.4 in the case of 20°C or from 8.0 to 7.6 in the case of 50°C). If the salinity and temperature are increased, both effects more or less compensate each other and the pKß value remains relatively similar (comparison of example 1 and 4). Example 5 shows that a further increase in the salt content to 15% NaCl at 50° C. leads to a pKß value of 6.4. In summary, it can be said that the pKß value fluctuates around a value of 7 in the presence of sodium chloride and an optionally increased temperature.

Table 6 shows the development of cloud points of surfactant A6 in aqueous NaCl solutions as a function of pH or the ratio of ethoxylated amine to protonated ethoxylated amine.

Table 6: Cloud points of 1 g of surfactant A6 plus 100 g of an aqueous NaCl solution

As can be seen in Table 6, a claimed mixing ratio of ethoxylated amine to protonated ethoxylated amine results in significantly higher cloud points and thus significantly improved solubility. Comparative examples C6 and C7 show a cloud point of 58 and 65° C. in 15% sodium chloride solution. A significant jump in temperature of 18°C can already be found in Example 8, in which the claimed mixing ratio is present. With an equimolar mixing ratio, the solution of A 6 in 15% sodium chloride solution was clear even up to at least 97° C. (Example 9). The significantly improved solubility plays a major role in carbonate deposits, since these usually have very high salinities of >100,000 ppm total dissolved salt. On the other hand, if the surfactant solution is cloudy, it can Blockage of low-permeability areas, which significantly reduces oil production from these areas, since they can no longer be addressed with injection solution and thus chemicals.

Claims

29 claims 1. A method for extracting crude oil from underground crude oil deposits containing oil-wetted carbonate rocks, comprising at least one injection well and at least one production well, the method comprising at least the following steps: • Injecting an aqueous composition comprising at least one surfactant through at least one injection well into at least part of the oil reservoir, with the aqueous composition flowing from the at least one injection well in the direction of the at least one production well due to the injection pressure and thereby interacting with the oil-wetted surfaces the carbonate rocks mobilized petroleum, as well as • Extraction of crude oil through the at least one production well, characterized in that the deposit has a deposit temperature in the range of 10 ° C to 130 ° C, and the reservoir water has a salinity> 30000 ppm, and that the aqueous composition has a pH of 5 to 9, wherein at least one of the surfactants is an alkoxylated amine of the general formula R ¹ -N(R ² )R ³ (I), where the radicals R ¹ , R ² and R ³ have the following meanings: R ¹ is a hydrocarbon radical having 8 to 22 carbon atoms, R ² is a radical selected from the group consisting of H, hydrocarbon radicals having 8 to 22 carbon atoms, or a group -(CH2C(R ⁴ )HO) _X H and R ³ is a group -(CH ₂ C(R ⁴ )HO) _X H, where R ⁴ and x have the following meanings R ⁴ is independently H or an alkyl radical having 1 to 3 carbon atoms, x is independently a number from 1 to 80, and the pH of the aqueous composition is chosen so that the molar ratio of protonated alkoxylated amines R ¹ -N ⁺ H(R ² )R ³ to non-profanated alkoxylated amines R ¹ -N(R ² )R ³ is 1:10 to 10:1. 2. The method according to claim 1, characterized in that it is a hydrocarbon radical having 12 to 22 carbon atoms in R ¹ . 30 3. Process according to Claim 1 or 2, characterized in that R ² is a radical selected from the group consisting of H or -(CH 2 C(R ⁴ )HO) _x H. 4. The method according to any one of claims 1 to 3, characterized in that it is H in at least 50 mol % of the radicals R ⁴ . 5. The method according to any one of claims 1 to 3, characterized in that the radicals R ⁴ are H. 6. The method according to any one of claims 1 to 5, characterized in that x is a number from 1 to 20. 7. The method according to claim 1, characterized in that R ¹ is a group selected from oleyl, stearyl and lauryl groups, and R ² and R ³ are independently groups - (CH2C (R ⁴ ) HO) _X H, where each x is 2 to 10. 8. The method according to any one of claims 1 to 7, characterized in that the concentration of the alkoxylated amines of the formula (I) in the aqueous composition is 0.05% by weight to 2% by weight, based on the sum of all components of the aqueous composition amounts to. 9. The method according to any one of claims 1 to 8, characterized in that the pH of the aqueous composition is 6-8. 10. The method according to any one of claims 1 to 9, characterized in that the carbonate rocks of the petroleum deposit comprise at least 80% by weight of calcite, based on the amount of all components of the carbonate rock. 11 . Method according to Claim 10, characterized in that the proportion of quartz and clay minerals in the carbonate rock does not exceed 10% by weight in each case. 12. The method according to any one of claims 1 to 11, characterized in that the deposit temperature is 30 to 100°C. 13. The method according to any one of claims 1 to 12, characterized in that the reservoir water has a salinity> 70,000 ppm. 14. The method according to any one of claims 1 to 13, characterized in that the method additionally comprises at least one method step of water flooding. Aqueous composition for extracting petroleum from underground petroleum deposits containing oil-wetted carbonate rocks, comprising at least one surfactant, characterized in that the aqueous composition has a pH of 5 to 9, with at least one of the surfactants being at least one alkoxylated amine of general formula R ¹ -N(R ² )R ³ (I), where the radicals R ¹ , R ² and R ³ have the following meanings: R ¹ is a hydrocarbon radical having 8 to 22 carbon atoms, R ² is a radical selected from the group consisting of H, hydrocarbon radicals having 8 to 22 carbon atoms, or a group -(CH2C(R ⁴ )HO) _X H and R ³ is a group -(CH ₂ C(R ⁴ )HO) _X H, where R ⁴ and x have the following meanings R ⁴ is independently H or an alkyl radical having 1 to 3 carbon atoms, x is independently a number from 1 to 80, and the pH of the aqueous composition is chosen so that the molar ratio of protonated alkoxylated amines R ¹ -N ⁺ H(R ² )R ³ to non-profanated alkoxylated amines R ¹ -N(R ² )R ³ is 1:10 to 10:1.