WO2018086984A1

WO2018086984A1 - Process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs

Info

Publication number: WO2018086984A1
Application number: PCT/EP2017/078083
Authority: WO
Inventors: Jia Zhou; Shawn RIMASSA; Jeremy MANNING; Hisham Nasr-El-Din
Original assignee: Basf Corporation; Basf Se
Priority date: 2016-11-10
Filing date: 2017-11-02
Publication date: 2018-05-17

Abstract

Process of increasing the productivity of hydrocarbon bearing reservoirs Process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs comprising at least the step of introducing an aqueous fluid comprising at least one chelating agent into the formation, wherein the chelating agent is a mixture of at least two different compounds. Preferably, the process is an acidizing and/or fracturing process.

Description

Process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs

The present invention relates to a process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs comprising at least the step of introducing an aqueous fluid comprising at least one chelating agent into the formation, wherein the chelating agent is a mixture of at least two different compounds comprising carboxylate and/or carboxamide groups. Preferably, the process is an acidizing and/or fracturing process. The production of oil and/or gas from subterranean reservoirs typically decreases in course of time and may become uneconomical at a particular time. In other cases the production may be insufficient from the beginning. Consequently, it is necessary to take suitable measures for increasing the productivity. Processes for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs are basically known in the art. Such processes include matrix acidizing, which involves creating flow paths in the formation matrix by differential dissolution of small portions of the formation, or removing -by dissolution- near-wellbore formation damage, with an acid. "Wormholes" (conductive channels) are often generated through the matrix as a result and allow for improved con- ductivity within the formation. Acidic-based fluids are useful for this purpose due to their ability to dissolve both formation minerals and contaminants, such as drilling fluid filter cake on the wellbore or that has penetrated into the formation introduced into the wellbore/formation during drilling or remedial operations. Acids used in such acid fluids comprise but are not limited to HCI, HF, mixtures of HCI and HF or organic acids such as acetic acid or formic acid. HF is im- portant for treating silicate-containing formations such as sandstone formations due to its ability to dissolve silicates.

It is known in the art to use chelating agents such as, but not limited to methyl glycine diacetic acid (MGDA) or their respective salts in various oilfield applications, including but not limited to processes for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs. MGDA is biodegradable and therefore in particular suitable for that purpose.

US 5,783,524 discloses a process for complexing alkaline earth and heavy metal ions in petroleum and/or natural gas using MGDA or salts thereof, in particular in course of production or transportation petroleum and/or natural gas.

US 2008/0153718 A1 discloses a method of acidizing or fracture acidizing carbonatic formations using methane sulfonic acid and optionally further acids. The acid may comprise complexing agents, in particular MGDA.

WO 2012/080297 A1 discloses a method of iron control in course of treating subterranean formations, in particular in course of acidizing formations by adding GLDA and/or MGDA to the treatment fluid. US 2012/01 15759 A1 and US 2012/0097392 A1 discloses the addition of complexing agents to treatment fluids for subterranean formations.

US 2012/0202720 A1 , US 2014701 1 16710 A1 , US 2014/0124205 A1 , WO 2013/160332 A1 , WO 2013/189842 A1 , US 2013/0264060 A1 , and WO 2013/189731 A1 disclose the use of MGDA and/or salts thereof for acidizing and/or fracturing.

WO 2012/171857 A1 discloses the treatment of shale formations using chelating agents, including MGDA.

US 2014/0120276 A1 and WO 2013/120806 A1 disclose the reduction of corrosion of oilfield equipment which is in contact with treatment fluids by adding MGDA and/or GLDA to the treatment fluid. WO 2013/160334 A1 discloses a one-step process of removing filter cake using MGDA.

WO 2016/097026 A1 discloses the use of MGDA as additive in processes for recovering crude oil and/or gas from subterranean formations, in particular in processes of acidizing, wherein the MGDA is a mixture of L- and D-enantiomers of MGDA or salts thereof, said mixture containing an excess of the respective L-isomer, and the enantiomeric excess (ee) of the L-isomer is in the range of from 10 % to 75 %.

MGDA may be made by an alkylation of amino acids with formaldehyde and hydrocyanic acid or an alkali metal cyanide followed by saponification with alkali hydroxide. In order to secure com- plete saponification a stoichiometric amount of alkali hydroxide or an excess of alkali hydroxide is applied, see, e. g., US 7,671 ,234. In other methods, MGDA is made by addition of

NH(CH2CN)2 and hydrocyanic acid to acetaldehyde under formation of a trinitrile, followed by hydrolysis with sodium hydroxide solution, see, e.g., US 7,754,91 1 The product of the described manufacturing procedures is not MGDA in its acid form but the trisodium salt MGDANa3.

Aqueous solutions of MGDANa3 are highly alkaline. An aqueous solution of MGDANa3 having a concentration of about 1 % by wt. in distilled water at 23°C has a pH of about 1 1.5. Consequently, for achieving a targeted pH (e.g. pH 2) in acidic treatment fluids containing MGDANa3 significantly more acid is needed than for a fluid which is identical except that no MGDANa3 is present thereby impairing the economic efficiency of the process.

Another disadvantage of using MGDANa3 in acidic treatment fluids is its high sodium content. Consequently, also acidic treatment fluids comprising MGDANa3 have a significant concentration of Na⁺ ions. Acidic treatment fluids for treating silicate formations, such as sandstone for- mations, usually comprise HF or HF-generating compounds. HF is able to dissolve silicates and alumosilicates thereby yielding fluorosilicates. However, fluorosilicates may form precipitates with Na⁺ or K⁺ thereby yielding insoluble sodium- or potassium fluorosilicates (see for instance Malcolm A. Kelland, "Production Chemicals for the Oil and Gas industry , 2^nd Ed., pages 147 to 148, CRC Press, Boca Raton, 2014 or US 3,283,816). In order to overcome said problem, it has been suggested to pre-flush formations with diluted HCI or NH4CI solution before acidizing treatments. Also, acidizing fluids comprising HF should be free of Na⁺ ions or should at least have only a low contents of Na⁺ ions in order to avoid undesired precipitation of sodium fluorosili- cates. For that purpose, it is known in the art to use ammonium salts of complexing agents.

It is of course possible to convert MGDANa3 into MGDAH3 i.e. its acid form and/or the respective ammonium salt before its use in treatment fluids, however such an additional process step makes the product more expensive and impairs the economic efficiency of the process.

It was an objective of the present invention to provide an improved process increasing the production of hydrocarbons from hydrocarbon bearing reservoirs.

Our older application PCT/EP2016/059821 discloses a process of manufacturing chelating agents by saponification of the abovementioned reaction product of amino acids with formaldehyde and hydrocyanic acid or an alkali metal cyanide with alkali metal hydroxides, however using less the stoichiometric amount. The reaction yields a mixture of at least two different chelating amounts. PCT/EP2016/059821 also discloses the use of such chelating agents for removal of alkali earth metal cations and/or iron cations from water, for manufacturing a detergent com- position for hard surface cleaning or laundry cleaning, for manufacturing a detergent composition for automatic dishwashing or in oilfield applications.

Surprisingly, it has been found that using the mixture of chelating agents mentioned above in processes for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs avoids the drawbacks mentioned above.

Accordingly, a process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs has been found comprising introducing an aqueous fluid comprising at least one chelating agent into the formation, wherein the chelating agent is a mixture of compounds, compris- ing

(A) at least one compound according to general formula (I)

R¹-CH(COOX¹)-N(CH₂COOX¹)₂ (I)

(B) at least one compound selected from compounds according to general formula (Ilia) and (1Mb):

R -CH(COOX )-N(CH₂COOX )(CH₂CONH₂) (Ilia)

R -CH(COOX )-N(CH₂CONH₂)₂ (1Mb)

wherein

R¹ is selected from Ci-C4-alkyl, linear or branched, phenyl, benzyl, CH₂OH, and

CH₂CH₂COOX¹,

X¹ is (Na_xHi-x), x is in the range of from 0.6 to 1 , and

component (A) and component (B) being in a molar ratio (A)/(B) in the range of from 2.5 : 1 to 0.1 : 1. In a preferred embodiment of the invention, the aqueous fluid comprises at least an acid. Specific details of the invention are as follows: Mixture of chelating agents

The mixture of chelating agents for using in the process according to the present invention comprises

(A) at least one compound according to general formula (I)

R¹-CH(COOX¹)-N(CH₂COOX¹)₂ (I)

(B) at least one compound selected from compounds according to general formula (Ilia) and (1Mb) :

R -CH(COOX )-N(CH₂COOX )(CH₂CONH₂) (Ilia)

R -CH(COOX )-N(CH₂CONH₂)₂ (1Mb)

wherein

R¹ is selected from hydrogen, linear or branched Ci-C4-alkyl, for example methyl, ethyl, n- propyl, isopropyl, n-butyl, sec-butyl, isobutyl, and tert. -butyl, preferred are methyl and iso- butyl and even more preferred is methyl, phenyl, benzyl, CH₂OH, and CH₂CH₂COOX¹,

X¹ is (Na_xHi-_x), wherein

x is in the range of from 0.6 to 1 , and

component (A) and component (B) being in a molar ratio (A)/(B) in the range of from 2.5 : 1 to 0.1 : 1 , preferably from 2 : 1 to 0.25 : 1 and for example from 2 : 1 to 1 :1 .

In a preferred embodiment of the present invention, R¹ is methyl. Component (A) may be a racemic mixture or a pure enantiomer, for example the L-enantiomer, or a mixture of L- and D-enantiomers in which one of the enantiomers prevails, preferably the L- enantiomer prevails. In a preferred embodiment of the present invention component (A) is a mixture of enantiomers containing predominantly the respective L-enantiomer with an enantiomeric excess (ee) in the range of from 10 to 98 %.

In an even more preferred embodiment of the present invention component (A) is a mixture of enantiomers containing predominantly the respective L-enantiomer with an enantiomeric excess (ee) in the range of from 10 to 98 %, and R¹ is methyl. In one embodiment of the present invention, the enantiomeric excess of the respective L-isomer of component (A) is in the range of from 10 to 98%, preferably in the range of from 12.5 to 85 % and even more preferred up to 75%. In other embodiments, all components of inventive mixtures constitute the respective racemic mixtures.

In embodiments where component (A) comprises two or more compounds, the ee refers to the enantiomeric excess of all L-isomers present in component (A) compared to all D-isomers in component (A). For example, in cases wherein a mixture of the di- and trisodium salt of MGDA is present, the ee refers to the sum of the disodium salt and trisodium salt of L-MGDA with re- spect to the sum of the disodium salt and the trisodium salt of D-MGDA.

The enantiomeric excess can be determined by measuring the polarization (polarimetry) or preferably by chromatography, for example by HPLC with a chiral column, for example with one or more cyclodextrins as immobilized phase. Preferred is determination of the ee by HPLC with an immobilized optically active ammonium salt such as D-penicillamine.

Component (B) is a mono- or diamide or a mixture therefrom. Component (B) comprises a mixture of compounds according to general formula (Ilia) and (1Mb). In embodiments wherein some compound (lib) as defined below has been used as starting material, the inventive mixture may contain some compound that has the general formula

R¹-CH(CONH₂)-N(CH₂COOX¹)₂ (lllc) Component (B) may be present as racemic mixture or in the form of a mixture of enantiomers in which the L-enantiomer predominates, for example with an enantiomeric excess in the range of from 5 to 95%, more preferably 15 to 90%. Compound according to general formula (lllc) - if applicable - is usually present as racemic mixture. In one embodiment of the invention the mixture of chelating agents comprises in total 1 ppm to 1.5% by weight of inorganic non-basic salt, based on the respective mixture.

In one embodiment of the present invention, the mixtures may contain in the range of from 0.1 to 10 % by weight of one or more optically inactive impurities, at least one of the impurities be- ing at least one of the impurities being selected from iminodiacetic acid, racemic N-carboxyme- thyl-alanine, formic acid, glycolic acid, propionic acid, acetic acid and their respective alkali metal or mono-, di- or triammonium salts.

In one aspect of the present invention, inventive mixtures may contain less than 0.2 % by weight of nitrilotriacetic acid (NTA), preferably 0.01 to 0.1 % by weight.

In one embodiment of the present invention, mixtures in which R¹ is methyl may additionally contain 0.1 to 3% by weight with respect to the sum of (A) and (B), of at least one diacetic acid derivative of glutamic acid, of aspartate, or of valine, or 0.1 to 3% by weight of the tetraacetic acid derivative of lysine, or 0.1 to 3% by weight of the mono-acetate of proline.

In one embodiment of the present invention, mixtures that contain an optically active compound according to general formula (I) may contain one or more optically active impurities. Examples of optically active impurities are L-carboxymethylalanine and its respective mono- or dialkali metal salts, and optically active mono- or diamides that result from an incomplete saponification of the dinitriles, see below. A further example of an optically active impurity is the respective mono-carboxymethyl derivative of (B). Preferably, the amount of optically active impurities is in the range of from 0.01 to 2 % by weight, referring to the mixture solution. Even more preferred, the amount of optically active impurities is in the range of from 0.1 to 0.2 % by weight.

In one aspect of the present invention, the mixtures may contain minor amounts of cations other than alkali metal. It is thus possible that minor amounts, such as 0.01 to 5 mol-% of total in- ventive mixture, based on anion, bear ammonium cations or alkali earth metal cations such as Mg²⁺ or Ca²⁺, or transition metal ions such as Fe²⁺ or Fe³⁺ cations.

The mixtures display a very good solubility, especially in water and aqueous alkali metal hydroxide solutions. Such very good solubility can be seen, e. g., in a temperature range of from zero °C to 40°C, in particular at room temperature and/or at zero and/or +10°C.

The mixtures also display a very good chelating power. The chelating power of inventive mixtures may be determined by titration with aqueous solutions of Fe(+lll) salt solution, for example of aqueous solutions of FeC -aq.

Process of manufacturing the mixture of chelating agents

The mixture to be used in the process for treating hydrocarbon bearing reservoirs according to the present invention may be manufactured by a process comprising at least steps (a), (b), and (c).

Step (a)

Step (a) refers to providing a solid or a slurry or a solution of a compound according to general formula (I I a)

R¹-CH(COOX²)-N(CH₂CN)₂ (Ma)

including mixtures from each at least one compound according to formula (I la) and one compound according to formula (lib)

R -CH(CN)-N(CH₂CN)₂ (Mb), preferably a compound of general formula (lla). Providing a solid means in the context of step (a) of the process that compound according to general formula (II a) is provided as a solid mass. Said slurry or solution is preferably an aqueous slurry or an aqueous solution, preferably an aqueous solution. Such slurry or solution, respectively, may have a total solids content in the range of from 5 to 60% by weight, preferably 30 to 50 % by weight. The term "aqueous" refers to a continuous phase or solvent comprising in the range of from 50 to 100 vol-% of water, preferably 70 to 100 vol-% of water, referring to the total continuous phase or solvent, respectively. Examples of suitable solvents other than water are alcohols such as methanol, ethanol and iso- propanol, furthermore diols such as ethylene glycol and triols such as glycerol.

In formulae (lla) and (lib), the variables are defined as follows. R¹ is defined as above. X² is (MyHi-y), M being selected from alkali metal, for example lithium, sodium, potassium and mixtures of at least two of the forgoing, preferred are sodium and potassium and mixtures from sodium and potassium and even more preferred is sodium, y is in the range of from zero to 1 , preferably 0.7 to 0.9,

Compound according to general formula (lla) may be selected from the respective L- and D-en- antiomers and combinations thereof, for example the racemic mixture and from mixtures in which the L-enantiomer prevails, for example with 50 to 99.5% L-enantiomer. Preferred are the racemic mixtures and mixtures that contain 95 to 99.5% L-enantiomer.

In a preferred embodiment of the present invention, R¹ in general formula (lla) is methyl, and compound (lla) is predominantly the L-enantiomer, the ratio of L to D being in the range of from 95:1 to 100:1. Compound according to general formula (lib) is preferably the racemic mixture. Step (b)

Step (b) of the inventive process refers to contacting said slurry or solution with an aqueous so- lution of alkali metal hydroxide, wherein the molar ratio of alkali metal ions to nitrile groups is in the range of from 0.6:1 to 0.95:1 , preferably 0.7 to 0.9.

In one embodiment of the present invention alkali metal hydroxide is selected from hydroxides of lithium, sodium, potassium and combinations of least two of the foregoing. Preferred are sodium hydroxide, potassium hydroxide, mixtures of sodium hydroxide and potassium hydroxide and even more preferred is sodium hydroxide.

Aqueous solutions of alkali metal hydroxide may have a concentration in the range of from 1 % by weight to 65% by weight, preferably from 10 to 55% by weight. Aqueous solutions of alkali metal hydroxide may contain one or more impurities such as, but not limited to alkali metal carbonate. For example, aqueous solutions of sodium hydroxide may contain 0.01 to 1 % sodium carbonate.

Said contacting may be performed by charging a reaction vessel with an aqueous solution of alkali metal hydroxide and then adding slurry or solution of compound according to general formula (II a), respectively, in one or more portions. In an alternative embodiment, said contacting may be performed by charging a reaction vessel with a portion of aqueous solution of alkali metal hydroxide and then adding slurry or solution of compound according to general formula (II a), respectively, in one or more portions, and the remaining solution of alkali metal hydroxide, consecutively or preferably in parallel. In an alternative embodiment, said contacting may be performed by continuously combining solution or slurry of compound according to general formula (II a) and aqueous solution of alkali metal hydroxide.

In embodiments in which aqueous solutions of alkali metal hydroxide is added in two portions in step (b), the first portion may contain 10 to 50 mole-% of the required alkali metal hydroxide and the second portion may contain the remaining 50 to 90 mole-%. In embodiments in which compound according to general formula (II a) is added in two portions in step (b), the first portion may contain 10 to 50 mole-% of the required compound according to general formula (II a) and the second portion may contain the remaining 50 to 90 mole-%.

Step (b) of the process may be performed at a temperature in the range of from zero to 80°C, preferably 5 to 75°C and sometimes up to 50°C and even more preferably from 25 to 40°C. A very particular temperature range is from 35 to 70°C. In embodiments wherein aqueous solution of alkali metal hydroxide or slurry or solution of compound according to general formula (II a) are combined in two or more portions said portions may be combined at the same or at different temperatures.

Step (b) of the inventive process may have a duration of 30 minutes to 24 hours, preferably 1 to 12 hours, even more preferably 2 to 6 hours.

Step (b) of the process may be performed under a pressure in the range of from 0.5 to 10 bar, preferably normal pressure.

In one embodiment of the present invention, the reaction vessel in which step (b) is performed contains at least one part made from stainless steel or stainless steel that is exposed to the mixture formed in step (b). Step (c)

Step (c) of the process refers to reacting said compound according to general formula (lla) with said alkali metal hydroxide. Step (c) of the process may be performed at a temperature in the range of from 30 to 200°C, preferably 70 to 190°C. Step (c) of the process may be performed at one temperature. In preferred embodiments, however, step (c) is performed in the form of two or more sub-steps (c1 ), (c2) and optionally more, of which the sub-steps are performed at different temperatures. Preferably, each sub-step may be performed at a temperature that is higher than the temperature at which the previous sub- step was performed. In the context of the present invention, sub-steps differ in temperature by at least 10°C, said temperature referring to the average temperature. In a preferred embodiment of the present invention, step (c) comprises at least two sub-steps (c1 ) and (c2), sub-step (c2) being performed at a temperature at least 20°C higher than sub-step (c1 ), preferably at least 25°C. In a preferred embodiment, step (c) comprises at least two sub-steps (c1 ) and (c2), sub- step (c2) being performed at a temperature from 20°C to 150°C higher than sub-step (c1 ).

Preferably, a sub-step is performed over a period of at least 30 minutes. Even more preferably, a sub-step is performed over a period of 30 minutes to 5 hours, preferably up to 2 hours.

In one embodiment, step (c) has an overall duration in the range of from 30 minutes up to 24 hours, preferably 2 to 16 hours.

In one embodiment, at least one sub-step of step (c) is carried out at a temperature in the range of from 50 to 90°C, preferably 70 to 80°C. In one embodiment, at least one sub-step of step (c) is carried out at a temperature in the range of from 90 to 200°C, preferably 150 to 190°C.

In one embodiment, at least one sub-step of step (c) is carried out at a temperature in the range of from 40 to 60°C, another sub-step of step (c) is carried out at a temperature in the range of from 50 to 80°C, and at least another sub-step of step (c) is carried out at a temperature in the range of from 100 to 200°C.

In one embodiment, ammonia formed during the reaction is removed, continuously or discontin- uously, for example by stripping or by distilling it off, for example at a temperature of at least 90°C, preferably 90 to 105°C.

In one embodiment, water is added during the course of step (c), for example in order to compensate for the loss of water due to ammonia removal. In one embodiment, step (c) is carried out at normal pressure or at a pressure above 1 bar, for example 1.1 to 40 bar, preferably 5 to 25 bar. In embodiments with two or more sub-steps of step (c), subsequent sub-steps are preferably carried out at a pressure at least as high as the previous sub-step. Step (c) may be carried out in a stirred tank reactor, or in a plug flow reactor, or in a cascade of at least two stirred tank reactors, for example 2 to 6 stirred tank reactors, or in a combination of a cascade of 2 to 6 stirred tank reactors with a plug flow reactor.

Especially in embodiments wherein the final sub-step of step (c) is carried out in a plug flow reactor, said final sub-step may be carried out at elevated pressure such as 1.5 to 40 bar, preferably at least 20 bar. The elevated pressure may be accomplished with the help of a pump or by autogenic pressure elevation.

In one embodiment, the reaction vessel in which step (c) is performed contains at least one part made from stainless steel that is exposed to the reaction mixture according to step (c).

In one embodiment, at least one reaction vessel in which a sub-step of step (c) is performed contains at least one part made from stainless steel that is exposed to the reaction mixture according to step (c).

During step (c), a partial or complete racemization may take place if compound according to general formula (II a) is optically active and if step (c) or at least one sub-step of step (c) is car- ried at a sufficiently high temperature. Without wishing to be bound by any theory, it is likely that racemization takes place on the stage of the above L-monoamide or L-diamide or of the L-iso- mer of compound according to formula (I).

Further steps

In one embodiment, the process for manufacturing the mixture of chelating agents to be used in the process according the present invention may comprise additional steps other than steps (a), (b) and (c) disclosed above. Such additional steps may be, for example, one or more decolonization steps, for example treatment with activated carbon or with peroxide such as H2O2 or by irradiation with UV-light in the absence or presence of H2O2.

A further step other than step (a), (b) or (c) that may be carried out after step (c) is stripping with air or nitrogen or steam in order to remove ammonia. Said stripping can be carried out at temperatures in the range of from 90 to 1 10°C. By nitrogen or air stripping, water can be removed from the solution so obtained. Stripping is preferably carried out at a pressure below normal pressure, such as 650 to 950 mbar.

In embodiments wherein an solution of the mixture of chelating agents is desired, the solution obtained from step (c) is just cooled down and, optionally, concentrated by partially removing the water. If dry samples of inventive mixtures are required, the water can be removed by spray drying or spray granulation. The process may be carried out as a batch process, or as a semi-continuous or continuous process.

By performing the process, a chelating agent of general formula (I) is obtained. Said chelating agent is not obtained in pure form but it contains certain amounts of at least one mono- or dia- mide according to general formula (Ilia) and (1Mb):

R¹-CH(COOX¹)-N(CH₂COOX¹)(CH₂CONH₂) (Ilia) R -CH(COOX )-N(CH₂CONH₂)₂ (1Mb) wherein the variables R¹ and X¹ are as defined above. The chelating power of mixtures obtained is excellent. While performing the manufacturing process, stainless steel reaction vessels and especially stainless steel parts of reaction vessels exposed to the reaction mixture suffer less wear-off or corrosion than in process in which an excess of alkali metal hydroxide is employed.

Preferably, such complexing agent according to general formula (I) contains only very low amounts of inorganic basic salts, for example in total 1 ppm to 1 .5% by weight of inorganic non- basic salt, based on the respective mixture of compounds according to general formulae (I) and (III a) and (III b). In the context of the present invention, basic inorganic salts may also be referred to as alkaline inorganic salts.

The chelating power, hereinafter also referred to as complexing power, of such mixtures may be determined by titration with aqueous solutions of Fe(+lll) salt solution, for example of aqueous solutions of FeC -aq. Values of complexing power with respect to alkali earth metals are excellent as well.

Process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs The process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs according to the present invention comprises at least a step of introducing an aqueous fluid comprising at least one chelating agent into the formation, wherein the chelating agent is a mixture of chelating agents as described above. Hydrocarbons may be crude oil and/or gas. In course of introducing the aqueous fluid into the hydrocarbon bearing reservoirs the productivity of hydrocarbon production is enhanced. The present invention is not limited to a specific mode of operation of the aqueous fluid but is intended to cover any mode of operation by which the hydrocarbon production is enhanced. Specifically, increasing the productivity may be achieved by at least one of the following measures:

· increasing the permeability of the reservoir by at least partial dissolution of the reservoir,

• increasing the permeability of the reservoir by creating fractures in the reservoir,

• removing small particles from the reservoir,

• removing inorganic scale and • removing filter cake during drilling and completion operations.

The hydrocarbon bearing reservoirs may be any kind of reservoirs. In an embodiment of the invention the reservoir is selected from reservoirs comprising carbonates, sandstone, or shale. Of course a reservoir may comprise mixtures of at least two of the materials. The temperature of the reservoir is not specifically limited. It may be from 5°C to 250°C, in particular from 25°C to 200°C. Examples of preferred ranges comprise 50°C to 200°C, 100°C to 200°C, or 120°C to 200°C. Aqueous fluids

The aqueous fluids to be used in the process according to the present invention comprise at least water as solvent. The water may be selected from fresh water, sea water, formation water or mixtures thereof.

The aqueous base fluid may comprise dissolved salts. Examples of salts comprise halogenides, in particular chlorides, sulfates, borates of mono- or divalent cations such as Li⁺, Na⁺, K⁺, Mg²⁺, Ca²⁺, Sr²⁺, or Ba²⁺. In an embodiment, the salt may be KCI and/or ammonium chloride.

The salinity of the water, in particular the concentration of KCI and/or ammonium chloride may be from 0.1 % by weight to 10 % by weight relating to the aqueous base fluid, in particular from 0.5 % to 8 % by weight, preferably from 1 % to 8 % by weight and by the way of example 1 to 7 % by weight.

Besides water, the aqueous fluid may comprise organic solvents miscible with water. Examples of such organic solvents comprise alcohols such as ethanol, n-propanol, i-propanol or butyl di- glycol. If organic solvents are present their amount should not exceed 50 % by weight with respect to all solvents present in the aqueous base fluid. In a preferred embodiment of the invention the aqueous base fluid comprises at least 70 % by weight of water with respect to the solvents present in the aqueous base fluid, more preferably at least 90 % by weight. In a further preferred embodiment of the invention only water is used as solvent in the aqueous base fluid. Besides water and optionally organic solvents miscible with water

The aqueous fluids to be used in the process according to the present invention furthermore comprise at least a chelating agent which is a mixture of compounds comprising

(A) at least one compound according to general formula (I)

R -CH(COOX )-N(CH₂COOX )₂ (I)

R¹-CH(COOX¹)-N(CH₂COOX¹)(CH₂CONH₂) (Ilia)

R¹-CH(COOX¹)-N(CH₂CONH₂)₂ (1 M b) wherein

R¹ is selected from Ci-C4-alkyl, linear or branched, phenyl, benzyl, CH2OH, and

X¹ is (Na_xHi-x),

x is in the range of from 0.6 to 1 , and

component (A) and component (B) being in a molar ratio (A)/(B) in the range of from 2.5 : 1 to 0.1 : 1 .

Details of such mixtures of chelating agents, including preferred mixtures have been described above and we refer to such description above.

The concentration of the mixtures of chelating agents may range from 0.01 % by weight to 30 % by weight relating to the sum of all components of such aqueous fluid. In one embodiment, only small amounts of the mixture of chelating agents are used, such as, but not limited to 0.05 % to 2 % by weight, preferably 0.1 to 1 % by weight of such mixtures. In other embodiments higher amounts may be used such as, but not limited to 5 % by weight to 30 % by weight.

Further components of the aqueous fluid The aqueous fluids for use in the process according to the present invention may comprise further components. In particular, such further components may be at least one component selected from the group of acids, bases, corrosion inhibitors, viscosifiers, crosslinkers, proppants or other particulates, retarders, flowback aids, breakers, surfactants, wetting agents, diverting agents, fluid loss additives, friction reducers, scale inhibitors, further complexing agents, or sta- bilizers such as oxygen scavengers, free radical scavengers, sulfide scavengers or bacteri- cides/biocides.

Acids In apreferred embodiment of the invention, the aqueous fluid comprises additionally at least one acid.

Acids may be generally to adjust the pH value of the fluid. In particular, acids may be used to dissolve the reservoir at least partly and/or to dissolve particulate material in the reservoir thereby increasing the permeability of the reservoir. Furthermore, acids may be used to dissolve scales, for instance scales on the wellbore walls and/or wellbore equipment.

Examples of suitable acids comprise HCI, HF, organic acids, such as, for example, formic acid, acetic acid, p-toluenesulfonic acid, amido sulfonic acid or alkanesulfonic acids. Preferred al- kanesulfonic acids have the general formula R²-SOsH, where R² is a straight-chain, branched or cyclic alkyl radical. For example, R² is selected from straight-chain or branched Ci-C6-alkyl, preferably Ci-C4-alkyl. Most preferably, R² is methyl, that means the alkane sulfonic acid is methanesulfonic acid.

Methanesulfonic acid (abbreviated to MSA) is particularly preferably used. Methanesulfonic acid is a very strong acid (pK_a: -2) but has a significantly lower vapor pressure than HCI or formic acid. It is therefore very particularly suitable also for use at relatively high temperatures. Methanesulfonic acid can therefore advantageously be used for the treatment of subterranean formations having a temperature of at least 60 ^°C, in particular from 60 to 250 °C. In special embodiments, a mixture of two or more acids may be used. Examples of suitable acid mixtures may be selected from mixtures of methanesulfonic acid and HF, methanesulfonic acid and HCI, formic acid and acetic acid, acetic acid and HCI, formic acid and HCI, and HF and HCI. Mixtures of HF and HCI are also known as mud acid any may be used for example in a weight ratio of 9 : 1 or 12 : 3.

Suitable acids may be selected in particular according to the nature of the formation to be acidized. For carbonate reservoirs a wide variety of acids may be used, for instance HCI and/or methane sulfonic acid. If the formation comprises silicates such as sandstone or alumosilicates and it is desired to also dissolve such silicates HF or acid mixtures comprising HF should be used.

The concentration of acid in the aqueous solutions may be chosen in wide ranges.

By way of example, the concentration of methanesulfonic acid may be from 1 % to 50 % by weight with respect to all components of the aqueous fluid, preferably from 5 % to 50 % by weight, more preferably 10 % to 30 % by weight, and even more preferably 15 % to 25 % by weight.

The concentration of HCI used may be from 2 % to 28 % by weight, preferably 2 to 20 % by weight and even more preferably 5 % to 15 % by weight.

In mixtures of formic acid and acetic acid the concentration of formic acid should be from 9 to 1 1 % by weight.

The pH value of the aqueous fluid comprising at least one acid should be less than or equal 7, preferably less than or equal to 6 and more preferably less than or equal to 5.5. Preferably, the pH-value is from 0 to 5.5, more preferably from 0 to 5. By the way of example the pH may be from 1 to 3 or from 1 .5 to 2.5.

Corrosion Inhibitors

In an embodiment of the invention, the aqueous fluid additionally comprises at least one corrosion inhibitor. Corrosion inhibitors may be used to protect metallic surfaces from corrosion, in particular steel surfaces which come into contact with the aqueous fluid, in particular acidic aqueous fluid.

Examples of suitable corrosion inhibitors comprise alkyne derivatives such as propargyl alcohol, ethoxylated propargyl alcohol, ethyleneglycole propargylether, 1 ,4-butynediol or alkoxylated 1 ,4- butynediol. Further examples comprise 2-mercaptoethanol, coco dimethylamine-N-oxide, quaternary ammonium compounds such as coco trimethylammonium sulfate, or alkylpolygycosides. Suitable corrosion inhibitors are commercially available, e.g. under the trademark Basocorr^®. Of course mixtures of two or more different corrosion inhibitors may be used. By way of example, the concentration of the corrosion inhibitors may be from 0.1 % to 2 % by weight with respect to all components of the aqueous fluid.

In a preferred embodiment, the corrosion inhibitor comprises ethyleneglycole propargylether. In a preferred embodiment of the invention, the aqueous fluid comprises at least an acid and a corrosion inhibitor, preferably ethyleneglycole propargylether.

Retard ers In an embodiment of the invention, the aqueous fluid additionally comprises at least one retarded

Retarders may be used to delay the reaction of acids upon reservoirs and/or particulates in the reservoir, If very reactive acids such as HCI are used for acidizing, such acid quickly reacts with the formation once it gets into contact with the formation and therefore the acid may quickly become spent in the near wellbore regions of the respective subterranean formation. Retarding surfactants slow down the reaction between the acid and the formation thereby allowing the acid to penetrate deeper into the formation. In one embodiment so-called "wormholes" may be formed. Examples of suitable retarding surfactants comprise sulfonates of the general formula RSO3M, wherein R is a Cs to C25 hydrocarbon moiety and M is an alkali metal ion or an ammonium ion. Further examples of suitable retarders comprise amines or amine derivatives such as those disclosed in WO 2015/154977 A1.

Diverting agents

In an embodiment of the invention, the aqueous fluid comprises additionally at least one diverting agent.

Treatment fluids injected into a subterranean formation tend to follow the flow path of least flow resistance. Consequently, the least permeable areas of the formation may not or not adequately be treated. Diverting agents may be used to insure a uniform injection over the area to be treated. They function by creating a temporary blocking effect that is safely cleaned up following the treatment, enabling enhanced productivity throughout the treated interval. Examples of diverting agents comprise degradable particulates such as sand, quartz, salts, polymeric particles, and degradable particulates such as polylactic acid or polylactide particulates in combination with/without fibers, benzoic acid, viscoelastic surfactants, or in-situ gelled fluids.

Viscosifiers

In an embodiment of the invention, the aqueous fluid comprises additionally comprises at least one viscosifier.

Viscosifiers may be necessary for fracturing processes to properly transport proppants. Also acids may be thickened in order to ensure a more uniform treatment of the subterranean formation. Viscosifiers may be water-soluble, thickening polymers, low molecular components such as vis- cosifying surfactants or combinations thereof.

Examples of thickening polymers comprise biopolymers or modified biopolymers such as xan- thans, Scleroglucanes, galactomannan gums, or cellulose derivatives. Examples of galactoman- nan gums include gum arabic, gum ghatti, gum karaya, tamarind gum, tragacanth gum, guar gum, or locust bean gum. Examples of derivatives include hydroxyethylguar, hydroxypropyl- guar, carboxymethylguar, carboxymethyl hydroxyethylguar and carboxymethyl hydroxypropyl- guar. Examples of suitable cellulose derivatives include hydroxyethyl cellulose, carboxyethyl- cellulose, carboxymethylcellulose, or carboxymethylhydroxyethylcellulose.

Further examples of thickening polymers comprise synthetic polymers, in particular poly acryla- mides or copolymers comprising acrylamide units and one or more comonomers.

In one embodiment, the thickening polymer comprises acryl amide units and at least one mo- noethylenically unsaturated monomer comprising acids groups or salts thereof, for example monomers comprising -COOH groups, such as acrylic acid or methacrylic acid, crotonic acid, itatonic acid, maleic acid or fumaric acid, monomers comprising sulfonic acid groups, such as vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid (AMPS), 2- methacrylamido-2-methylpropanesulfonic acid, 2-acrylamidobutanesulfonic acid, 3-acrylamido- 3-methylbutanesulfonic acid or 2-acrylamido-2,4,4-trimethylpentanesulfonic acid, or monomers comprising phosphonic acid groups, such as vinylphosphonic acid, allylphosphonic acid, N- (meth)acrylamidoalkylphosphonic acids or (meth)acryloyloxyalkylphosphonic acids.

In another embodiment, the thickening polymer comprises acryl amide units and at least one monoethylenically unsaturated monomer comprising cationic groups. Examples of such cationic monomers comprise quaternized N-(co-aminoalkyl) (meth)acrylamides or co-aminoalkyl (meth)acrylic esters such as salts of 3-trimethylammonium propylacrylamides or 2-trimethylammonium ethyl (meth)acrylates, for example the corresponding chlorides, such as 3-trimethylammonium propylacrylamide chloride and 2-trimethylammonium ethyl methacrylate chloride. Besides acryl amide and optionally anionic and/or cationic monomers the thickening polymers may also comprise associating monomers such as the associating monomers disclosed in WO 2010/133527 A1 and WO 2015/086468 A1.

Examples of low molecular viscosifiers comprise viscosifying surfactants such as the visco-elas- tic surfactants disclosed in US 5,964,295 or combinations of viscosifying surfactants and polymers such as disclosed in WO 201 1/012164 A1.

In one preferred embodiment of the invention, the viscosifier is guar gum and/or a guar gum derivative.

In another preferred embodiment of the invention, the viscosifier is a copolymer comprising at least acryl amide units and one monoethylenically unsaturated monomer comprising cationic groups. Crosslinkers

In an embodiment of the invention, the aqueous fluid additionally comprises at least one cross- linker. Thickening polymers may also be used together with suitable crosslinkers in order to enhance the thickening effect. Suitable crosslinkers may be selected by the skilled artisan according to the polymer to be crosslinked. Examples of crosslinkers comprise inorganic compounds such as borates, metal compounds such as Al(lll)-, Ti (IV)- or Zr(IV)-compounds or organic crosslinkers comprising at least two groups capable of reacting with polymer chains.

In certain embodiments crosslinkers may be so-called "delayed crosslinkers". Delayed crosslinkers do not immediately crosslink polymers upon mixing but crosslinking starts after some time or when certain conditions are fulfilled, i.e. when the temperature exceeds a certain limit. Delayed crosslinkers may be obtained by coating crosslinkers.

Proppants

In an embodiment of the invention, the aqueous fluid additionally comprises at least one prop- pant.

Proppants may be used if the process of treating the reservoir is a process of fracturing.

Proppants are small hard particles which prevent the fractures from closing after formation of the fractures and subsequent removal of pressure. Suitable proppants are known to the skilled artisan. Examples of proppants include naturally-occurring sand grains, resin-coated sand, sintered bauxite, ceramic materials, glass materials, polymer materials, ultra lightweight polymer beads polytetrafluoroethylene materials, nut shell pieces, cured resinous particulates comprising nut shell pieces, seed shell pieces, cured resinous particulates comprising seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates, and any combinations thereof.

The amount of proppants in the aqueous fluid may be from 50 kg/m³ to 3500 kg/m³ of the fracturing fluid, in particular from 50 kg/m³ to 1200 kg/m³ of the fracturing fluid.

Breakers

In an embodiment of the invention, the aqueous fluid comprises additionally at least one breaker.

Aqueous fluids for use in the process according to the present invention may comprise breakers capable of reducing the viscosity of the fluid. Breakers may be added to viscosified fluids, such as fluids comprising polymers as mentioned above in order to reduce their viscosity after the treatment process. Reducing the viscosity typically eases removing the treatment fluid from the formation.

Examples of such suitable breakers include oxidizing agents such as sodium chlorites, sodium bromate, hypochlorites, perborate, persulfates, and peroxides, including organic peroxides. Other suitable breakers include peroxide breakers, triethanol amine, or enzymes. The breakers may be encapsulated so that breaking only occurs with some delay.

In one embodiment of the invention the breaker comprises at least one enzyme. Enzymes are in particular suitable for degrading polysaccharides and/or polysaccharide derivatives. The enzyme can be any enzyme capable of degrading polysaccharides and/or polysaccharide derivatives. Non-limiting examples of the enzyme include cellulases, hemicellulases, pectinases, xan- thanases, mannanases, galactosidases, glucanases, amylases, amyloglucosidases, invertases, maltases, endoglucanase, cellobiohydrolase, glucosidase, xylanase, xylosidase, arabino- furanosidase, oligomerase, and the like, and any mixtures thereof. The galactosidases can be a-galactosidases, β-galactosidases, or any combination thereof. The glucosidases can be a- glucosidases, β-glucosidases, or any combination thereof. The amylases can be a-amylases, β- amylases, γ-amylases, or any combination thereof. In some embodiments, the enzyme is a thermostable or thermotolerant enzyme.

In a preferred embodiment the enzyme is a cellulase. In another preferred embodiment, the breaker is an encapsulated enzyme, in particular an encapsulated cellulase.

Flowback aids In an embodiment of the invention, the aqueous fluid comprises additionally at least one flow- back aid.

Flowback aids facilitate the removal of injected aqueous fluid from the subterranean formation. They may be surface active components or co-solvents added to aqueous fluids to reduce capillary pressure. Examples of flowback aids comprise alkyl or alkenyl polyglucosides, carboxylated alkyl or alkenyl polyglucosides, alkoxylated branched alcohols or esters of an alkoxylated saccharide. Such flowback aids are described in WO 2014/108350 A1. Surfactants

In an embodiment of the invention, the aqueous fluid comprises additionally at least one surfactant.

Suitable surfactants may be selected from the group of anionic surfactants, cationic surfactants, non-ionic surfactants, amphoteric surfactants or zwitterionic surfactants. Mixtures of two or more surfactants may be selected as well. Examples of suitable surfactants comprise alk(en)ylpoly- glucosides, alkylpolyalkoxylates, alkylphenolalkoxylat.es, sorbitan esters which may be alkoxylated, alkanolamides, amine oxides, alkoxylated fatty acids, alkoxylated fatty amines alkoxylated alkyl amines or quaternary ammonium compounds.

Surfactants may serve several functions in the aqueous fluids to be used. In one embodiment, foaming surfactants may be used. Formulations for comprising such foaming surfactants may be foamed before or during injection into the subterranean formation. Foams of aqueous fluids have a higher viscosity than liquid formulations and therefore flow into subterranean formations more uniformly. Examples of suitable foaming surfactants comprise alkyl sulfates such as sodium lauryl sulfate, betaines such as alkylamidobetaines, amine oxides, or quaternary ammonium compounds such as trimethyl tallow ammonium salts.

Wetting agents

In an embodiment of the invention, the aqueous fluid comprises additionally at least one wetting agent.

Wetting agents may be used to modify the wettability properties of the reservoir surfaces.

Examples of wetting agents include crude tall oil, oxidized crude tall oil, surfactants, organic phosphate esters, modified imidazolines and amidoamines, alkyl aromatic sulfates and sulfonates and combinations or derivatives of these.

Fluid loss additives

In an embodiment of the invention, the aqueous fluid comprises additionally at least one fluid loss additive. Fluid loss means the leakage of the liquid phase of treatment fluids containing solid particles into the reservoir. The resulting buildup of solid material (the so-called "filter cake") may be undesirable, as may the penetration of filtrate through the formation. Fluid-loss additives are used to control the process and avoid potential reservoir damage.

Examples of fluid loss additives include starches, silica flour, benzoic acid, soaps, resin particulates, relative permeability modifiers, degradable gel particulates, diesel or other hydrocarbons dispersed in fluid, and other immiscible fluids. Further examples include degradable materials such as polysaccharides, polyesters, polylactides, or polyethyleneoxides.

Friction reducers

In an embodiment of the invention, the aqueous fluid comprises additionally at least one friction reducer.

Friction reducers may be used to alter fluid rheological properties to reduce friction created within the aqueous fluid as it flows through small-diameter tubulars or similar restrictions. Examples of friction reducers comprise high molecular-weight polymers.

Scale inhibitors

In an embodiment of the invention, the aqueous fluid comprises additionally at least one scale inhibitor.

Examples of scale inhibitors include water-soluble organic molecules, polymers, copolymers or graft polymers comprising carboxylic acid groups, sulfonic acid groups, or phosphonic acid groups. Examples of such compounds include aliphatic phosphonic acids such as diethylene triamine penta (methylene phosphonate) and polymeric species such as polyvinyl sulfonate. The scale inhibitor may be in the form of the free acid but is preferably in the form salts.

Stabilizers

Stabilizers may be used in the aqueous fluid in order to protect chemicals and polymers used in the fluid from degradation by heat, oxygen, sulfides or microorganisms. In an embodiment of the invention, the aqueous fluid comprises at least one stabilizer selected from the group of oxygen scavengers, free radical scavengers, sulfide scavengers or bacteri- cides/biocides. Examples of suitable oxygen scavengers include inorganic or organic sulfites such as sodium sulfite, sodium dithionite, alkylated sulfites, formic acid or erythorbate salts.

Examples of suitable free radical scavengers include sulfur compounds such a thiourea, 2-mer- captobenzothiazole, dimedone, ammonium thiocyanate, or tertramethylthiuram disulfide.

Examples of sulfide scavengers include aldehydes or ketones.

Examples of suitable bactericides and/or biocides include henoxyethanoi, ethylhexyl glycerine, benzyl alcohol, methyl chloroisothiazolinone, methyl isothiazolinone, methyl paraben, ethyl paraben, propylene glycol, bronopol, benzoic acid, imidazolinidyl urea, 2,2-dibromo-3-nitrilo- propionamide, or 2- bromo-2-nitro-1 ,3-propane diol.

Further chelating agents

In an embodiment of the invention, the aqueous fluid additionally comprises at least one chelating agent different from the mixture to be used according to the present invention, including but not limited to glutamic acid Ν,Ν-diacetic acid (GLDA), nitrilotriacetic acid (NTA), ethylenedia- minetetraacetic acid (EDTA), diethylenetriaminepentaacetic acid (DTPA), or hydroxyethyleth- ylenediaminetriacetic acid (HEDTA).

Specific processes for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs Matrix acidizing

In one embodiment of the invention the process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs is a matrix acidizing process. The aqueous fluid for use in the matrix acidizing process comprises at least water, the mixture of chelating agents as described above, and an acid. It may optionally comprise further components.

The pH value should be less than or equal 7 preferably less than 7, preferably less than or equal to 6 and more preferably less than or equal to 5.5. In an embodiment of the invention, the pH-value is from 0 to 5.5, preferably from 0 to 5. By the way of example the pH may be from 1 to 3 or from 1 .5 to 2.5.

The aqueous fluid comprising at least an acid is capable of dissolving at least a part of the hy- drocarbon bearing reservoir and/or dissolving scales and/or fine particles present in the formation. These measures yield an increased permeability of the reservoir so that the reservoir fluids can flow better to the production wellbore, thereby increasing the production. In case of matrix acidizing the pressure of injecting the aqueous fluid is limited to pressures not sufficient to hydraulically create fissures and/or fractures in the formation.

Suitable acids, including preferred acids have already been mentioned above. Suitable acids may be selected in particular according to the nature of the formation to be acidized. For carbonate reservoirs or carbonates containing reservoirs a wide variety of acids may be used, for instance HCI and/or methane sulfonic acid. If the formation comprises sandstone and it is desired to also dissolve such silicates HF or acid mixtures comprising HF, e.g. mixtures of HCI and HF should be used.

In another embodiment of the invention a mixture of formic acid and acetic acid may be used. Organic acids are in particular advantageous at higher formation temperatures, e.g. at temperatures > 90°C Preferred reservoir temperatures have already been mentioned.

In an embodiment, the concentration of the mixture of chelating agents in the aqueous fluid may be in the range of from 0.05 % to 2 % by weight, preferably 0.1 to 1 % by weight, relating to the total of all components of the respective aqueous formulation. In another embodiment, the con- centration of the mixture of chelating agents may be from 2.5 % to 30 % by weight with respect to the total formulation, preferably 5 % to 25 % by weight and for example 10 % to 20 % by weight.

Besides water, the mixture of complexing agents and at least one acid, the aqueous fluid to be used in matrix acidizing may comprise further components. Suitable further components have already been mentioned.

In one embodiment, the aqueous fluid for use in the matrix acidizing process comprises at least water, the mixture of chelating agents as described above, an acid and a corrosion inhibitor. Suitable corrosion inhibitors have already been mentioned above. In a preferred embodiment, the corrosion inhibitor comprises ethyleneglycole propargylether.

In one embodiment, the aqueous fluid for use in the matrix acidizing process comprises at least water, the mixture of chelating agents as described above, an acid and a diverting agent. Exam- pies of suitable diverting agents have been mentioned above. In one embodiment degradable particulates such as polylactic acid or polylactide particulates may be used.

In one embodiment, the aqueous fluid for use in the matrix acidizing process comprises at least water, the mixture of chelating agents as described above, an acid and a viscosifier.

In one embodiment, the aqueous fluid for use in the matrix acidizing process comprises at least water, the mixture of chelating agents as described above, an acid and viscoelastic surfactants (VES). A VES-containing acidizing fluid often relies on the increase in viscosity when the pH of the treatment fluid increases to a pH where these surfactants transition to a gelled state.

Fracture acidizing

The process of acidizing according to the present invention may be combined with a fracturing process (the so called "fracture acidizing").

In course of fracture acidizing the aqueous fluid is injected into the reservoir at a pressure suffi- cient to hydraulically create fissures and/or fractures in the reservoir. After fracturing the applied pressure is released thereby allowing at least a portion of the injected aqueous fluid to flow back from the reservoir into the wellbore. A proppant contained in the aqueous fluid keeps the fractures formed open also after release of the pressure. The aqueous fluid for use in the fracture acidizing process comprises at least water, the mixture of chelating agents, an acid, a proppant and a viscosifier. The viscosifier ensures that the prop- pant does not sediment in the aqueous fluid but is transported into the reservoir. Suitable prop- pants and viscosifiers have already been mentioned. In one embodiment, the viscosifier is a polysaccharide and/or polysaccharide derivative, in particular guar gum and/or a guar gum derivative.

In another embodiment, viscosifier is a polymer comprising acryl amide units and at least one monoethylenically unsaturated monomer comprising cationic groups.

Polymeric viscosifiers may be used together with crosslinkers in order to enhance the viscosify- ing effect. Suitable crosslinkers have already been mentioned above.

In one embodiment, the viscosifier is a polysaccharide and/or polysaccharide derivative, in par- ticular guar gum and/or a guar gum derivative and at least one crosslinker.

In order to ease removal of the aqueous fluid from the formation after pressure release the aqueous fluid may comprise further components. In one embodiment the aqueous fluid comprises at least one breaker, for instance encapsulated breakers. Examples of suitable breakers have already been mentioned.

In one embodiment the viscosifier is a polysaccharide and/or polysaccharide derivative, in particular guar gum and/or a guar gum derivative and the breaker is an enzyme, in particular an encapsulated enzyme.

In another embodiment, the aqueous fluid comprises at least one flowback aid. Examples of suitable flowback aids have already been mentioned. Fracturing

The process according to the present invention may also be a "simple" fracturing process, i.e. the reservoir is fracked as mentioned above, however, the aqueous fluid doesn't necessarily comprise an acid. Besides that, we refer to our disclosure above.

Scale inhibition and/or dissolution of scale

In another embodiment of the invention, the process for increasing the production from hydro- carbon bearing reservoirs is a process for the inhibition and/or dissolution of scale.

In the course of mineral oil and/or natural gas production, solid deposits of inorganic or organic substances can form in a mineral oil and/or natural gas containing subterranean formation itself, in underground installation parts, for example the well lined with metal tubes, and in above- ground installation parts, for example separators. The formation of such solid deposits is extremely undesirable because they can at least hinder the production of mineral oil or natural gas and, in extreme cases, lead to complete blockage of the installation parts affected. Such deposited scales typically comprise carbonates such as calcium carbonate or magnesium carbonate but also sulfates, such as calcium sulfate, strontium sulfate or barium sulfate.

In the process for the inhibition and/or dissolution of scale such scales may be dissolved using suitable aqueous fluids comprising at least water and the mixture of chelating agents mentioned above. Preferably, the aqueous fluid also comprises at least one acid. Examples of suitable acids have already been mentioned above.

In another embodiment, the aqueous fluid furthermore comprises at least one additional scale inhibitor. Suitable examples have been mentioned above.

Removal of filter cakes

In another embodiment of the present invention, the process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs is a process for removing filter cakes.

In oil well operations filter cakes may be formed within a subterranean formation by the intro- duction of a material capable of forming an impermeable layer on the walls of the wellbore, in particular during the drilling. Such a filter cake prevents the flow of drilling fluid into the formation. Let aside the loss of drilling fluid, drilling fluid in the formation may damage the near wellbore area and thereby hinder the flow of oil or gas from the formation into the wellbore. For this reason such a filter cake has to be removed.

For removing filter cakes the respective filter cake is brought into contact with the aqueous fluid described by injecting the aqueous fluid into the wellbore. For the process of removing filter cakes according to the present invention suitable aqueous fluids comprising at least water the mixture comprising chelating agents as described above are used. Besides such components, the aqueous fluids may comprise additional components, i.e. enzymes, in particular encapsulated enzymes such as oamylases.

Advantages

The present invention provides an improved process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs by substitution MGDANa3 which is known in the art by the mixture of chelating agents as described above.

The mixture has a lower content of sodium ions than MGDANa3 (technical MGDANa3 28.75 wt. % for the solid or 1 1 .5 wt. % for a solution comprising 40 wt. % solids; a typical mixture as described may have only about 22.25 wt. % or 8.9 wt. % for a solution comprising 40 wt.% solids). Consequently, also aqueous treatment fluids have a lower sodium content than aqueous treatment fluids comprising MGDANa3 thereby diminishing the risk of precipitating sodium fluorosili- cates in case of acidizing silicate containing reservoirs.

Furthermore, less acid is needed to adjust the pH value of an aqueous treatment fluid compris- ing the mixture of chelating agents to a certain pH as compared to an identical treatment fluid except that MGDANa3 is used instead of the described mixture of complexing agents.

Despite such differences, the complexing capacity of the mixture of chelating agents as described above still is sufficient.

Acidizing carbonate formations can be challenging due to the relatively rapid reactivity of the carbonate with the acid. For instance, acid treatments in carbonate formations are plagued by at least two complications: (1 ) radial penetration, and (2) fluid loss of the acidizing fluid into the formation. The first problem, radial penetration, results from the fast reaction of the acid with the formation matrix upon introduction of the fluid in the near well bore region. The radial acid penetration is often limited to just a few inches to a few feet, which is not optimal. Those portions of the formation that are more distal to the wellbore (as one moves radially outward from the well- bore) remain untouched by the acid because the acid will fully spend. In fact, due to such limited penetration, it is believed that acid matrix treatments are limited in carbonate formations to those treatments focused on removing near-wellbore flow restrictions. Yet low permeability at any point along the hydrocarbon flow paths can impede flow (hence production), which is undesirable. Fluid loss of the matrix acidizing fluid into smaller wormholes neighboring the near well bore region only serves to exacerbate this radial penetration problem. Consequently, to try to achieve maximum radial penetration, prodigious fluid volumes are often required, which can prove costly. To improve radial penetration involves controlling the fluid loss of the matrix acidizing fluid so as to attempt to extend the radial depth of the main channels. Fluid loss in acidizing fluids for carbonate formations is typically controlled by the addition of polymeric gelling agents to the acidizing fluid. These polymeric gelling agents modify the relative viscosity of the treatment fluid, therefore, reducing or eliminating fluid loss flow into the natural permeability within the formation. However, such gels may prove problematic in that they can block conductive channels thereby reducing the conductivity of the formation if they are not removed prior to production. Extra steps are usually necessitated to remove the gel, such as breaking the gel downhole by adding an additional chemical breaker component to the formation and allowing sufficient time to pass to allow that breaker to break the gel, to improve conductivity.

Of the many advantages of the present invention, one is that the chelating agent in the com- plexing-acidizing treatment fluids is able to complex with metal divalent and trivalent cations that result from dissolution of the formation material by the acid to form "aggregate blocking agenting agents" in situ. These aggregate blocking agenting agents are believed to block fluid loss of the complexing-acidizing fluids through the smaller wormholes in the formation matrix by plugging the newly created paths or microfractures therein. This results in diversion of the complexing- acidizing fluid to the primary channels formed by the matrix treatment, which is believed to consequently extend the radial penetration of the acidizing treatment. It is notable that no external components, such as polymeric gels or other non-related diverting agents, are required to be included in the fluid to achieve this fluid loss prevention and diversion result. Because the treatment fluids of this disclosure are able to form these aggregate blocking agents in situ without the addition of external components, the complexing-acidizing treatment fluids disclosed herein may be considered "self-diverting," as that term is described herein.

Often challenges in formations subjected to acid stimulation in offshore applications include high temperatures (300°F and above), low reservoir pressure (0.3 psi/ft and below), highly heterogeneous multilayered formations with large perforated intervals (greater than 1 ,300 ft net and 2,400 ft gross), and scale in the wellbore, perforations, and sometimes in the near-wellbore area (NWA). When treated with conventional acid systems based on hydrochloric acid (HCI), only sustain the productivity increase for very short periods. Such conventional acid systems have been based on 7.5% HCI and 10% acetic acid (AcOH) with high loadings of corrosion inhibitor, iron sequestering agents, demulsifiers, and antisludge agents. This approach has constraints that can potentially include the following: ineffective stimulation attributed to fast acid reaction rates, limited penetration of live acid, rock disintegration, damage from reprecipitation of acid reaction products, such as iron and mineral fines from wellbore scale, damage from high corrosion inhibitor loading, fluids (stimulation and reservoir) incompatibility.

The use of chelating based stimulation fluid described here provides advantages that circum- vent these constraints and provides deeper stimulation treatments because of lower reaction rates and potentially a more effective wormhole type of reaction for the reservoirs' characteristics. This fluid also chelates reaction products to help enable superior cleanup of the acid sys- tem. This system also requires lower loadings of corrosion inhibitors, demulsifiers, and an- tisludge agents, and is more compatible with formation lithology, lowering the risk of formation damage. The examples which follow are intended to illustrate the invention in detail: Manufacture of the mixture of chelating agents to be used Compound (I a):

L-CH₃-CH(COOX²)-N(CH₂CN)2 with X² is (Na_yHi_-y), y is 0.65. Compound (I a) was made according to WO 2015/036324.

Step (a.1 ):

An amount of 293.3 g (31 .6 wt.-%, 0.51 mol) of compound (I a) was used as aqueous solution. Step (b.1 ):

A 1-l-three-necked flask was charged with 100 g of 10% by weight aqueous solution of NaOH (corresponds to 0.25 mol NaOH). Under stirring, the solution from step (a.1 ) and 59.6 g of 50 % by weight aqueous NaOH (0.745 mol) were added simultaneously over a period of 120 minutes under cooling. The temperature did not exceed 40°C. The reaction mixture was stirred addi- tional 60 minutes at 40°C.

Step (c.1 ):

The reaction mixture obtained from step (b.1 ) was stirred at 70°C for 60 minutes, sub-step (c2.1 ).

Then, the reaction mixture was refluxed for 240 minutes at a reduced pressure of 900 to 950 mbar, the temperature rose up to 90 to 100°C, sub-step (c3.1 ). Since considerable amounts of ammonia evaporated together with water, the loss of water was partially compensated by adding deionized water. It was observed that the temperature dropped to lower temperatures.

After completion of sub-step (c3.1 ), an orange-brown reaction mixture of 362.2 g inventive mixture (IM.1 ) was obtained.

(IM.1 ) displayed an iron-binding capacity of 1.513 mmol/g. This corresponds to a yield of 97 % (calculated as MGDA-H3) . The NTA content (calculated as NTA-H3) was < 0.1 wt.-% according to HPLC analysis.

The ratio of components (A) to (B) was 1.4 to 1. The pH value of the solution obtained was 10.2.

The content of NaCI was 16.6 mg/kg, and the content of Na2S0₄ was about 4.4 mg/kg, both de- termined by ICP measurements.

Sodium content (relating to the total of solids): 22.25 % by weight. MGDANas

For the tests, commercially available MGDANa3 (Trilon^® M) was used.

Sodium content (relating to the total of solids): 28.75 % by weight.

The pH value of a commercially available 40 % solution of MGDA in water is about 13.

Application tests:

1 ) pH Adjustment

For the tests the abovementioned mixture of complexing agents (Complexing agent B) de- scribed above was used

Corrosion Inhibitor: Potassium iodide at 0.1 % by wt with 2% by vol. % of Basocorr® ACI 100.

For the tests, solutions of the complexing agents to be tested and the corrosion inhibitor in 250 ml were prepared and acidized with concentrated HCI or concentrated HCI + NH4HF2

Test 1.1

0.25M Complexing agent B + 2 vol% Corrosion inhibitor + HCI (36.31wt%)

> HCI needed for 250 ml preparation - 9 ml

> Final pH: 2

Test 1.2

0.6M Complexing agent B +2 vol% Corrosion inhibitor + HCI (36.31 wt%)

> HCI needed for 250 ml preparation - 20 ml

> Final pH: 2

Test 1.3

0.25M Complexing agent B + 2 vol% Corrosion inhibitor + HCI (36.31wt%)+ 2% NH4HF2

> HCI needed for 250 ml preparation (only for pH adjustment) - 13 ml

> Final pH: 2.5

2) Core flood test

Formulation of the mixture of chelating agents

For the tests a formulation comprising the following components was used:

Component

Chelating agent Aqueous solution of the chelating agent mixture as obtained above

(pH = 10.6, concentration 40 % by wt.)

Corrosion inhibitor Ethyleneglycole propargyl ether

Potassium iodide

HCI To the aqueous solution of the chelating agent, 2 vol. % of the corrosion inhibitor, 0.1 % by wt. of Kl were mixed, diluted with deionized water and the pH adjusted with HCI to achive a solution comprising 20 % by wt. of the chelating agent mixture and having a pH of 2 (all percentages re- late to the total of the final solution).

Equipment for core flood test

All experiments were conducted with Indiana carbonate core at 148.9°C, 7.584 MPa back pressure, and 13.790 MPa overburden pressure. Table 1 summarizes the coreflooding information.

Table 1. Coreflooding information

The experiment procedure is described below.

1. The core was dried at 121.1 °C.

2. Perform CT scan for the dried core.

3. The absolute permeability (initial permeability) was determined at 25°C using various injection rates of 1 , 2, 4, 5, and 10 cm³/min.

4. Continuous values of the pressure drop across each core were monitored (using deionized water) until steady state conditions were achieved.

5. The permeabilities of the cores were calculated using Darcy's law.

6. The porosity of the cores was determined by using the weight method from the weight difference between the saturated and dried cores.

7. Perform CT scan for the saturated core.

8. Reload the core to the coreflood system, inject deionized water at rates of 5 cm³/min at room temperature for around 3 PV.

9. Then inject deionized water at rates of 5 cm³/min for around three hours at temperature of 148.9°C.

10. The core is ready to pump chemical: pump the chemical using injection rate of 5 cm³/min at pH of 2.

1 1. Then inject deionized water at rates of 5 cm³/min until no color change in the injected water. 12. The final permeability were measure at 77°F (25°C) using various injection rates of 1 , 2, 4, 5, and 10 (cm³/min).

13. Perform CT scan after final permeability measurements. Results of Core Flood test:

Figure 1 shows the pressure drop across the core. The pressure drop started at 91 .0 kPa and then gradually increased because of the increase in the viscosity of the chemical solution. Then, after the injection of 2.88 PV of chemical solution, the pressure drop to 12.4 kPa, which indicating a good wormwhole formation and successful stimulation of core permeability.

Claims

Claims:

Process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs comprising at least the step of introducing an aqueous fluid comprising at least one chelating agent into the formation, wherein the chelating agent is a mixture of compounds, comprising

(C) at least one compound according to general formula (I)

R¹-CH(COOX¹)-N(CH₂COOX¹)₂ (I)

(D) at least one compound selected from compounds according to general formula (Ilia) and (1Mb):

R -CH(COOX )-N(CH₂COOX )(CH₂CONH₂) (Ilia)

R -CH(COOX )-N(CH₂CONH₂)₂ (1Mb)

wherein

CH₂CH₂COOX¹,

X¹ is (Na_xHi-x),

x is in the range of from 0.6 to 1 , and

Process according to claim 1 , wherein R¹ is methyl.

Process according to claim 1 or 2, wherein compound (I) is the racemic mixture.

Process according to claim 1 or 2 wherein component (A) is a mixture of enantiomers containing predominantly the respective L-enantiomer with an enantiomeric excess (ee) in the range of from 10 to 98 %.

Process according to any of claims 1 to 4, wherein the formation temperature is 50°C to 200°C.

Process according to any of claims 1 to 4, wherein the formation temperature is 100°C to 200°C. 7. Process according to any of claims 1 to 6, wherein the process is a matrix acidizing process and the aqueous fluid comprises at least water, the mixture of compounds according to any of claims 1 to 4, and an acid.

8. Process according to claim 7, wherein the acid is at least one selected from the group of HCI, HF, formic acid, acetic acid, p-toluenesulfonic acid, amido sulfonic acid or methane sulfonic acid. 9. Process according to claim 7, wherein the acid comprises a mixture of formic acid and acetic acid.

10. Process according to any of claims 7 to 9, wherein the aqueous fluid comprises additionally at least one corrosion inhibitor.

1 1. Process according to claim 10, wherein the corrosion inhibitor comprises ethyleneglycole propargylether.

12. Process according to any of claims 7 to 1 1 , wherein the pH of the aqueous fluid is from 0 to 5.5.

13. Process according to claim 7, wherein the hydrocarbon bearing reservoir comprises silicates and the acid comprises HF. 14. Process according to claim 13, wherein the acid comprises a mixture of HCI and HF.

15. Process according to any of claims 1 to 6, wherein the process is a fracture acidizing process and the aqueous fluid comprises at least water, the mixture of compounds according to any of claims 1 to 4, an acid, a proppant and a viscosifier.

Process according to claim 15, wherein the viscosifier is a polymeric viscosifier.

17. Process according to claim 16, wherein the polymeric viscosifier is a polymer comprising acryl amide units and at least one monoethylenically unsaturated monomer comprising cationic groups.

18. Process according to claims 16 or 17, wherein the aqueous fluid additionally comprises a crosslinker. 19. Process according to any of claims 1 to 6, wherein the process is a fracturing process.

20. Process according to any of claims 1 to 6, wherein the process is a process for inhibiting and/or removing scale. 21. Process according to any of claims 1 to 6, wherein the process is a process for the removal of filter cakes.