WO2018086984A1 - Procédé permettant d'augmenter la production d'hydrocarbures à partir de réservoirs pétrolifères - Google Patents

Procédé permettant d'augmenter la production d'hydrocarbures à partir de réservoirs pétrolifères Download PDF

Info

Publication number
WO2018086984A1
WO2018086984A1 PCT/EP2017/078083 EP2017078083W WO2018086984A1 WO 2018086984 A1 WO2018086984 A1 WO 2018086984A1 EP 2017078083 W EP2017078083 W EP 2017078083W WO 2018086984 A1 WO2018086984 A1 WO 2018086984A1
Authority
WO
WIPO (PCT)
Prior art keywords
acid
process according
mixture
aqueous fluid
coox
Prior art date
Application number
PCT/EP2017/078083
Other languages
English (en)
Inventor
Jia Zhou
Shawn RIMASSA
Jeremy MANNING
Hisham Nasr-El-Din
Original Assignee
Basf Corporation
Basf Se
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Basf Corporation, Basf Se filed Critical Basf Corporation
Publication of WO2018086984A1 publication Critical patent/WO2018086984A1/fr

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/04—Aqueous well-drilling compositions
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/72—Eroding chemicals, e.g. acids
    • C09K8/74—Eroding chemicals, e.g. acids combined with additives added for specific purposes
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/20—Hydrogen sulfide elimination

Definitions

  • 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.
  • 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
  • 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.
  • 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 methyl glycine diacetic acid
  • 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.
  • a stoichiometric amount of alkali hydroxide or an excess of alkali hydroxide is applied, see, e. g., US 7,671 ,234.
  • MGDA is made by addition of
  • 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.
  • a targeted pH e.g. pH 2
  • Acidic treatment fluids for treating silicate formations usually comprise HF or HF-generating compounds.
  • HF is able to dissolve silicates and alumosilicates thereby yielding fluorosilicates.
  • fluorosilicates may form precipitates with Na + or K + thereby yielding insoluble sodium- or potassium fluorosilicates (see for instance Malcolm A.
  • 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.
  • ammonium salts of complexing agents it is known in the art to use ammonium salts of complexing agents.
  • 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.
  • 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.
  • a process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs 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
  • R 1 is selected from Ci-C4-alkyl, linear or branched, phenyl, benzyl, CH 2 OH, and
  • X 1 is (Na x Hi-x), x is in the range of from 0.6 to 1 , and
  • 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
  • R 1 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, CH 2 OH, and CH 2 CH 2 COOX 1 ,
  • X 1 is (Na x Hi- x ), wherein
  • x is in the range of from 0.6 to 1 .
  • 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 .
  • R 1 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.
  • 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 %.
  • 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 R 1 is methyl.
  • 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%.
  • all components of inventive mixtures constitute the respective racemic mixtures.
  • the ee refers to the enantiomeric excess of all L-isomers present in component (A) compared to all D-isomers in component (A).
  • 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).
  • the inventive mixture may contain some compound that has the general formula
  • 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.
  • 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.
  • 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.
  • inventive mixtures may contain less than 0.2 % by weight of nitrilotriacetic acid (NTA), preferably 0.01 to 0.1 % by weight.
  • NTA nitrilotriacetic acid
  • mixtures in which R 1 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.
  • mixtures that contain an optically active compound according to general formula (I) may contain one or more optically active impurities.
  • 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).
  • 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.
  • 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 Mg 2+ or Ca 2+ , or transition metal ions such as Fe 2+ or Fe 3+ 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.
  • 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) refers to providing a solid or a slurry or a solution of a compound according to general formula (I I a)
  • 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.
  • 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.
  • 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.
  • R 1 is defined as above.
  • X 2 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.
  • R 1 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) 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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-%.
  • 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.
  • 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.
  • 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) 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.
  • 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.
  • each sub-step may be performed at a temperature that is higher than the temperature at which the previous sub- step was performed.
  • sub-steps differ in temperature by at least 10°C, said temperature referring to the average temperature.
  • 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.
  • 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 ).
  • 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.
  • step (c) has an overall duration in the range of from 30 minutes up to 24 hours, preferably 2 to 16 hours.
  • 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.
  • 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
  • at least another sub-step of step (c) is carried out at a temperature in the range of from 100 to 200°C.
  • 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.
  • step (c) water is added during the course of step (c), for example in order to compensate for the loss of water due to ammonia removal.
  • 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.
  • 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.
  • said final sub-step of step (c) 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.
  • 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).
  • 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).
  • 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.
  • step (c) 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).
  • 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.
  • 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.
  • 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.
  • 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.
  • 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):
  • 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).
  • 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 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.
  • 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.
  • increasing the productivity may be achieved by at least one of the following measures:
  • the hydrocarbon bearing reservoirs may be any kind of reservoirs.
  • the reservoir is selected from reservoirs comprising carbonates, sandstone, or shale.
  • 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.
  • 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.
  • salts comprise halogenides, in particular chlorides, sulfates, borates of mono- or divalent cations such as Li + , Na + , K + , Mg 2+ , Ca 2+ , Sr 2+ , or Ba 2+ .
  • 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.
  • the aqueous fluid may comprise organic solvents miscible with water.
  • 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.
  • 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.
  • water and optionally organic solvents miscible with water are examples of such organic solvents.
  • 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
  • R 1 is selected from Ci-C4-alkyl, linear or branched, phenyl, benzyl, CH2OH, and
  • X 1 is (Na x Hi-x)
  • x is in the range of from 0.6 to 1 .
  • component (A) and component (B) being in a molar ratio (A)/(B) in the range of from 2.5 : 1 to 0.1 : 1 .
  • 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.
  • aqueous fluids for use in the process according to the present invention may comprise further components.
  • 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.
  • the aqueous fluid comprises additionally at least one acid.
  • Acids may be generally to adjust the pH value of the fluid.
  • 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.
  • acids may be used to dissolve scales, for instance scales on the wellbore walls and/or wellbore equipment.
  • 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 R 2 -SOsH, where R 2 is a straight-chain, branched or cyclic alkyl radical.
  • R 2 is selected from straight-chain or branched Ci-C6-alkyl, preferably Ci-C4-alkyl.
  • R 2 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.
  • 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.
  • 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.
  • 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.
  • the pH-value is from 0 to 5.5, more preferably from 0 to 5.
  • the pH may be from 1 to 3 or from 1 .5 to 2.5.
  • 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.
  • 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.
  • the corrosion inhibitor comprises ethyleneglycole propargylether.
  • the aqueous fluid comprises at least an acid and a corrosion inhibitor, preferably ethyleneglycole propargylether.
  • 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.
  • 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.
  • the aqueous fluid comprises additionally at least one diverting agent.
  • 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.
  • 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.
  • thickening polymers comprise biopolymers or modified biopolymers such as xan- thans, Scleroglucanes, galactomannan gums, or cellulose derivatives.
  • galactoman- nan gums include gum arabic, gum ghatti, gum karaya, tamarind gum, tragacanth gum, guar gum, or locust bean gum.
  • derivatives include hydroxyethylguar, hydroxypropyl- guar, carboxymethylguar, carboxymethyl hydroxyethylguar and carboxymethyl hydroxypropyl- guar.
  • suitable cellulose derivatives include hydroxyethyl cellulose, carboxyethyl- cellulose, carboxymethylcellulose, or carboxymethylhydroxyethylcellulose.
  • thickening polymers comprise synthetic polymers, in particular poly acryla- mides or copolymers comprising acrylamide units and one or more comonomers.
  • 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)acryloyloxyal
  • the thickening polymer comprises acryl amide units and at least one monoethylenically unsaturated monomer comprising cationic groups.
  • 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.
  • the thickening polymers may also comprise associating monomers such as the associating monomers disclosed in WO 2010/133527 A1 and WO 2015/086468 A1.
  • 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.
  • the viscosifier is guar gum and/or a guar gum derivative.
  • the viscosifier is a copolymer comprising at least acryl amide units and one monoethylenically unsaturated monomer comprising cationic groups.
  • Crosslinkers
  • 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.
  • 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.
  • 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/m 3 to 3500 kg/m 3 of the fracturing fluid, in particular from 50 kg/m 3 to 1200 kg/m 3 of the fracturing fluid.
  • 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.
  • breakers examples include oxidizing agents such as sodium chlorites, sodium bromate, hypochlorites, perborate, persulfates, and peroxides, including organic peroxides.
  • oxidizing agents such as sodium chlorites, sodium bromate, hypochlorites, perborate, persulfates, and peroxides, including organic peroxides.
  • suitable breakers include peroxide breakers, triethanol amine, or enzymes. The breakers may be encapsulated so that breaking only occurs with some delay.
  • 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, ⁇ -galactosidases, or any combination thereof.
  • the glucosidases can be a- glucosidases, ⁇ -glucosidases, or any combination thereof.
  • the amylases can be a-amylases, ⁇ - amylases, ⁇ -amylases, or any combination thereof.
  • the enzyme is a thermostable or thermotolerant enzyme.
  • the enzyme is a cellulase.
  • the breaker is an encapsulated enzyme, in particular an encapsulated cellulase.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the aqueous fluid comprises additionally at least one wetting agent.
  • Wetting agents may be used to modify the wettability properties of the reservoir surfaces.
  • 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.
  • 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.
  • fluid loss additives examples 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.
  • 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.
  • degradable materials such as polysaccharides, polyesters, polylactides, or polyethyleneoxides.
  • 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.
  • the aqueous fluid comprises additionally at least one scale inhibitor.
  • 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.
  • the aqueous fluid comprises additionally at least one scale inhibitor.
  • 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.
  • the aqueous fluid comprises at least one stabilizer selected from the group of oxygen scavengers, free radical scavengers, sulfide scavengers or bacteri- cides/biocides.
  • suitable oxygen scavengers include inorganic or organic sulfites such as sodium sulfite, sodium dithionite, alkylated sulfites, formic acid or erythorbate salts.
  • Suitable free radical scavengers include sulfur compounds such a thiourea, 2-mer- captobenzothiazole, dimedone, ammonium thiocyanate, or tertramethylthiuram disulfide.
  • sulfide scavengers examples include aldehydes or ketones.
  • bactericides and/or biocides examples 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.
  • 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 ⁇ , ⁇ -diacetic acid (GLDA), nitrilotriacetic acid (NTA), ethylenedia- minetetraacetic acid (EDTA), diethylenetriaminepentaacetic acid (DTPA), or hydroxyethyleth- ylenediaminetriacetic acid (HEDTA).
  • glutamic acid ⁇ , ⁇ -diacetic acid GLDA
  • NTA nitrilotriacetic acid
  • EDTA ethylenedia- minetetraacetic acid
  • DTPA diethylenetriaminepentaacetic acid
  • HEDTA hydroxyethyleth- ylenediaminetriacetic acid
  • 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.
  • the pH-value is from 0 to 5.5, preferably from 0 to 5.
  • 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.
  • 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 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the corrosion inhibitor comprises ethyleneglycole propargylether.
  • 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.
  • degradable particulates such as polylactic acid or polylactide particulates may be used.
  • 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.
  • 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).
  • VES viscoelastic surfactants
  • the process of acidizing according to the present invention may be combined with a fracturing process (the so called “fracture acidizing").
  • 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.
  • the viscosifier is a polysaccharide and/or polysaccharide derivative, in particular guar gum and/or a guar gum derivative.
  • 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.
  • 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.
  • the aqueous fluid may comprise further components.
  • the aqueous fluid comprises at least one breaker, for instance encapsulated breakers. Examples of suitable breakers have already been mentioned.
  • 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.
  • the aqueous fluid comprises at least one flowback aid.
  • suitable flowback aids have already been mentioned.
  • 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.
  • the process for increasing the production from hydro- carbon bearing reservoirs is a process for the inhibition and/or dissolution of scale.
  • 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.
  • Such scales may be dissolved using suitable aqueous fluids comprising at least water and the mixture of chelating agents mentioned above.
  • the aqueous fluid also comprises at least one acid. Examples of suitable acids have already been mentioned above.
  • the aqueous fluid furthermore comprises at least one additional scale inhibitor. Suitable examples have been mentioned above.
  • the process for increasing the production of hydrocarbons from hydrocarbon bearing reservoirs is a process for removing filter cakes.
  • 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.
  • the respective filter cake is brought into contact with the aqueous fluid described by injecting the aqueous fluid into the wellbore.
  • suitable aqueous fluids comprising at least water the mixture comprising chelating agents as described above are used.
  • the aqueous fluids may comprise additional components, i.e. enzymes, in particular encapsulated enzymes such as oamylases.
  • 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.
  • an aqueous treatment fluid comprising 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.
  • Acidizing carbonate formations can be challenging due to the relatively rapid reactivity of the carbonate with the acid.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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):
  • 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 (b.1 ) The reaction mixture obtained from step (b.1 ) was stirred at 70°C for 60 minutes, sub-step (c2.1 ).
  • 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.
  • 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 Na2S0 4 was about 4.4 mg/kg, both de- termined by ICP measurements.
  • the pH value of a commercially available 40 % solution of MGDA in water is about 13.
  • Corrosion Inhibitor Potassium iodide at 0.1 % by wt with 2% by vol. % of Basocorr® ACI 100.
  • 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
  • HCI 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).
  • the core was dried at 121.1 °C.
  • the absolute permeability (initial permeability) was determined at 25°C using various injection rates of 1 , 2, 4, 5, and 10 cm 3 /min.
  • the porosity of the cores was determined by using the weight method from the weight difference between the saturated and dried cores.
  • the core is ready to pump chemical: pump the chemical using injection rate of 5 cm 3 /min at pH of 2.
  • 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.

Landscapes

  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)

Abstract

L'invention concerne un procédé d'augmentation de la productivité de réservoirs pétrolifères. Le procédé d'augmentation de la production d'hydrocarbures à partir de réservoirs pétrolifères comprend au moins l'étape consistant à introduire un fluide aqueux comprenant au moins un agent chélatant dans la formation, l'agent chélatant étant un mélange d'au moins deux composés différents. De préférence, le procédé est un procédé d'acidification et/ou de fracturation.
PCT/EP2017/078083 2016-11-10 2017-11-02 Procédé permettant d'augmenter la production d'hydrocarbures à partir de réservoirs pétrolifères WO2018086984A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
EP16198082.6 2016-11-10
EP16198082 2016-11-10

Publications (1)

Publication Number Publication Date
WO2018086984A1 true WO2018086984A1 (fr) 2018-05-17

Family

ID=57281124

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/EP2017/078083 WO2018086984A1 (fr) 2016-11-10 2017-11-02 Procédé permettant d'augmenter la production d'hydrocarbures à partir de réservoirs pétrolifères

Country Status (1)

Country Link
WO (1) WO2018086984A1 (fr)

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2019191044A1 (fr) * 2018-03-27 2019-10-03 Texas A&M University Nanoparticules d'hydrogel contenant une enzyme pour nettoyage de fluide de fracturation hydraulique
CN110387220A (zh) * 2019-06-04 2019-10-29 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 一种注水井用耐酸颗粒暂堵剂及其制备方法
WO2020214180A1 (fr) * 2019-04-18 2020-10-22 Halliburton Energy Services, Inc. Traitement d'élimination de gâteau de filtration encapsulé

Citations (29)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3283816A (en) 1964-04-13 1966-11-08 Shell Oil Co Acidizing wells
US5783524A (en) 1994-12-14 1998-07-21 Basf Aktiengesellschaft Use of glycine-N,N-diacetic acid derivatives as complexing agents for alkaline earth metal and heavy metal ions in the production and transport of petroleum and natural gas
US5964295A (en) 1996-10-09 1999-10-12 Schlumberger Technology Corporation, Dowell Division Methods and compositions for testing subterranean formations
US20080153718A1 (en) 2005-03-04 2008-06-26 Basf Aktiengesellschaft Use of Water-Soluble Alkane Sulfonic Acids For Increasing the Permeability of Underground Petroliferous and/or Gas-Bearing Carbonate Rock Formations and For Dissolving Carbonate Contaminants and/or Contaminants Containing Carbonates During Petroleum Production
US7671234B2 (en) 2005-05-06 2010-03-02 Basf Aktiengesellschaft Method for producing methylglycine-N,N-diethanoic acid-trialkali metal salts with a low by-product content
US7754911B2 (en) 2005-05-06 2010-07-13 Basf Aktiengesellschaft Method for isolating methyl glycine nitrile-N,N-diacetonitriles from an aqueous crude mixture
WO2010133527A2 (fr) 2009-05-20 2010-11-25 Basf Se Copolymères associatifs à groupes hydrophobes
WO2011012164A1 (fr) 2009-07-30 2011-02-03 Basf Se Procédé de fracturation de formations souterraines
US20120097392A1 (en) 2006-08-04 2012-04-26 Halliburton Energy Services, Inc. Treatment Fluids Containing Biodegradable Chelating Agents and Methods for Use Thereof
US20120115759A1 (en) 2006-08-04 2012-05-10 Halliburton Energy Services, Inc. Treatment fluids containing a boron trifluoride complex and methods for use thereof
WO2012080297A1 (fr) 2010-12-17 2012-06-21 Akzo Nobel Chemicals International B.V. Procédé de régulation du fer dans des applications pétrolières et gazières à l'aide d'un agent chélatant
US20120202720A1 (en) 2010-12-17 2012-08-09 Akzo Nobel Chemicals International B.V. Environmentally friendly stimulation fluids, processes to create wormholes in carbonate reservoirs, and processes to remove wellbore damage in carbonate reservoirs
WO2012171857A1 (fr) 2011-06-13 2012-12-20 Akzo Nobel Chemicals International B.V. Traitement de formations de schiste à l'aide d'un agent chélatant
WO2013120806A1 (fr) 2012-02-13 2013-08-22 Akzo Nobel Chemicals International B.V. Amélioration de la résistance à la corrosion à l'aide d'agents chélateurs dans un équipement contenant un acier au carbone
US20130264060A1 (en) 2010-12-17 2013-10-10 Akzo Nobel Chemicals International B.V. Fluid suitable for treatment of carbonate formations containing a chelating agent
WO2013160334A1 (fr) 2012-04-27 2013-10-31 Akzo Nobel Chemicals International B.V. Procédé en une étape d'élimination du gâteau de filtration et de traitement d'une formation souterraine au moyen d'un agent chélateur
WO2013160332A1 (fr) 2012-04-27 2013-10-31 Akzo Nobel Chemicals International B.V. Mousse ou composition de viscosité améliorée contenant un agent chélateur
WO2013189731A1 (fr) 2012-06-18 2013-12-27 Akzo Nobel Chemicals International B.V. Composition contenant un agent chélateur émulsifié et procédé pour traiter une formation souterraine
WO2013189842A1 (fr) 2012-06-18 2013-12-27 Akzo Nobel Chemicals International B.V. Procédé de production d'huile ou de gaz à partir d'une formation souterraine utilisant un agent chélatant
US20140120276A1 (en) 2011-06-13 2014-05-01 Akzo Nobel Chemicals International B.V. Corrosion Resistance When Using Chelating Agents in Chromium-Containing Equipment
US20140124205A1 (en) 2011-06-13 2014-05-08 Akzo Nobel Chemicals International B.V. Process to fracture a subterranean formation using a chelating agent
WO2014108350A1 (fr) 2013-01-14 2014-07-17 Basf Se Procédé de fracturation de formations souterraines
WO2015012818A1 (fr) * 2013-07-24 2015-01-29 Halliburton Energy Services, Inc. Mousse de fluides de traitement contenant un agent chélateur à utiliser dans des stimulations de matrice souterraine et des opérations de nettoyage souterraines et de surface
WO2015030801A1 (fr) * 2013-08-30 2015-03-05 Halliburton Energy Services, Inc. Fluides acidifiants auto-détournants à base d'agent chélatant et procédés associés à ceux-ci
WO2015036324A1 (fr) 2013-09-13 2015-03-19 Basf Se Mélange d'énantiomères et procédé pour la fabrication de tels mélanges
WO2015086468A1 (fr) 2013-12-13 2015-06-18 Basf Se Procédé d'extraction de pétrole
WO2015126397A1 (fr) * 2014-02-20 2015-08-27 Halliburton Energy Services, Inc. Composition d'acidification pratiquement solide servant au traitement de formations souterraines
WO2015154977A1 (fr) 2014-04-11 2015-10-15 Basf Se Procédé d'acidification faisant appel à des formulations d'acides retardés
WO2016097026A1 (fr) 2014-12-17 2016-06-23 Basf Se Utilisation de mgda en tant qu'additif dans des procédés de récupération de pétrole brut et/ou de gaz à partir de formations souterraines

Patent Citations (30)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3283816A (en) 1964-04-13 1966-11-08 Shell Oil Co Acidizing wells
US5783524A (en) 1994-12-14 1998-07-21 Basf Aktiengesellschaft Use of glycine-N,N-diacetic acid derivatives as complexing agents for alkaline earth metal and heavy metal ions in the production and transport of petroleum and natural gas
US5964295A (en) 1996-10-09 1999-10-12 Schlumberger Technology Corporation, Dowell Division Methods and compositions for testing subterranean formations
US20080153718A1 (en) 2005-03-04 2008-06-26 Basf Aktiengesellschaft Use of Water-Soluble Alkane Sulfonic Acids For Increasing the Permeability of Underground Petroliferous and/or Gas-Bearing Carbonate Rock Formations and For Dissolving Carbonate Contaminants and/or Contaminants Containing Carbonates During Petroleum Production
US7671234B2 (en) 2005-05-06 2010-03-02 Basf Aktiengesellschaft Method for producing methylglycine-N,N-diethanoic acid-trialkali metal salts with a low by-product content
US7754911B2 (en) 2005-05-06 2010-07-13 Basf Aktiengesellschaft Method for isolating methyl glycine nitrile-N,N-diacetonitriles from an aqueous crude mixture
US20120097392A1 (en) 2006-08-04 2012-04-26 Halliburton Energy Services, Inc. Treatment Fluids Containing Biodegradable Chelating Agents and Methods for Use Thereof
US20120115759A1 (en) 2006-08-04 2012-05-10 Halliburton Energy Services, Inc. Treatment fluids containing a boron trifluoride complex and methods for use thereof
WO2010133527A2 (fr) 2009-05-20 2010-11-25 Basf Se Copolymères associatifs à groupes hydrophobes
WO2011012164A1 (fr) 2009-07-30 2011-02-03 Basf Se Procédé de fracturation de formations souterraines
US20130264060A1 (en) 2010-12-17 2013-10-10 Akzo Nobel Chemicals International B.V. Fluid suitable for treatment of carbonate formations containing a chelating agent
WO2012080297A1 (fr) 2010-12-17 2012-06-21 Akzo Nobel Chemicals International B.V. Procédé de régulation du fer dans des applications pétrolières et gazières à l'aide d'un agent chélatant
US20120202720A1 (en) 2010-12-17 2012-08-09 Akzo Nobel Chemicals International B.V. Environmentally friendly stimulation fluids, processes to create wormholes in carbonate reservoirs, and processes to remove wellbore damage in carbonate reservoirs
US20140116710A1 (en) 2011-06-13 2014-05-01 Akzo Nobel Chemicals International B.V. Treatment of shale formatons using a chelating agent
WO2012171857A1 (fr) 2011-06-13 2012-12-20 Akzo Nobel Chemicals International B.V. Traitement de formations de schiste à l'aide d'un agent chélatant
US20140124205A1 (en) 2011-06-13 2014-05-08 Akzo Nobel Chemicals International B.V. Process to fracture a subterranean formation using a chelating agent
US20140120276A1 (en) 2011-06-13 2014-05-01 Akzo Nobel Chemicals International B.V. Corrosion Resistance When Using Chelating Agents in Chromium-Containing Equipment
WO2013120806A1 (fr) 2012-02-13 2013-08-22 Akzo Nobel Chemicals International B.V. Amélioration de la résistance à la corrosion à l'aide d'agents chélateurs dans un équipement contenant un acier au carbone
WO2013160334A1 (fr) 2012-04-27 2013-10-31 Akzo Nobel Chemicals International B.V. Procédé en une étape d'élimination du gâteau de filtration et de traitement d'une formation souterraine au moyen d'un agent chélateur
WO2013160332A1 (fr) 2012-04-27 2013-10-31 Akzo Nobel Chemicals International B.V. Mousse ou composition de viscosité améliorée contenant un agent chélateur
WO2013189842A1 (fr) 2012-06-18 2013-12-27 Akzo Nobel Chemicals International B.V. Procédé de production d'huile ou de gaz à partir d'une formation souterraine utilisant un agent chélatant
WO2013189731A1 (fr) 2012-06-18 2013-12-27 Akzo Nobel Chemicals International B.V. Composition contenant un agent chélateur émulsifié et procédé pour traiter une formation souterraine
WO2014108350A1 (fr) 2013-01-14 2014-07-17 Basf Se Procédé de fracturation de formations souterraines
WO2015012818A1 (fr) * 2013-07-24 2015-01-29 Halliburton Energy Services, Inc. Mousse de fluides de traitement contenant un agent chélateur à utiliser dans des stimulations de matrice souterraine et des opérations de nettoyage souterraines et de surface
WO2015030801A1 (fr) * 2013-08-30 2015-03-05 Halliburton Energy Services, Inc. Fluides acidifiants auto-détournants à base d'agent chélatant et procédés associés à ceux-ci
WO2015036324A1 (fr) 2013-09-13 2015-03-19 Basf Se Mélange d'énantiomères et procédé pour la fabrication de tels mélanges
WO2015086468A1 (fr) 2013-12-13 2015-06-18 Basf Se Procédé d'extraction de pétrole
WO2015126397A1 (fr) * 2014-02-20 2015-08-27 Halliburton Energy Services, Inc. Composition d'acidification pratiquement solide servant au traitement de formations souterraines
WO2015154977A1 (fr) 2014-04-11 2015-10-15 Basf Se Procédé d'acidification faisant appel à des formulations d'acides retardés
WO2016097026A1 (fr) 2014-12-17 2016-06-23 Basf Se Utilisation de mgda en tant qu'additif dans des procédés de récupération de pétrole brut et/ou de gaz à partir de formations souterraines

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
MALCOLM A. KELLAND: "Production Chemicals for the Oil and Gas Industry", 2014, CRC PRESS, pages: 147 - 148

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2019191044A1 (fr) * 2018-03-27 2019-10-03 Texas A&M University Nanoparticules d'hydrogel contenant une enzyme pour nettoyage de fluide de fracturation hydraulique
US11667831B2 (en) 2018-03-27 2023-06-06 Texas A&M University Enzyme-encapsulated hydrogel nanoparticles for hydraulic fracturing fluid cleanup
WO2020214180A1 (fr) * 2019-04-18 2020-10-22 Halliburton Energy Services, Inc. Traitement d'élimination de gâteau de filtration encapsulé
CN110387220A (zh) * 2019-06-04 2019-10-29 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 一种注水井用耐酸颗粒暂堵剂及其制备方法

Similar Documents

Publication Publication Date Title
AU2011343272B2 (en) Fluid suitable for treatment of carbonate formations containing a chelating agent
EP2652077B1 (fr) Traitement de formations illitiques par utilisation d'un agent de chélation
US7992656B2 (en) Self healing filter-cake removal system for open hole completions
AU2011343385B2 (en) Ammonium salts of chelating agents and their use in oil and gas field applications
US20140124205A1 (en) Process to fracture a subterranean formation using a chelating agent
AU2011343382B2 (en) Process and fluid to improve the permeability of sandstone formations using a chelating agent
CA2694151C (fr) Fluides de traitement comprenant du xanthane clarifie et procedes associes
WO2012116032A1 (fr) Compositions de chélate et procédés et fluides pour utilisation dans des opérations de champ pétrolifère
EP2718391A1 (fr) Traitement de formations de schiste à l'aide d'un agent chélatant
AU2011343383A1 (en) Process to control iron in oil and gas applications using a chelating agent
WO2013160334A1 (fr) Procédé en une étape d'élimination du gâteau de filtration et de traitement d'une formation souterraine au moyen d'un agent chélateur
WO2018086984A1 (fr) Procédé permettant d'augmenter la production d'hydrocarbures à partir de réservoirs pétrolifères
CA2968773A1 (fr) Utilisation de mgda en tant qu'additif dans des procedes de recuperation de petrole brut et/ou de gaz a partir de formations souterraines

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 17804074

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 17804074

Country of ref document: EP

Kind code of ref document: A1