WO2024083796A1 - Procédé de traitement de formations souterraines - Google Patents

Procédé de traitement de formations souterraines Download PDF

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WO2024083796A1
WO2024083796A1 PCT/EP2023/078784 EP2023078784W WO2024083796A1 WO 2024083796 A1 WO2024083796 A1 WO 2024083796A1 EP 2023078784 W EP2023078784 W EP 2023078784W WO 2024083796 A1 WO2024083796 A1 WO 2024083796A1
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acid
mol
aqueous composition
water
ppm
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PCT/EP2023/078784
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English (en)
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Alain Zaitoun
Nicolas Gaillard
Nazanin SALEHI
Jérôme BOUILLOT
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Poweltec
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    • 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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular 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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/512—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
    • 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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/516—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material

Definitions

  • the present invention relates generally to hydrocarbon recovery. More particularly, the invention relates to a method for improving the conformance and/or fluid profiles in a subterranean formation from which hydrocarbons are to be recovered.
  • Hydrocarbons in particular oil
  • a well is drilled and because of the pressure of the reservoir, oil is produced by simple depressurization.
  • the pressure of the reservoir decreases and operators need to inject a displacement fluid (either gas or water) to pressurize the reservoir and promote the production of the remaining oil.
  • a displacement fluid either gas or water
  • operators inject the fluids in so called “injection wells” and produce oil in “production wells”.
  • the displacement fluid in particular water, propagates in the reservoir pushing the mobile hydrocarbons towards the production well.
  • reservoirs are subterranean formation containing different rock layers that are characterized by their permeabilities. From one layer to another, the permeability can be different. Permeability can vary even within the same layer.
  • the displacement fluid in particular water
  • it will preferentially penetrate in the layer having the less resistance to flow which is in general the layer having the highest permeability.
  • the zones of the reservoir having lower permeabilities remain un-swept leaving oil from these layers in the reservoir.
  • the presence of fractures or fracture networks or other structural anomalies in the rock matrix can also pose the same problem.
  • US4,773,481 and US4,683,949 describe the injection of crosslinked acrylamide- based polymer gels to decrease the permeability or plug the layer having the highest permeability or fractures.
  • the injection of such treatments is not selective because it can penetrate all the layers with different depth of penetration. Obviously, for layers with lower permeabilities, the depth of penetration is shorter than for the ones with higher permeabilities.
  • the gelation of treatment at the entrance of those layers will occur eventually and will block the subsequent injection of water.
  • the bull head injection of such treatment is risky because it is not selective. Operators can inject selectively those gel treatments through a coiled tubing that will target the zone of injection in the open interval. However, this requires a work over unit and a lot of operations that have a significant cost and will require long time and difficult deployment for the whole treatment.
  • US8,016,034 describes the injection of a pre-flush using a degradable product that will protect some layers from the further injection of another fluid. Once the principal treatment has been injected in the target zone, the access to the protected layer is restored where a second fluid can be injected. For this process, the liberation of the “protected” layer can be controlled by the injection of a fluid containing specific chemicals which add operations and chemicals to the whole treatment. Furthermore, this technology requires a specific product that is degradable under the action of chemicals, temperature or radiation, or which can be degraded with time in the reservoir. The operators cannot control this parameter and in case of problem, for example the pull-out of the injection pump, the treatment has to be performed once again because the product would have been degraded.
  • EP2288631 and US8263533 disclose methods for the treatment of rock formations comprising the injection into the formation of a microgel.
  • US2006/278390 discloses a method of diverting a treatment fluid in a formation comprising the injection into the formation of a crosslinkable polymer and a treatment fluid.
  • US2014/144628 discloses a method for increasing the recovery of hydrocarbon fluids in a formation comprising the injection into the formation of an expandable acrylamide-based polymeric microparticles.
  • the applicant has developed a novel method for improving conformance and/or sweep efficiency, in particular for reducing permeability in at least one relatively highly permeable zone of a subterranean formation also containing at least one relatively less permeable zone, said formation being penetrated by at least a well in fluid communication therewith, the method comprising first the injection of an aqueous composition comprising a specific microgel, and secondly the injection of an aqueous composition capable of generating a gel in situ in the subterranean formation.
  • the invention relates to a method for improving conformance in hydrocarbon- bearing heterogeneous subterranean formations and/or for improving flow profiles and sweep efficiencies of fluids injected in said formations and/or for diverting fluids injected in said formations, the method comprising the steps of:
  • a first aqueous composition comprising microgels obtained by dispersing in water (a) a self-invertible inverse latex or of a self-invertible inverse microlatex of a crosslinked polyelectrolyte, or (b) a powder obtained by drying and/or atomization of said self-invertible inverse latex or said self-invertible inverse microlatex, the crosslinked polyelectrolyte being obtained by copolymerization in the presence of a crosslinking agent of:
  • the anionic monomer is selected from the group consisting of (meth)acrylic acid, itaconic acid, crotonic acid, maleic acid, fumaric acid, 2-methyl-2- [(l-oxo-2-propenyl)amino]-l-propanesulfonic acid, vinylsulphonic acid, vinylphosphonic acid, allylsulphonic acid, allylphosphonic acid, styrene sulphonic acid and their salts of an alkali metal, an alkaline earth metal and ammonium, and mixtures of these monomers.
  • the proportion of the anionic monomer units in the crosslinked poly electrolyte is from 1 to 75 mol%, preferably from 5 to 40 mol%.
  • the neutral monomer is selected from the group consisting of: acrylamide; N,N-dimethylacrylamide; N-[2-hydroxy-l, l-bis(hydroxymethyl)- ethyl]propenamide; 2-hydroxy ethyl acrylate; N-vinylpyrrolidone; and mixtures thereof.
  • the proportion of neutral monomer units in the crosslinked poly electrolyte is from 10 to 90 mol % and preferably from 50 to 70 mol %.
  • the crosslinked polyelectrolyte is obtained by copolymerization with a further cationic monomer.
  • the proportion of cationic monomer units in the crosslinked polyelectrolyte is from 1 to 75 mol %, preferably from 1 to 30 mol %.
  • the microgels used in step (i) have a spherical shape and have an average size ranging from 0.05 to 10 pm, preferably from 0.1 to 8 pm, more preferably from 0.3 to 5 pm.
  • the first aqueous composition comprises an amount of microgels ranging from 500 to 10 000 ppm, preferably from 500 to 7000 ppm.
  • the second aqueous composition capable of generating a gel in the subterranean formation is a composition comprising at least one crosslinkable polymer and at least a crosslinking agent.
  • the crosslinkable polymer is an acrylamide- based polymer.
  • the average molecular weight of the crosslinkable polymer is from 10,000 to 50,000,000 g/mol' 1 and preferably from 100,000 to 20,000,000 g/mol' 1 , and most preferably from 200,000 to 15,000,000 g/mol' 1 .
  • the second aqueous composition capable of generating a gel in in the subterranean formation comprises an amount of the crosslinkable polymer ranging from 500 to 120 000 ppm, preferably from 1000 to 110000 ppm and an amount of crosslinking agent ranging from 500 to 15 000 ppm, preferably from 500 to 12000 ppm.
  • the viscosifying agent is an acrylamide-based polymer.
  • the steps i) and ii) and iii) of the method according to the invention are applied at most 21 days before any injection of a displacement fluid.
  • the term "consists essentially of followed by one or more characteristics, means that may be included in the process or the material of the invention, besides explicitly listed components or steps, components or steps that do not materially affect the properties and characteristics of the invention.
  • treatment relates to the injection of chemical formulations through at least an injection well in fluid communication with the formation to be treated.
  • injection wells are well known in the field of oil recovery and formation treatments and can be vertical, inclined or horizontal.
  • the present invention is intended to provide a novel method for improving conformance in hydrocarbon-bearing heterogeneous subterranean formations and for correspondingly improving flow profiles and sweep efficiencies of fluids injected in said formations, in particular displacement fluids such as water.
  • the method is also intended to divert displacement fluids, in particular water, in hydrocarbon-bearing heterogeneous subterranean formations.
  • the method is also intended to improve the oil displacement efficiency in a subterranean formation during an oil recovery process.
  • heterogeneous subterranean formation it is intended to mean a consolidated or non-consolidated geological subterranean formation (or reservoir) having heterogeneous permeabilities, i.e., wherein the permeability varies within a single layer or between two or more layers separated or not by an impermeable layer.
  • the variation in permeability within the formation can be vertical or horizontal and can be also due for example to the presence of fractures.
  • permeability it is intended to mean the ability of the subterranean formation/ the reservoir/ the rocks/ the layers to transmit fluids or to be penetrated by fluids.
  • displacement fluids it is intended to mean aqueous fluids such as water (e.g., fresh water, salt water, brines, etc.) or gas which are supplied to the reservoir from external sources in order to mobilize and produce/extract the remaining oil in the subterranean formation.
  • water e.g., fresh water, salt water, brines, etc.
  • gas which are supplied to the reservoir from external sources in order to mobilize and produce/extract the remaining oil in the subterranean formation.
  • the displacement fluid is water.
  • the objectives of the present invention are achieved by injecting into the subterranean formation, prior to the injection of a gelling system, an aqueous composition comprising microgels obtained by dispersing in water (a) a self-invertible inverse latex of a crosslinked polyelectrolyte or of a self-invertible inverse microlatex of a crosslinked polyelectrolyte, or (b) a powder obtained by drying and/or atomization of a self-invertible inverse latex of a crosslinked polyelectrolyte or of a self-invertible inverse microlatex of a crosslinked polyelectrolyte.
  • the method of the present invention comprises the steps of:
  • a first aqueous composition comprising microgels obtained by dispersing in water of a self-invertible inverse latex or of a self-invertible inverse microlatex of a crosslinked polyelectrolyte, or a powder obtained from the same, the crosslinked polyelectrolyte being obtained by copolymerization in the presence of a crosslinking agent of:
  • the term “dispersing in water” used herein is intended to mean adding and/or diluting the self-invertible inverse latex or the self-invertible inverse microlatex in water, or adding and/or mixing the powder obtained from said latex or microlatex in water.
  • the method according to the invention can be carried out by injecting the different compositions into the subterranean formation through at least a well in fluid communication therewith.
  • the third aqueous composition to be injected in step iii) of the method according to the invention is distinct from the injection of a displacement fluid to pressurize the reservoir and promote the production of oil.
  • the method according to the invention comprises a first step (i) of injecting into the subterranean formation an aqueous composition comprising microgels obtained by dispersing in water of a self-invertible inverse latex or of a self-invertible inverse microlatex of a crosslinked polyelectrolyte, obtained by copolymerization in the presence of a crosslinking agent of:
  • the microgels are obtained by dispersing in water a powder obtained by drying and/or atomization of the self-invertible inverse latex or the self-invertible inverse microlatex described above and in details here-under.
  • the self-invertible inverse latex or the self-invertible inverse microlatex described above can be dried and atomized beforehand before being mixed in water to form said microgels.
  • crosslinked polyelectrolyte denotes a nonlinear polymer in the form of a three-dimensional network and which can swell in water thus resulting in a chemical gel being obtained.
  • the self-invertible inverse latex or the self-invertible inverse microlatex comprises from 15 to 70% by weight, preferably from 15 to 60% by weight, more preferably from 25 to 40% by weight of said crosslinked polyelectrolyte.
  • microgels is intended to mean cross-linked polymer network of colloidal size that are swollen in the presence of a solvent, particularly water, and have an average size between 100 nm and several micrometers.
  • the anionic monomer may have acrylic, vinyl, maleic, fumaric and/or allylic functionalities and may contain a carboxyl group, a phosphonate group, and/or a sulphonate group.
  • the anionic monomer can also be an ammonium or alkaline earth metal or alkali metal salt of the above-mentioned monomers.
  • the anionic monomer is selected from the group consisting of acrylic acid, methacrylic acid, itaconic acid, crotonic acid, maleic acid, fumaric acid, 2- methyl-2-[(l-oxo-2-propenyl)amino]-l-propanesulfonic acid, vinylsulphonic acid, vinylphosphonic acid, allylsulphonic acid, allylphosphonic acid, styrene sulphonic acid and their salts of an alkali metal, an alkaline earth metal and ammonium, and mixtures of these monomers.
  • the anionic monomer is selected from partially or totally salified 2-methyl-2-[(l-oxo-2-propenyl)amino]-l -propanesulfonic acid and partially or totally salified (meth)acrylic acid.
  • partially salified or “totally salified” means that the corresponding monomer is respectively partially salified or completely salified in the form of an alkali metal salt, such as, for example, sodium salt or potassium salt, of an alkaline earth metal or of an ammonium salt.
  • the anionic monomer is partially or totally salified 2-methyl-2-[(l-oxo-2-propenyl)amino]-l-propanesulfonic acid (also known as 2-acrylamido-2-methylpropanesulfonic acid or AMPSTM).
  • the proportion of the anionic monomer units, in the crosslinked poly electrolyte is from 1 to 75 mol%, preferably from 5 to 40 mol%.
  • the neutral monomer is selected from the group consisting of acrylamide; N,N-dimethylacrylamide; N-[2-hydroxy-l, l-bis(hydroxymethyl)- ethyl]propenamide; 2-hydroxy ethyl acrylate; N-vinylpyrrolidone; and mixtures thereof.
  • the neutral monomer is acrylamide.
  • the proportion of the neutral monomer units in the crosslinked poly electrolyte is from 10 to 90 mol % and preferably from 50 to 70 mol %.
  • the molar ratio between the anionic monomer units and the neutral monomer units is from 5:95 to 95:5, preferably from 10:90 to 90: 10, more preferably from 20:80 to 80:20.
  • the crosslinked polyelectrolyte is a crosslinked copolymer of AMPS, partially or totally salified in the sodium salt form, and of acrylamide.
  • the crosslinked polyelectrolyte is obtained by copolymerization of:
  • the cationic monomer is selected from the group consisting of N,N,N-tetramethyl-2-[(l-oxo-2-propenyl)amino]propanammonium chloride; N,N,N- trimethyl-3-[(l-oxo-2-propenyl)amino]propanammonium chloride; diallyldimethylammonium chloride; N,N,N-trimethyl-2-[(l-oxo-2- propenyl)amino]ethanammonium chloride; N,N,N-trimethyl-2-[(l-oxo-2-methyl-2- propenyl)amino]ethanammonium chloride; N,N,N-trimethyl-3-[(l-oxo-2-methyl-2- propenyl)amino]propanammonium chloride; and mixtures thereof.
  • the cationic monomer is N,N,N-trimethyl 3-[(l-oxo 2-propenyl)
  • the proportion of cationic monomer unit in the crosslinked poly electrolyte can vary from 1 to 75 mol %, preferably from 1 to 30 mol %.
  • the crosslinking agent is chosen from compounds comprising at least two ethylenic bonds and very particularly from diallyloxyacetic acid or one of its salts and more particularly its sodium salt, triallylamine, diallylurea, trimethylolpropane triacrylate, ethylene glycol dimethacrylate, diethylene glycol diacrylate, methylenebis(acrylamide) or a mixture of several of these compounds.
  • the crosslinking agent is employed in the molar proportion, expressed with respect to the monomers used, of from 0.001 to 0.5% and preferably of from 0.005 to 0.25%.
  • the self-invertible inverse latex or self-invertible inverse microlatex described above comprises an emulsifying system comprising at least one surfactant of water-in-oil (W/O) type and at least one surfactant of oil-in-water (O/W) type.
  • W/O water-in-oil
  • O/W oil-in-water
  • the water-in-oil (W/O) type surfactant may be either a single surfactant or a mixture of surfactants provided that said mixture has a sufficiently low HLB value to induce water-in-oil emulsions.
  • the “HLB-value” is the capability of surfactants to stabilize water-in-oil-emulsions or oil-in-water emulsions and is usually a number from 0 to 20.
  • surfactants having a low HLB-value the lipophilic parts of the molecule predominate and consequently they are usually good water-in-oil emulsifiers.
  • surfactants having a high HLB-value the hydrophilic parts of the molecule predominate and consequently they are usually good oil-in-water emulsifiers.
  • the water-in-oil (W/O) type surfactant or mixtures thereof has an HLB-value of not more than 9, preferably not more than 8, and more preferably from 3 to 8.
  • water-in-oil surfactants include, not limitatively, sorbitan esters, in particular sorbitan monoesters with C12 to C18-groups such as sorbitan monolaurate, sorbitan monopalmitate, sorbitan monostearate, sorbitan monooleate but also sorbitan esters with more than one ester group such as sorbitan tristearate, sorbitan trioleate, ethoxylated fatty alcohols with 1 to 4 ethyleneoxy groups, e.g. polyoxyethylene (4) dodecylether ether, polyoxyethylene (2) hexadecyl ether or polyoxyethylene (2) oleyl ether, or mixtures thereof.
  • HLB values e.g. polyoxyethylene (4) dodecylether ether, polyoxyethylene (2) hexadecyl ether or polyoxyethylene (2) oleyl ether, or mixtures thereof.
  • oil-in-water (O/W) type surfactant are emulsifiers having an HLB value sufficiently high to provide oil-in-water emulsions, i.e., an HLB value more than 9, preferably more than 10.
  • oil-in-water surfactants include, not limitatively, ethoxylated sorbitan esters like for example polyethoxylated sorbitan oleate with 20 moles of ethylene oxide, polyethoxylated sorbitan laurate with 20 moles of ethylene oxide, castor oil poly ethoxylated with 40 moles of ethylene oxide, decaethoxylated oleodecyl alcohol, heptaethoxylated lauryl alcohol, decaethoxylated nonylphenol, polyethoxylated sorbitan hexaoleates, or mixtures thereof.
  • ethoxylated sorbitan esters like for example polyethoxylated sorbitan oleate with 20 moles of ethylene oxide, polyethoxylated sorbitan laurate with 20 moles of ethylene oxide, castor oil poly ethoxylated with 40 moles of ethylene oxide, decaethoxylated oleodec
  • the emulsifying system comprises from 20% to 50% of water-in-oil (W/O) type surfactant and from 80% to 50% of oil-in-water (O/W) type surfactants, percentages being expressed by weight with regards to the total weight of surfactants in the emulsifying system.
  • W/O water-in-oil
  • O/W oil-in-water
  • the self-invertible inverse latex or the self-invertible inverse microlatex comprises from 2 to 20%, preferably from 2 to 8% by weight of emulsifying system as described above.
  • the preparation of the self-invertible inverse latex or microlatex used in the method according to the invention can be carried out by radical polymerization in an inverse water-in-oil emulsion, i.e., wherein the continuous phase is oily, in presence of water-in-oil surfactants.
  • Oil-in-water surfactants as described above are added at the end of the polymerization step to modify and adjust the hydrophilic-lipophilic balance of the water-in-oil emulsion comprising the polyelectrolyte so as to obtain a mixture which, once mixed with water, will change the direction of emulsion from the water-in-oil form to the oil-in-water form, thus allowing the polyelectrolyte to be placed in contact with water.
  • the cross-linked polyelectrolyte polymer expands in water and forms microgels.
  • the self- invertible inverse latex or the self-invertible inverse microlatex or the powder obtained therefrom results after swelling in water in microgels which can be deformed, which are temperature stable, which are mechanically stable when subjected to high shear, and which are irreversibly adsorbed.
  • the microgels used in the method according to the invention are non-degradable polymer particles and cannot irreversibly degrade through hydrolysis of their chemical bonds.
  • the microgels have a spherical shape and have an average size ranging from 0.05 pm to 10 pm, preferably from 0.1 to 8 pm, more preferably from 0.3 to 5 pm.
  • the morphology of the microgels can be investigated for example by environmental scanning electron microscope.
  • microgels described above can be carried out according to techniques known to the skilled person and is described for example in patent US8680028 and in patent EP 1799960.
  • microgels used in the method according to the invention can also contain various additives such as complexing agents, transfer agents, or chain length limiting agents.
  • the first aqueous composition injected in step (i) comprises an amount of microgels as defined above ranging from 500 to 10 000 ppm, preferably from 500 to 7000 ppm. Lower concentrations can be used but are not generally very effective.
  • the first aqueous composition can optionally contain other ingredients such as salts, mineral acids, organic acids with low molecular weight, surfactants and wetting agents.
  • the water used as solvent in the first aqueous composition has a moderate salinity, generally comprising from 1% to 5% of TDS (Total Dissolved Salt).
  • the water may be production water, seawater, tap water, soft water (river water, running water) or mixtures thereof, or any other type of water having the desired salinity.
  • the applicant has found that the above-described microgels, due to their relatively large size, when injected in the subterranean formation, will spontaneously invade preferentially the zones of highest permeability, and will only to a very small extent spread into the zones of low permeability.
  • the first aqueous composition comprising microgels will protect the relatively low permeability layers from the invasion of the subsequent injection of gel treatment of step (ii) of the method according to the invention. It has been observed that the presence of a cationic monomer in the crosslinked poly electrolyte injected in the form of microgels in step i) of the described process improves the performance of the process.
  • the second aqueous composition capable of generating a gel in situ in the subterranean formation
  • the method according to the invention comprises a second treatment step (ii) of the subterranean formation using a second aqueous composition which is capable of generating a gel in the subterranean formation after the injection of said aqueous composition.
  • gel as used herein means a continuous three-dimensional crosslinked polymeric network containing water confined within the solid polymeric network. Gels used in the method according to the invention have sufficient structure so as not to propagate from the confines of a plugged volume into a less permeable zone of the formation.
  • the second aqueous composition capable of generating a gel in situ in the subterranean formation is also referred to as gelation composition, gelling system, or gel treatment as commonly used in the art.
  • the second aqueous composition may comprise one or more gelling systems having different final strengths and/or different compositions.
  • the second aqueous composition capable of generating a gel in situ in the subterranean formation is an aqueous composition comprising at least one crosslinkable polymer and at least a crosslinking agent.
  • the crosslinkable polymer is a carboxylate-based polymer.
  • a preferred carboxylate-based polymer is an acrylamide-based polymer.
  • the acrylamide-based polymers the most preferred are polyacrylamide (PA), partially hydrolyzed polyacrylamide (PHPA), copolymers of acrylamide and acrylate, carboxylate-containing terpolymers of acrylate, and copolymers of acrylamide and 2- acrylamido-2-methylpropanesulfonic acid.
  • polyacrylamide an acrylamide polymer having substantially less than 1% of the acrylamide groups in the form of carboxylate groups.
  • polyacrylamide an acrylamide polymer having at least 1% but not 100% of the acrylamide groups in the form of carboxylate groups is termed partially hydrolyzed polyacrylamide.
  • the degree of hydrolysis of the polyacrylamide polymer is from 0 to 60% and preferably from 0 to 30%.
  • the crosslinkable polymer is polyacrylamide.
  • the polyacrylamide has from about 0.1% to about 1% of its amide groups hydrolyzed.
  • the crosslinkable polymer is partially hydrolyzed polyacrylamide.
  • the partially hydrolyzed polyacrylamide has greater than 3% of its amide groups hydrolyzed.
  • the crosslinkable polymer is an acrylamide polymer containing 2-acrylamido-2-methylpropanesulfonic acid.
  • the acrylamide polymer has greater than 3% of 2-acrylamido-2-methylpropanesulfonic acid.
  • the average molecular weight of the acrylamide-based polymer is in the range of 10,000 to 50,000,000 g/rnol' 1 and preferably from 100,000 to 20,000,000 g/mol' 1 , and most preferably from 200,000 to 15,000,000 g/mol' 1 .
  • the crosslinking agent effects crosslinking between the carboxylate sites of the same or different polymer molecules.
  • the crosslinking agent used for the purpose of the invention can be organic or mineral.
  • a mineral crosslinking agent can be a molecule or complex containing a reactive transition metal cation.
  • a preferred crosslinking agent comprises a tri valent chromium cation complexed or bonded to an anion, oxygen or water.
  • Exemplary preferred crosslinking agents are chromic triacetate and chromic trichloride. Such crosslinking agents are described for example in US4,683,949.
  • Other examples of transition metal cations can be for example chromium VI within a redox system, aluminium III within aluminum citrate or aluminum trichloride, iron II, iron III, and zirconium IV.
  • organic crosslinking agent examples include but are not limited to polyamines, polyethyleneimine, polyphenols.
  • the crosslinking agent used in the method according to the invention is an organic crosslinking agent.
  • the second aqueous composition capable of generating a gel in the subterranean formation is an aqueous composition comprising an acrylamide polymer and/or an acrylamide polymer containing 2-acrylamido-2-methylpropanesulfonic acid and an organic crosslinking agent.
  • the second aqueous composition capable of generating a gel in the formation comprises an amount of the crosslinkable polymer as defined above ranging from 500 to 120 000 ppm, preferably from 1000 to 110000 ppm and an amount of crosslinking agent ranging from 500 to 15 000 ppm, preferably from 500 to 12000 ppm. Lower concentrations can be used but are not generally very effective.
  • the weight ratio of the crosslinkable polymer to the crosslinking agent is about 1 : 1 to about 500: 1, preferably about 2.5: 1 to about 100: 1, and most preferably about 5 : 1 to about 40: 1.
  • the gelation rate of the gel treatment injected in step (ii) of the method according to the invention is advantageously sufficiently slow to enable preparation of the gelation composition at the surface, injection of the composition as a uniform slug into the well bore, and displacement of the entire composition into the desired treatment zone of the subterranean formation.
  • the contact time required for the gel treatment according to the invention to efficiently react in the subterranean formation is quite short and can be considered to be completed within from 12 hours to 21 days preferably from 1 day to 7 days.
  • This gelation time depends on various parameters, such as the type of the formation and the temperature.
  • the person skilled in the art is able to determine the time it takes for the polymer to gel in the formation by using his general knowledge.
  • the person skilled in the art is also able to delay or accelerate the gelling time according to his wishes or to the constraints which he can meet on the field.
  • the second aqueous composition comprising the gel treatment has a viscosity ranging from 1.5 mPa.s to 3500 mPa.s at 7.34 s' 1 and at 25°C.
  • the aqueous solvent of the second composition as described above may be fresh water or a brine having a total dissolved solids concentration up to the solubility limit of the solids in water.
  • the aqueous solvent can be the same as used in the first aqueous composition.
  • Inert fillers such as crushed or naturally fine rock material or glass beads can also be added to the second aqueous composition to reinforce the gel network structure.
  • the method according to the invention further comprises a step (iii), immediately after step (ii), of injecting a third composition comprising water and optionally one or more viscosifying agents, in order to push the gel treatment injected in step ii) deeper into the subterranean formation.
  • the third aqueous composition comprises one or more viscosifying agent.
  • viscosifying agent include but are not limited to acrylamide-based polymers, xanthan gums, guar gums or mixtures thereof.
  • the viscosifying agent is an acrylamide- based polymer.
  • the acrylamide-based polymer has an average molecular weight ranging from 1,000,000 to 20,000,000 g.mol' 1 .
  • the third aqueous composition comprises an amount of viscosifying agent ranging from 500 to 20 000 ppm, preferably from 500 to 15000 ppm. Lower concentrations can be used but are not generally very effective.
  • the third aqueous composition optionally comprising the viscosifying agent has a viscosity ranging from 1.5 mPa.s to 3500 mPa.s at 7.34 s' 1 and at 25°C.
  • compositions can be introduced into the subterranean formation at the desired pressure, provided that said pressure is not above the fracturing pressure.
  • the method for improving conformance and/or fluid profiles according to the invention consists essentially in steps (i) and (ii) as described above.
  • the method for improving conformance and/or fluid profiles according to the invention consists essentially in steps (i), (ii) and (iii) as described above.
  • the steps i) and ii), and iii), of the method according to the invention are applied at most 21 days, preferably at most 7 days, and more preferably at most 1 day, before any injection of a displacement fluid. This depends in particular on the time needed for the gelation of the second composition injected in step ii).
  • the inventive method described herein selectively reduces the permeability of at least one relatively highly permeable zone of a subterranean formation to improve conformance and flow profiles of fluids injected into the subterranean formation.
  • the method according to the present invention can be preceded by an optional pre-treatment step which can be carried out, for example, with an aqueous solution containing a surfactant, in order to clean the formation to be treated.
  • an optional pre-treatment step which can be carried out, for example, with an aqueous solution containing a surfactant, in order to clean the formation to be treated.
  • the method of the present invention can also be followed by a final step of injecting a displacement fluid, such as water, brine or gas in the formation, in order to invade the un-swept low permeability layers.
  • a displacement fluid such as water, brine or gas in the formation
  • the method of the invention has many advantages, and notably requires limited operations.
  • the treatments used in the invention are compatible with the anionic polymers used for example for Enhanced Oil Recovery and are compatible with surfactants used for example in Alkali Surfactant Polymer flooding.
  • the method according to the invention has the advantage of being applicable over wide temperature ranges.
  • it can be carried out in a formation the temperature of which is between 0°C and 200°C.
  • Figure 1 represents the connection between a well-bore (1) drilled in a subterranean formation and in contact, through perforations (2), with two layers of different permeabilities, layer (3) having a lower permeability than layer (4).
  • Figure 2 illustrates the invasion of all the layers of the subterranean formation of figure 1 when a prior art gel treatment is performed bull heading (5).
  • the treatment invades both layers having different permeabilities.
  • Figures 3 to 6 illustrate the mechanism of the method according to the present invention to avoid the gel treatment to invade the low permeability layer in a subterranean formation corresponding to the formation represented in figure 1.
  • Figure 3 represents the injection of the first aqueous composition comprising the microgel (6) that will invade mainly the high permeability layer (4) leaving a skin at the entrance of the low permeability layer (3).
  • Figure 4 illustrates the subsequent injection of the second aqueous composition comprising the gelling treatment (7).
  • Figure 5 illustrates the injection of the third aqueous composition (8), that can optionally comprise a viscosifying agent, that is intended to push the gel treatment (7) deeper into the subterranean formation.
  • Figure d shows the subsequent injection of a displacement fluid (9) (after treatment of the formation with the method according to the invention) that will only invade the low permeability layer (3) through the skin of microgel (6).

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  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Addition Polymer Or Copolymer, Post-Treatments, Or Chemical Modifications (AREA)

Abstract

L'invention concerne un procédé pour dévier un écoulement d'eau dans une formation souterraine, ledit procédé comprenant l'injection d'une première composition comprenant des microgels et de l'eau, une deuxième composition qui peut générer un gel dans la formation souterraine et comprenant au moins un polymère, un agent de réticulation et de l'eau, et une troisième composition comprenant de l'eau et éventuellement un ou plusieurs améliorants de viscosité.
PCT/EP2023/078784 2022-10-18 2023-10-17 Procédé de traitement de formations souterraines WO2024083796A1 (fr)

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EP22306575.6 2022-10-18

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Citations (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3973629A (en) * 1972-11-06 1976-08-10 Knight Bruce L Injection profiles with radiation induced copolymers
US4683949A (en) 1985-12-10 1987-08-04 Marathon Oil Company Conformance improvement in a subterranean hydrocarbon-bearing formation using a polymer gel
US4773481A (en) 1987-06-01 1988-09-27 Conoco Inc. Reducing permeability of highly permeable zones in underground formations
US20060278390A1 (en) 2005-06-14 2006-12-14 Halliburton Energy Services, Inc. Crosslinkable polymer compositions and associated methods
EP1799960A2 (fr) 2004-08-25 2007-06-27 Institut Français du Pétrole Methode de traitement de formations ou de cavites souterraines par des microgels
EP2288631A1 (fr) 2008-06-10 2011-03-02 Société d'Exploitation de Produits pour les Industries Chimiques SEPPIC Nouveau procede de traitement des formations rocheuses et nouveaux polyampholytes
US8016034B2 (en) 2009-09-01 2011-09-13 Halliburton Energy Services, Inc. Methods of fluid placement and diversion in subterranean formations
US20140144628A1 (en) 2012-11-26 2014-05-29 University Of Kansas Crosslinking of swellable polymer with pei
US10287485B2 (en) * 2016-01-19 2019-05-14 Saudi Arabian Oil Company Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs

Patent Citations (12)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3973629A (en) * 1972-11-06 1976-08-10 Knight Bruce L Injection profiles with radiation induced copolymers
US4683949A (en) 1985-12-10 1987-08-04 Marathon Oil Company Conformance improvement in a subterranean hydrocarbon-bearing formation using a polymer gel
US4773481A (en) 1987-06-01 1988-09-27 Conoco Inc. Reducing permeability of highly permeable zones in underground formations
EP1799960A2 (fr) 2004-08-25 2007-06-27 Institut Français du Pétrole Methode de traitement de formations ou de cavites souterraines par des microgels
US8263533B2 (en) 2004-08-25 2012-09-11 Ifp Method of treating underground formations or cavities by microgels
US20060278390A1 (en) 2005-06-14 2006-12-14 Halliburton Energy Services, Inc. Crosslinkable polymer compositions and associated methods
EP2288631A1 (fr) 2008-06-10 2011-03-02 Société d'Exploitation de Produits pour les Industries Chimiques SEPPIC Nouveau procede de traitement des formations rocheuses et nouveaux polyampholytes
US8680028B2 (en) 2008-06-10 2014-03-25 Societe D'exploitation De Produits Pour Les Industries Chimiques Seppic Method for the treatment of rock formations and novel polyampholytes
EP2288631B1 (fr) * 2008-06-10 2017-10-25 Poweltec Procede de traitement des formations rocheuses et polyampholytes
US8016034B2 (en) 2009-09-01 2011-09-13 Halliburton Energy Services, Inc. Methods of fluid placement and diversion in subterranean formations
US20140144628A1 (en) 2012-11-26 2014-05-29 University Of Kansas Crosslinking of swellable polymer with pei
US10287485B2 (en) * 2016-01-19 2019-05-14 Saudi Arabian Oil Company Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs

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