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    • 专利摘要:
    METHOD OF INHIBITING OR CONTROLLING WELL TREATMENT AGENT RELEASE. The present invention relates to a microemulsion delivery system containing a well treatment agent in a water-in-oil microemulsion that can be used for the remediation of wells, as well as in other treatment operations, including stimulation, acidification and drilling. In addition, the water-in-oil microemulsion dispensing system can be used to clean surface equipment and downhole equipment.
    公开号:BR112013031449B1
    申请号:R112013031449-4
    申请日:2012-05-16
    公开日:2021-05-04
    发明作者:Kay Cawiezel；D.V. Satyanarayana Gupta
    申请人:Baker Hughes Incorporated；
    IPC主号:
    专利说明:

    REPORT Field of Invention
    [001] The invention relates to a method of inhibiting or controlling the rate of release of a well treatment agent in an underground formation, an oil well, a gas well, a geothermal well, an outflow conduit or container by introducing into the formation, well, outflow conduit or container a microemulsion containing the well treatment agent. Background of the Invention
    [002] In the treatment of oil, gas and geothermal wells and/or underground formations penetrated by wells, it is important that the well treatment agents are distributed in defined target areas. Well fluids are typically complex mixtures of aliphatic hydrocarbons, aromatics, heteroatomic molecules, anionic and cationic salts, acids, sands, silts, clays and a wide variety of other components. The nature of these fluids, combined with the severe conditions of heat, pressure and turbulence to which they are often subjected, are contributing factors to the formation and deposition of contaminants such as scale, salts, paraffins, corrosion, bacteria and asphaltenes in production wells.
    [003] A common site for the formation and deposition of these contaminants in oil or gas wells is the annular space between the production piping and the casing. The annulus can be a static area or it can produce gas or liquid. The formation and deposition of these contaminants can reduce well productivity. Also, the presence of contaminants such as scale on the annulus can make it difficult or impossible to remove the tubing for maintenance.
    [004] In addition, these contaminants form in other equipment and flow conduits used in the production of oil, gas and other fluids. Acute problems result when these contaminants develop in equipment and flow conduits used in oil and gas production, refineries and other fluid processing facilities.
    [005] Well treatment agents are known in the art for the inhibition or control of these unwanted contaminants. In some cases, it is necessary for well treatment agents to be distributed in their target area over an extended period of time. For example, it is typically desirable that well treatment agents that inhibit the formation or deposition of contaminants, such as scale, salts, paraffins, corrosion, bacteria and asphaltenes, be slowly distributed in production wells, underground formations, equipment and outflow conduits used in gas production and oil production. The formation and deposition of these unwanted contaminants decrease formation permeability and reduce well productivity and can completely block the well tube in severe cases.
    [006] U.S. Patent No. 7,491,682 and U.S. Patent No. 7,493,955, both incorporated herein by reference, disclose the use of composites for the slow release of well treatment agents. U.S. Patent No. 7,475,730 and U.S. Patent Publication No. 20090114247, both also incorporated herein by reference, also disclose a method of inhibiting and/or removing undesirable contaminants from wells, drains and containers. with a foam treatment composition.
    [007] In well service operations such as drilling operations, hydraulic fracturing operations and shutdown operations, it is often important that the activity of the well treatment agent is delayed for some time after it has been introduced into the well and/ or formation of underground production. For example, in hydraulic fracturing, the viscosity of the fracturing fluid is typically decreased after placing propants into the fracture so that the fluid can flow naturally from the formation. Although breaking agents are typically incorporated into the fracturing fluid, their activity is most desirably delayed until the proppant is placed in the fracture. In addition, it is often desirable to delay crosslinking in a fracturing fluid until the fluid has traveled a designated distance within the well and/or through the formation. At this point, gelling of the fluid is desired.
    [008] Breaking agents are also used to break up filter cakes that form during downhole operations. For example, breaking agents are often included in drilling fluid to comminute filter cakes. However, it is desirable that the breaking agent is not functional until fragmentation of the filter cake is required.
    [009] Although composites have been successful in the slow release of well treatment agents in drilling, stimulation and closure operations, methods are sought to improve the slow or delayed release of well treatment agents, particularly well treatment agents. liquid wells, as well as improved methods for delivering these treatment agents to wells, formations, conduits and/or containers. In particular, alternatives are sought for the delivery of well treatment agents to target areas so that the well treatment agent can be slowly released, and the activity of the treatment agent can be delayed. Invention Summary
    [0010] A microemulsion with an incorporated well treating agent ensures the slow and controlled release of a well treating agent into a well, underground formation penetrated by a well, drainpipe or container. The release of the well treating agent into the well, formation, flow conduit or container can be delayed until such time as the effect generated by the well treating agent is required.
    [0011] Thus, in one embodiment, a well treatment agent can be slowly and continuously released into a target area in a gas well, oil well or geothermal well over an extended period of time when incorporated into an emulsion.
    [0012] In another embodiment, the well treatment agent may be slowly and continuously released into a target area of an underground formation over an extended period of time when incorporated into a microemulsion.
    [0013] In another embodiment, the well treatment agent may be slowly and continuously released into a target area of a flow conduit or container over an extended period of time when incorporated into a microemulsion.
    [0014] In another embodiment, the microemulsion into which the well treatment agent is incorporated may be a solvent-surfactant mixture added to an aqueous diluent. The solvent-surfactant mixture may optionally contain an alcohol.
    [0015] Exemplary solvents include terpenes, exemplary surfactants include those with a hydrophilic-lipophilic balance (HLB) between about 3 and about 8, and exemplary diluents include water as well as mixtures of water and triethylene glycol.
    [0016] The oily phase of the microemulsion can be diesel, kerosene, crude oil, a linear α-olefin, poly-α-olefin or other synthetic oils.
    [0017] The well treatment agent may include enzymatic breaking agents, oxidative breaking agents, breaking agent catalysts, crosslinkers, buffers, paraffin inhibitors, asphaltene inhibitors, scale inhibitors, pH adjusting agents, oxidants , crosslinking agents, crosslinking retarding agents, demulsifying agents, acids and esters. Brief Description of Drawings
    [0018] In order to more fully understand the drawings mentioned in the detailed description of the present invention, a brief description of each drawing is presented, in which:
    [0019] FIG. 1 compares the apparent viscosity at 24°C (75°F) of a linear gel with 6% by volume of enzyme incorporated in a water-in-oil microemulsion versus a linear gel with 6% by volume of enzyme in an aqueous fluid .
    [0020] FIG. 2 compares the apparent viscosity at 24°C (75°F) of a linear gel with 8% by volume of enzyme incorporated in a water-in-oil microemulsion versus a linear gel with 8% by volume of enzyme in an aqueous fluid .
    [0021] FIG. 3 compares the apparent viscosity at 51.6°C (125°F) of a linear gel with 6% by volume of enzyme incorporated in a water-in-oil microemulsion versus a linear gel with 6% by volume of enzyme in one aqueous fluid.
    [0022] FIG. 4 compares the apparent viscosity at 51.6°C (125°F) of a linear gel with 8% by volume of enzyme incorporated in a water-in-oil microemulsion versus a linear gel with 8% by volume of enzyme in one. aqueous fluid.
    [0023] FIG. 5 compares the apparent viscosity at 65.5°C (150°F) of a linear gel with 6% by volume of enzyme incorporated in a water-in-oil microemulsion versus a linear gel with 6% by volume of enzyme in one aqueous fluid.
    [0024] FIG. 6 compares the apparent viscosity at 65.5°C (150°F) of a linear gel with 8% by volume of enzyme incorporated in a water-in-oil microemulsion versus a linear gel with 8% by volume of enzyme in a aqueous fluid. Detailed Description of Preferred Modalities
    [0025] A well treatment agent can remain inactive in a well, underground formation penetrated by a well, as well as flow conduits and containers used in the production of oil and/or gas, as well as refineries, by incorporating the treatment agent well in a microemulsion. Delayed release of the microemulsion well treating agent at a generally constant rate can be prolonged over a period of time, in some cases exceeding three years. Typically, the well treating agent is released from the microemulsion by increased temperatures and changes in the solubility of the well treating agent with time.
    [0026] Well treatment microemulsions are thermally stable and can be formed by combining solvent-surfactant mixtures with an oil-based fluid. The oil phase forms the continuous or discontinuous phase of the microemulsion. The microemulsion can be thought of as a small scale version of emulsions, i.e. oil-in-water or water-in-oil droplet type dispersions with average particle size ranges of the order of about 5 to about 50 nm in radius of droplet. In emulsions, the average droplet size continuously grows with time, so that finally phase separation occurs. Emulsion droplets are usually large (>0.1 microns) and often exhibit a milky or cloudy appearance rather than translucent as seen in microemulsions.
    Exemplary microemulsions include those disclosed in U.S. Patent No. 5,603,942 and U.S. Patent Publication No. 20080287324, both of which are incorporated herein by reference.
    [0028] The particle size of the well treating agent in the microemulsion is typically between about 0.001 microns and about 100 microns. In some cases, the particle size of the well treatment agent is less than or equal to 0.05 microns.
    The water-in-oil microemulsion may be a solvent-surfactant mixture added to an aqueous diluent. The solvent-surfactant mixture may optionally contain an alcohol. The solvent-surfactant mixture can include from about 35 to about 80% by volume of surfactant, from about 14% to about 54% by volume of solvent and from 0 to about 20% by volume of alcohol. The amount of water in the water-in-oil microemulsion is typically at most 50 percent by volume, preferably at most about 30 percent by volume. The amount of hydrocarbon in the oil-in-water microemulsion is typically at most 50 percent by volume, preferably at most about 30 percent by volume.
    [0030] In one embodiment, the solvent is selected from the group of unsaturated aliphatic cyclic hydrocarbons known as terpenes, including monoterpenes and diterpenes. In a preferred embodiment, the solvent is monoterpene d-limonene (C10H16). The terpene-based solvent can also be partially or completely replaced by alkyl, cyclic or aryl acid esters of short-chain alcohols such as ethyl lactate and hexyl ester.
    [0031] The surfactant of the solvent-surfactant blend is one that is capable of creating a water-in-oil microemulsion by combining with oil. The surfactant can be cationic, anionic, zwitterionic or non-ionic. Preferred surfactants are biodegradable and have an HLB value between about 3 and 8. Exemplary water-in-oil surfactants include Span® 40 (sorbitan monopalmitate), Span® 60 (sorbitan monostearate), Span® 80 (sorbitan monooleate). sorbitan), linear alcohol alkoxylates, ethoxylated castor oil and polyethylene glycol. A preferred water-in-oil surfactant blend includes sorbitan monopalmitate, ethoxylated castor oil and polyethylene glycol.
    [0032] The alcohol component of the solvent-surfactant mixture, when present, can serve as a coupling agent between the solvent and the surfactant and can aid in the stabilization of the microemulsion, as well as in reducing the freezing point of the microemulsion. Although isopropanol is currently preferred, alternative suitable alcohols include middle range primary, secondary and tertiary alcohols with between 1 and 20 carbon atoms, such as t-butanol, n-butanol, n-pentanol, n-hexanol and 2-ethyl- hexanol.
    [0033] Other freeze prevention additives can be added or alternatively added, such as detergent range alcohol ethoxylates, ethylene glycols (EG), polyethylene glycols (PEG), propylene glycols (PG) and triethylene glycols (TEG).
    [0034] The solvent-surfactant mixture may also optionally include a salt for stability and co-solvent replacement. Salts of K, Na, Mg, Zn, Br, Sr, Cs, Li and Ca are suitable as, for example, NaCl, KCl, CaCl2 and MgCl2 are currently preferred.
    [0035] A diluent is also added to the mixture containing the solvent, surfactant and alcohol before adding the oil. Exemplary diluents include water and mixtures of water and triethylene glycol (TEG), such as one containing about 90% by volume of water and 10% by volume of triethylene glycol. With the addition of the diluent, the solvent-surfactant mixture may partially or completely emulsify.
    [0036] Exemplary solvent-surfactant mixtures are those containing about 56% by volume of a surfactant mixture of sorbitan monopalmitate, ethoxylated castor oil and polyethylene glycol, about 34% by volume of d-limonene and/or lactate ethyl and about 10% by volume of isopropanol.
    [0037] The oily phase of the microemulsion is preferably diesel, kerosene, crude oil, condensate, an ester, linear α-olefin, poly-α-olefin, internal olefin, paraffin, linear alkyl benzene, ester, acetal or others synthetic oils. In a preferred embodiment, diesel or condensate is used as a diluent.
    The well treatment microemulsion typically includes from about 0.5% to about 98% of the solvent-surfactant mixture.
    To the base water-in-oil microemulsion, a water-based well treatment chemical is added with minimal mixing when the well treatment chemical preferably enters the aqueous phase of the microemulsion. Similarly, to an oil-in-water base microemulsion, a hydrocarbon-based well treatment chemical can be added with minimal mixing when the well treatment chemical enters the hydrocarbon phase of the microemulsion.
    [0040] The well treatment agent is added to the microemulsion before its introduction into the well. The amount of well treating agent in the microemulsion usually is from about 2 to 20 percent by weight, preferably from about 3 to about 12 percent by weight, more preferably from about 4 to about 8 percent. by weight.
    [0041] The well treatment agent may include enzymatic breaking agents (including encapsulated enzymatic breaking agents), oxidative breaking agents (including encapsulated oxidative breaking agents), breaking agent catalysts, crosslinking agents, demulsifying agents, crosslinking retarding agents, paraffin inhibitors, asphaltene inhibitors, scale inhibitors, corrosion inhibitors, scale inhibitors, gas hydrate inhibitors, pH adjusting agents, oxidizers, foaming agents, oxygen scavengers, biocides , emulsifiers (both water-in-oil and oil-in-water) and surfactants, as well as other agents where slow release into the well, underground formation, drainpipe or vessel is desired.
    [0042] When the well treating agent is used to inhibit or control the formation of deposits or undesirable contaminants, the well treating agent is preferably at least one member selected from the group consisting of demulsifying agents (both of water-in-oil, and oil-in-water), corrosion inhibitors, scale inhibitors, paraffin inhibitors, gas hydrate inhibitors, salt formation inhibitors and asphaltene dispersants.
    [0043] As the aqueous phase containing the well treating agent is emulsified in the oil phase of the microemulsion and as the microemulsion is thermally stable, only a small amount of well treating agent is released onto the desired area or surface.
    [0044] The well treatment agent is preferably a liquid material. If the well treatment agent is a solid, it can be dissolved in a suitable solvent, thus making it a liquid.
    [0045] Microemulsions can be introduced into the well opening, flow conduits, containers or surface equipment as a component of a treatment fluid or vehicle to facilitate placement of the microemulsion in a desired location within the formation. In this regard, any well treatment fluid suitable for transporting the microemulsion can be used. Typically, the microemulsion containing the well treatment agent is introduced into the vehicle fluid on the fly and injected into the wellbore.
    [0046] Well treatment fluids containing the microemulsion can be gelled or ungelled. In one embodiment, the microemulsion can be introduced or pumped into a well as neutrally buoyant particles, for example, in a fluid of saturated sodium chloride solution or a fluid that is any other closure or working brine known in the art.
    The well treatment fluid can be a brine (such as a saturated potassium chloride or sodium chloride solution), salt water, fresh water, a hydrocarbon liquid, or a gas such as nitrogen or carbon dioxide.
    [0048] The amount of microemulsion in the treatment fluid is typically between about 15 ppm and about 100,000 ppm.
    [0049] The microemulsion can be used to remove deposited contaminants that form in drainpipes or containers. For example, during oil and gas production from wells, it is not uncommon for scale, rust, salts, paraffins, and asphaltenes to deposit on the surfaces of flow conduits or containers. The treating agent in the microemulsion can be used to inhibit the deposition of these materials and/or remove these deposits after their formation.
    [0050] The microemulsion also has applicability in inhibiting and/or removing contaminants from flow conduits and containers used in refineries and fluid processing facilities. Thus, in addition to being used in the treatment of oil and gas wells, the microemulsion finds applicability in the refinery and chemical industries.
    [0051] The microemulsion therefore has applicability in the treatment of flowpipes, including pipelines and flowlines, as well as transmission and processing piping, including piping used to connect containers in chemical treatment facilities as well as refineries.
    [0052] A fluid containing the microemulsion can also be introduced into the well opening to inhibit or control the formation of unwanted contaminants in tubular surface equipment within the well, as well as equipment at a refinery or chemical processing site.
    [0053] Microemulsions can be effective in removing contaminants on metallic as well as non-metallic surfaces. In a preferred embodiment, the treated compositions are used to remove contaminants on metallic surfaces such as high alloy steels, including chromium steels, duplex steels, stainless steels, martensitic alloy steels, ferritic alloy steels, austenitic alloy steels, stainless steels precipitation hardened and high nickel steels.
    [0054] In addition, microemulsions can be used in well treatment fluids such as fracturing fluids, closure fluids, acidifying fluids, drilling fluids and others. For example, when used to inhibit or control the formation of unwanted contaminants or when used to delay the release of contaminants into the well, the microemulsion can be introduced into the well opening as a component of a closure fluid.
    [0055] In a preferred embodiment, the water-in-oil microemulsions effectively inhibit, control, remove or prevent the formation of inorganic scales that settle in oil wells, gas wells, water wells, geothermal wells and underground formations penetrated by a well. Water-in-oil microemulsions are particularly effective in treating calcium, barium, magnesium and other salt scales, including barium sulphate, calcium sulphate and calcium carbonate scales. Water-in-oil microemulsions may also have applicability in the treatment of other inorganic scales, such as zinc sulfide, iron sulfide and others.
    [0056] Suitable scale inhibitors are anionic scale inhibitors. Preferred scale inhibitors include strong acidic materials such as a phosphonic acid, a phosphoric acid or a phosphorous acid, phosphate esters, phosphonate/phosphonic acids, the various amino polycarboxylic acids, chelating agents and polymeric inhibitors and their salts. Organophosphonates, organophosphates and phosphate esters are included, as well as their corresponding acids and salts. Phosphonate/phosphonic acid-type scab inhibitors are often preferred in light of their effectiveness in controlling scabs at a relatively low concentration. Polymeric scale inhibitors such as polyacrylamides, salts of acrylamido-methyl propane/acrylic acid sulfonate copolymer (AMPS/AA), phosphined maleic copolymer (PHOS/MA) or the sodium salt of polymaleic acid/acrylic acid/sulfate terpolymers acrylamido-methyl propane (PMA/AMPS) are also effective scale inhibitors. Sodium salts are preferred. Chelating agents are also useful, including diethylenetriaminepentamethylene phosphonic acid and ethylenediaminetetraacetic acid.
    The well treatment agent may also be any of the fructans or fructan derivatives such as inulin and inulin derivatives as set forth in U.S. Patent Publication No. 2009/0325825, incorporated herein by reference.
    [0058] Exemplary demulsifying agents that are useful include, but are not limited to, condensation polymers of alkylene oxides and glycols, such as condensation polymers of ethylene oxide and propylene oxide and dipropylene glycol, as well as trimethylol propane; and alkyl substituted phenol formaldehyde resins, bisphenyl diepoxides and esters and diesters of these difunctional products. Particularly preferred as nonionic demulsifiers are oxyalkylated phenol formaldehyde resins, oxyalkylated amines and polyamines, oxyalkylated diepoxidized polyethers and the like. Suitable oil-in-water demulsifiers include polytriethanolamine methyl chloride quaternary, melamine acid colloid, aminomethylated polyacrylamide and others.
    [0059] Hydrocarbon soluble paraffin inhibitors can include ethylene/vinyl acetate copolymers, acrylates (such as polyacrylate esters and methacrylate esters of fatty alcohols) and olefin/maleic esters.
    Exemplary corrosion inhibitors include fatty imidazolines, alkyl pyridines, alkyl pyridine quaternaries, fatty amine quaternaries and phosphate salts of fatty imidazolines.
    [0061] Chemical treatment substances or gas hydrate inhibitors may include polymers and homopolymers and copolymers of vinyl pyrrolidone, vinyl caprolactam and amine-based hydrate inhibitors, such as those disclosed in US patent publications No. 2006/0223713 and 2009/0325823, both of which are incorporated herein by reference.
    [0062] Exemplary asphaltene treatment chemicals include fatty ester homopolymers and copolymers (such as fatty esters of acrylic and methacrylic acid polymers and copolymers) and sorbitan monooleate.
    [0063] Suitable foaming agents include oxyalkylated sulfates or ethoxylated alcohol sulfates, or mixtures thereof.
    [0064] Exemplary surfactants include cationic, amphoteric, anionic and non-ionic surfactants. Included as cationic surfactants are those containing a quaternary ammonium moiety (such as a linear quaternary amine, a benzyl quaternary amine or a quaternary ammonium halide), a quaternary sulfonium moiety or a quaternary phosphonium moiety or mixtures thereof. Suitable surfactants containing a quaternary group include quaternary ammonium halide or quaternary amine such as quaternary ammonium chloride or a quaternary ammonium bromide. Amphoteric surfactants include glycinates, amphoacetates, propionates, betaines and their mixtures. The cationic or amphoteric surfactant can have a hydrophobic tail (which can be saturated or unsaturated) with a carbon chain length of C12 - C18. In addition, the hydrophobic tail can be obtained from a natural plant oil, such as one or more of coconut oil, rapeseed oil and palm oil.
    [0065] Preferred surfactants include N,N,N-trimethyl-1-octadecaammonium chloride, N,N,N-trimethyl-1-hexadecaammonium chloride and N,N,N-trimethyl-1-sojaammonium chloride and mixtures thereof . Suitable anionic surfactants are sulfonates (such as sodium xylene sulfonate and sodium naphthalene sulfonate), phosphonates, ethoxysulfates and mixtures thereof.
    [0066] Exemplary oxygen scavengers include triazines, maleimides, formaldehydes, amines, carboxamides, alkylcarboxyl-azo compounds, cumine-peroxide compounds, morpholino and amino derivatives and morpholine and piperazine derivatives, amine oxides, alkanolamines, aliphatic and aromatic polyamines .
    [0067] The microemulsions of the invention do not require excessive amounts of well treatment agents. When used to delay or control the release over an extended period of time of a well treating agent usable in removing, inhibiting or controlling unwanted contaminants, the amount of well treating agent in microemulsions can be as low as 1 ppm. Generally, the amount of well treating agent in the microemulsion is from about 0.05 to about 5 (preferably from about 0.1 to about 2) percent by weight based on the total weight of the microemulsion.
    [0068] When placed in a well, the well treating agent slowly demulsifies the microemulsion at a generally constant rate over an extended period of time in the water or hydrocarbons that are contained in the formation, well, flue or vessel. The microemulsion therefore allows for a continuous supply of the well treatment agent in the target area. Generally, the shelf life of a single treatment using the microemulsion with an incorporated well treating agent for the removal of unwanted contaminants is between six and twelve months and can exceed 3 years.
    [0069] In well remediation applications, the selected well treatment microemulsion is preferably injected directly into the well opening through the production pipeline or by use of coil tubing or similar distribution mechanisms. Once it has descended into the well, the well treatment microemulsion remediates drilling damage, fracturing fluid damage, water blockages and removes fines, asphaltenes and paraffins from the formation and the well. The well treatment microemulsion also serves to thin heavy hydrocarbons, alleviate water blockages and reduce pore pressure in the formation.
    [0070] An additional amount of fluid containing the well treating agent may be introduced into the well or formation at any time after the initial charge of well treating agent in the microemulsion has been at least partially depleted. Typically, the additional well treating agent is introduced when the well treating agent has been substantially depelled, and the performance level of the well treating agent in the microemulsion has become unacceptable.
    [0071] Microemulsion can also be used in stimulating fluids, including acidifying fluids, fracturing fluids and fluids used in sand control. For example, the microemulsion well treating agent can be a crosslinking agent, crosslinking retarding agent or pH control additive, which can be released when its activity is desired inside the well. For example, as some stimulation fluids are highly viscous, it is sometimes desirable to delay crosslinking until the treatment fluid reaches a target destination. In such cases, it is desirable to include the crosslinking agent (or crosslinking retarding agent) as a component of the water-in-oil microemulsion.
    [0072] Suitable crosslinking agents include a borate ion releasing compound, a metal ion in an organometallic or organic complex comprising at least one transition metal or alkaline earth metal, as well as mixtures thereof. Specific crosslinking agents include borate ion releasing compounds, eg boric acid, alkali metal borates such as sodium diborate, potassium tetraborate, sodium tetraborate (borax), pentaborates and others, and alkali metal and zinc borates , metal compounds in organometallic and organic complexes, such as those containing zirconium IV ions such as, for example, zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate and zirconium lactate diisopropylamine, titanium IV ions such as, for example, titanium ammonium lactate, titanium triethanolamine and titanium acetylacetonate.
    Suitable crosslinking retarding agents may include organic polyols such as sodium gluconate, sodium glucoeptonate, sorbitol, mannitol, phosphonates, bicarbonate salt, salts, various weak inorganic and organic acids, including aminocarboxylic acids and their salts (EDTA, DTPA and others) and citric acid and mixtures thereof.
    [0074] In a particularly preferred embodiment, the well treatment agent is a disrupting agent that is capable of reducing the viscosity of a gelled fluid. For example, after a fracturing fluid is formed and pumped into an underground formation, it is often desirable to convert the highly viscous gel into a lower viscosity fluid. This allows the fluid to be easily and effectively removed from the formation, allowing the desired material, such as oil or gas, to flow into the well. A water-in-oil microemulsion containing a disrupting agent as well as a treating agent is useful for the slow release of the disrupting agent upon termination of stimulation. Likewise, an oil-in-water microemulsion containing a hydrocarbon-based breaking agent as well as a well treating agent is useful for the slow release of the breaking agent into the viscoelastic surfactant-based fluid with the termination of stimulation. Timing the release of the well treatment agent is important because if the chemical activity of the breaking agent is released too quickly, the viscous fluid will break up and not perform the necessary function. If chemical activity is released too slowly or not fully, the fluid will be too viscous, and the flow of oil or gas from the formation will be reduced.
    [0075] Typically, the breaking agent is an oxidative breaking agent or an enzymatic breaking agent, including encapsulated oxidative breaking agents and encapsulated enzymatic breaking agents.
    [0076] Examples of oxidative breaking agents include persulfates (such as alkaline earth metal and ammonium persulfates), percarbonates (such as alkaline earth metal percarbonates), perborates (such as alkaline earth metal perborates), peroxides (such as peroxides alkaline earth metals and zinc salts of peroxides), perphosphates, permanganates and others. Furthermore, materials such as esters, which are capable of assisting the breaking agent in the degradation of the viscous fluid, can also be used in the microemulsion. Suitable esters include phenyl esters, alkyl phenyl esters, C 1 -C 11 alkyl esters, substituted C 1 -C 11 alkyl esters, substituted phenyl esters and also include diesters, triesters and others.
    [0077] Examples of enzymatic disrupting agents are specific enzymes for guar, alpha and beta amylases, amyloglucosidase, oligoglucosidase, invertase, maltase, cellulase and hemicellulase, as well as mannanoidrolase enzymes, including those presented in U.S. Patents No. 5,806,597 and 5,067,566, incorporated herein by reference.
    [0078] When used in stimulation, microemulsions can be present in the fluid containing viscosity agent, proppant, water, salt, brine and gelled fluid, foam and liquid gas, as well as any other additive conventionally employed in stimulating fluids.
    [0079] When incorporated into microemulsions for use with stimulating fluids, the amount of well treatment agent in the microemulsions is typically between about 0.05 and about 5 (preferably from about 0.1 to about 2) weight percent based on the total weight of the microemulsion.
    [0080] Microemulsions can also be used to comminute filter cakes deposited by a drilling fluid, fluid within the borehole, fluid loss control pill and others. For example, when used to fragment filter cake formed by drilling operations, the microemulsion containing the well treatment agent can be injected into the well opening through the drill string. Typically, the microemulsion is a component of the drilling fluid, the activity of the well treatment agent being delayed until it is desirable to degrade the filter cake.
    [0081] In addition, the microemulsion can be useful in controlling the release of well treatment agents that present compatibility problems with the fluids that are being introduced in the well opening and/or underground formation. For example, where the well treating agent can adversely affect the activity performed by a fluid component that is required for an operation prior to the activity offered by the well treating agent, it may be beneficial to include the well treating agent in the microemulsion. For example, in some cases, such as with a fluid loss pill, it is beneficial for the fluid's viscosity to increase before the fluid breaks. To avoid premature action of the breaking agent, it may be beneficial to include the breaking agent in the microemulsion to decrease the possibility of adverse effects generated by the breaking agent and to maximize the effect of the breaking agent when the breaking agent is needed. The microemulsion also prevents destabilization or other changes to the treatment fluid until the desired effect caused by the well treating agent has to occur.
    [0082] The following examples are illustrative of some of the embodiments of the present invention. All percentages are in percent by volume unless otherwise noted. Other embodiments within the scope of the present claims will be apparent to those skilled in the art from the description presented herein. The report, together with the examples, is intended to be considered only as exemplary, with the scope and spirit of the invention being indicated by the following claims.
    [0083] Example 1. The release rate of water-in-oil microemulsions containing a beta-mannanase enzyme, commercially available as GBW-12CD from Baker Hughes Incorporated, Enzyme G, a disrupting agent for guar-based fluids, commercially available from Baker Hughes Incorporated, and a hemicellulase, commercially available as Enzyme GBW-15C from Baker Hughes Incorporated, were compared to aqueous fluids containing the same enzymes. Tests were conducted using the same concentrations at the same temperatures to demonstrate the effect of the well treating agent on the water-in-oil microemulsion compared to the well treating agent in an aqueous fluid. The oil phase of the microemulsion consisted of about 56% by volume of a surfactant mixture of polyoxyethylene sorbitan monopalmitate and ethoxylated castor oil and about 34% by volume of d-limonene. Microemulsions contained 6% Enzyme G, 8% Enzyme GBW-15C. Solutions in water containing 6% Enzyme G and 8% Enzyme GBW-15C were also prepared.
    [0084] The linear gel was prepared from an aqueous suspension containing 1.8 kg (4 lb) of guar polymer, oleophilic clay and a surfactant. One liter of the suspension was hydrated for 30 minutes using a standard Servodyne mixer with a high efficiency paddle at 1500 rpm to generate 18 kg (40 lb) of linear gel. The basic viscosity of the gel was measured on an OFITE M900, available from OFI Testing Equipment, Inc., using a RotorBob R1B1 setting at 511 s-1. In the OFITE M900 test, the fluid was initially sheared at 60 s-1 followed by a shear rate sweep of 60, 100 and 300 s-1 to calculate the power law indices n’ and K’. The fluid was sheared at 60 s-1 between shear rate scans, and the shear rate scan was repeated every 5 minutes for 3 hours. Rotor-Bob R1B1 configuration was used.
    [0085] OFITE rheology test results for the 18 kg (40 lb) linear gel GLFC-5D with microemulsion fluid/Enzyme G and water fluid/Enzyme G at 24°C (75°F) are shown in FIG. 1. (The baseline in the figures represents the fluid without the enzyme disrupting agent.) All linear gels containing the enzymes showed a decrease in viscosity over time. The fluid containing 1.0 gpt of microemulsion fluid/6% Enzyme G showed a lower viscosity drop rate than the fluid containing 1.0 gpt of water fluid/6% Enzyme G. This indicates the product of microemulsion is slowing the release of the enzyme.
    [0086] OFITE rheology test results for the 18 kg (40 lb) linear gel GLFC-5D with microemulsion fluid/8% Enzyme GBW-15C and water fluid/8% Enzyme GBW-15C at 24 °C (75°F) are shown in FIG. two.
    [0087] OFITE rheology test results for the 18 kg (40 lb) linear gel GLFC-5D with microemulsion fluid/8% Enzyme GBW-15C and water fluid/8% Enzyme GBW-15C at 51 .6°C (125°F) are shown in FIG. 3. The OFITE rheology test results for the 18 kg (40 lb) linear gel GLFC-5D with microemulsion fluid/8% Enzyme GBW-15C and water fluid/8% Enzyme GBW-15C at 51, 6°C (125°F) are shown in FIG. 4. In both cases, the fluid containing 1.0 gpt of Microemulsion/Enzyme fluid showed a lower rate of viscosity drop than the fluid containing 1.0 gpt of Water/Enzyme fluid. This indicates that the microemulsion product is delaying enzyme release.
    [0088] FIGs. 5 and 6 show the test results at 65.5°C (150°F). Again, the fluid containing 1.0 gpt of Microemulsion/Enzyme fluid showed a lower rate of viscosity drop than the fluid containing 1.0 gpt of Water/Enzyme fluid. This indicates that the microemulsion product is delaying enzyme release.
    [0089] Referring to Figures 1 - 6, the data show the retardation of activity in two different enzymes by incorporation of the enzyme or enzyme diluted in water into the internal phase of the microemulsion. The results show that at 24°C (75°F), 51.6°C (125°F) and 65.5°C (150°F), the enzyme microemulsion has a slower release than the same concentration of enzyme in an aqueous solution.
    [0090] The Examples illustrate that incorporation of the diluted enzyme/enzyme in a water-in-oil microemulsion delays the release of the enzyme in a fracturing fluid. In particular, the data demonstrates that at 24°C (75°F), 51.6°C (125°F) and 65.5°C (150°F), fluid containing 1.0 gpt of fluid from microemulsion/6% Enzyme G showed a lower viscosity decrease rate than fluid containing 1.0 gpt water fluid/6% Enzyme G. This indicates that the microemulsion product delayed enzyme release, and that the fluid containing 1.0 gpt microemulsion fluid/8% Enzyme GBW-15C showed a lower rate of viscosity drop than fluid containing 1.0 gpt fluid water/8% Enzyme GBW-15C. This indicates that the microemulsion product delayed enzyme release.
    [0091] From what has been said, it is observed that numerous variations and modifications can be made without leaving the true spirit and scope of the new concepts of the invention.
    权利要求:
    Claims (18)
    [0001]
    1. Method of inhibiting or controlling the rate of release of a well treatment agent into a well, an underground formation, an outflow conduit or a container, the method characterized by (a) introducing into the well, underground formation, in the flow conduit or in the well treatment agent container in a water-in-oil microemulsion; and (b) demulsify the microemulsion well treating agent at a constant rate for a continuous period of time of at least six months to continuously release the microemulsion well treating agent into water or hydrocarbons that are contained in the formation, conduit of well or container; and wherein the oil phase of the water-in-oil microemulsion is a solvent-surfactant mixture and the amount of surfactant in the mixture is 35 to 80% by volume.
    [0002]
    2. Method according to claim 1, characterized in that it further comprises introducing the water-in-oil microemulsion into a gas well, oil well or geothermal well.
    [0003]
    3. Method according to claim 1 or 2, characterized in that the oil phase of the microemulsion comprises a solvent selected from the group consisting of unsaturated aliphatic cyclic hydrocarbons, a surfactant with an HLB value between 8 and 18 and a C1-C20 alcohol or glycol.
    [0004]
    4. Method according to claim 1 or 2, characterized in that the oily phase of the microemulsion comprises a solvent among a terpene or esters of alkyl, cyclic or aryl acids of short-chain alcohols or a mixture thereof.
    [0005]
    5. Method according to claim 4, characterized in that the terpene is a monoterpene, a diterpene or a mixture thereof.
    [0006]
    6. Method according to claim 5, characterized in that the monoterpene is d-limonene.
    [0007]
    7. Method according to claim 1 or 2, characterized in that the oily phase of the microemulsion comprises an ester of alkyl, cyclic or aryl acid or a mixture thereof.
    [0008]
    8. Method according to claim 3, characterized in that the surfactant is selected from the group consisting of polyoxyethylene sorbitan monopalmitate, polyoxyethylene sorbitan monostearate, polyoxyethylene sorbitan monooleate, linear alcohol alkoxylates, alkyl ether sulfates, dodecylbenzene sulfonic acid (DDBSA), linear nonyl-phenols, dioxane, ethylene oxide, ethoxylated castor oils and mixtures thereof.
    [0009]
    9. Method according to claim 3, characterized in that the water-in-oil microemulsion contains an alcohol, a glycol or a mixture thereof.
    [0010]
    10. Method according to claim 9, characterized in that the alcohol or glycol is selected from the group consisting of isopropanol, t-butanol, n-butanol, n-pentanol, n-hexanol, 2-ethyl-hexanol , ethylene glycol, polyethylene glycol, propylene glycol, triethylene glycol and mixtures thereof.
    [0011]
    11. Method according to any one of claims 1 to 10, characterized in that the well treatment agent is at least one member selected from the group consisting of scale inhibitors, salt inhibitors, paraffin inhibitors, agents demulsifiers, gas hydrate inhibitors, pH adjusting agents, corrosion inhibitors, asphaltene inhibitors, crosslinking agents, crosslinking retarding agents, oxygen scavengers, biocides, breaking agents, buffers, acids and esters.
    [0012]
    12. Method according to any one of claims 1 to 11, characterized in that the well treatment agent has a particle size between 0.001 and 100 microns.
    [0013]
    13. Method according to any one of claims 1 to 12, characterized in that the microemulsion has an oil phase selected from the group consisting of diesel, kerosene, crude oil, condensate, synthetic oils, an ester, α-olefins linear, poly-α-olefins, paraffins, linear alkyl benzenes, esters, acetals and mixtures thereof.
    [0014]
    14. Method according to any one of claims 1 to 13, characterized in that the water-in-oil microemulsion contains between 2 and 20 percent by weight of the well treatment agent.
    [0015]
    15. Method according to any one of claims 1 to 14, characterized in that a well treatment fluid contains the water-in-oil microemulsion, and additionally wherein the amount of water-in-oil microemulsion in well treatment fluid is between 15 ppm and 100,000 ppm.
    [0016]
    A method according to any one of claims 1 to 15, characterized by further introducing the water-in-oil microemulsion into the well or formation with a treatment fluid selected from the group consisting of stimulation fluids, drilling fluids, fluids within the borehole, closure fluids and fluid loss control pills.
    [0017]
    17. Method according to claim 16, characterized by additionally injecting the treatment fluid directly into the well through a release tube and removing fines, asphaltenes, paraffins or water blockages or a combination thereof formed during treatment of the well.
    [0018]
    18. Method according to any one of claims 1 to 17, further characterized by the fact that the water-in-oil microemulsion provides continuous release of the well treatment agent introduced into the well for up to three years.
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    同族专利:
    公开号 | 公开日
    US9102860B2|2015-08-11|
    MX2013014845A|2014-03-31|
    CA2835041A1|2012-12-20|
    US20120318515A1|2012-12-20|
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    EP2721118B1|2021-08-11|
    MX351409B|2017-10-13|
    AR086966A1|2014-02-05|
    AU2012271174A1|2013-11-14|
    WO2012173728A1|2012-12-20|
    BR112013031449A2|2016-12-06|
    EP2721118A1|2014-04-23|
    CA2835041C|2016-06-28|
    CO6801706A2|2013-11-29|
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    法律状态:
    2018-04-03| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2019-07-23| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
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    优先权:
    申请号 | 申请日 | 专利标题
    US13/162,461|US9102860B2|2011-06-16|2011-06-16|Method of inhibiting or controlling release of well treatment agent|
    US13/162,461|2011-06-16|
    PCT/US2012/038048|WO2012173728A1|2011-06-16|2012-05-16|Method of inhibiting or controlling release of well treatment agent|
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