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    • 专利摘要:
    AQUEOUS VISCOELASTIC FLUID, UNDERGROUND FORMATION ACIDIFICATION METHOD, AND UNDERGROUND FORMATION FRACTURE METHOD The present invention relates generally to viscoelastic fluids, thickened acid compositions and the like, as well as methods of using said compositions gelled. Thickened compositions according to the present invention can be usefully employed in methods of stimulating and/or modifying the permeability of underground formations, in drilling fluids, finishing fluids, working fluids, acidifying fluids, fracture formation, packaging of gravel and the like.
    公开号:BR112013028865B1
    申请号:R112013028865-5
    申请日:2012-05-21
    公开日:2021-04-20
    发明作者:James F. Gadberry；Michael J. Engel；John Douglas Nowak；Jian Zhou；Xiaoyu Wang
    申请人:Akzo Nobel Chemicals International B.V.；
    IPC主号:
    专利说明:

    FIELD OF THE INVENTION
    The present invention relates generally to thickened viscoelastic compositions and their uses. Gels in accordance with the present invention are thickened with a gelling agent which comprises erucamidopropyl hydroxypropyl sulfobetaine. BACKGROUND OF THE INVENTION
    The present invention relates generally to viscoelastic compositions, thickened acid gels and uses of such thickened gels. Acid thickened solutions can be usefully employed, for example, in cleaning formulations such as hard surface cleaners, toilet cleaners, industrial cleaners and the like, and in petroleum applications such as well stimulation. These and other uses will be evident to those skilled in the art.
    The compositions according to the present invention are particularly useful in petroleum applications. Hydrocarbons are obtained by drilling wells that penetrate an underground formation that contains hydrocarbons, providing a partial flow path for the oil to reach the surface. For oil to travel from the formation to the well hole, there must be a flow path from the formation to the well hole. This flow path passes through the formation's rocks and has pores of sufficient size and number to allow the oil conductor to move through the formation.
    A common reason for declining oil production is formation damage that clogs the pores of the rock and impedes the flow of oil to the wellbore and ultimately to the surface. This damage usually arises from the deliberate injection of another fluid into the wellbore. Even after drilling, some drilling fluid remains in the formation region near the wellbore, which can dehydrate and form a coating over the wellbore. The natural effect of this coating is to reduce the permeability to oil movement from the formation towards the wellbore.
    Another reason for the decline in oil production is when the formation's pores are small in size, such that oil migrates towards the well hole only very slowly. In both circumstances, it is desirable to increase the low permeability of the formation.
    Well stimulus designates the various methods employed to increase the permeability of a formation that contains hydrocarbons. Three general well stimulation methods are typically employed. The first involves injecting substances into the wellbore to react and dissolve materials that damage permeability such as wellbore linings. A second method requires injecting substances through the wellbore and into the formation to react and dissolve small parts of the formation to create alternative flow paths for hydrocarbons to flow into the wellbore. These alternative flow paths redirect the flow of oil around damaged or low permeability areas of the formation. A third method, often called fracturing, involves injecting substances into the formation under enough pressure to actually fracture the formation to create a large flow channel through which the hydrocarbon can more easily move from the formation and into the formation. of the well hole.
    US2008/161207 relates to viscoelastic surfactant gels comprising non-aqueous tackifiers and uses of such gels. Disclosed viscoelastic surfactants include betaines and alkylamidopropylbetaines.
    US2008/161210 relates to viscoelastic surfactant gels comprising non-aqueous tackifiers and uses of such gels. Disclosed viscoelastic surfactants include methyl ester sulfonates.
    WO2009/064719 relates to foam generating compositions for treating oil and gas wells. The foam maker comprises a quaternized heterocyclic foaming agent and optionally a betaine surfactant. US2002064510 refers to personal care formulations containing an anionic surfactant and a betaine surfactant.
    The viscoelastic fluids thickened in accordance with the present application also have applications in hydraulic fracturing, gravel packing and in other well stimulation methods known to those of ordinary skill in the art. In addition, the acid thickened fluids in accordance with the present invention can be usefully employed in a variety of household and industrial cleaners, which include, but are not limited to, detergent compositions, toilet bowl cleaners, hard surface cleaners, water cutting compositions. grease and the like. SUMMARY OF THE INVENTION
    The present invention generally relates to viscoelastic fluids, thickened acidic compositions and the like, as well as methods of using the aforementioned
    Thickened compositions according to the present invention can be usefully employed in methods of stimulating and/or modifying the permeability of underground formations, in drilling fluids, finishing fluids, working fluids, acidifying fluids, fracture formation, packaging of gravel and the like. Furthermore, the acidic thickened compositions according to the present invention can also be employed in cleaning formulations, water-based coatings, detergent formulations, personal care formulations, water-based asphalt formulations and the like. DETAILED DESCRIPTION OF THE INVENTION
    The present invention generally relates to viscoelastic fluids or compositions and methods of using said compositions/fluids. Thickened compositions according to the present invention can be usefully employed in methods of stimulating and/or modifying the permeability of underground formations, in drilling fluids, finishing fluids, working fluids, acidifying fluids, gravel packaging, formation of fractures and the like. Furthermore, the thickened compositions according to the present invention can also be employed in cleaning formulations, water-based coatings, detergent formulations, personal care formulations, water-based asphalt formulations and the like.
    Viscoelasticity is a desirable rheological characteristic in drilling fluids, working or finishing fluids, and stimulus fluids that can be provided by fluid modifying agents such as polymeric agents and surfactant gelling agents. Viscoelastic fluids are those that exhibit elastic behavior and viscous behavior. Elasticity is defined as an instantaneous stretching (strain) reaction of a material to an applied stress. After removal of tension, the material returns to its undeformed equilibrium state. This type of behavior is associated with solids. On the other hand, viscous behavior is defined as continuous deformation resulting from an applied stress. After a period, the deformation speed (cutting speed or general drawing speed) becomes stable. After removal of stress, the material does not return to its initial undeformed state. This type of behavior is associated with liquids. Viscoelastic fluids can behave as a viscous fluid or an elastic solid or a combination of both, depending on the stress applied to the system and the time scale of the observation. Viscoelastic fluids exhibit elastic reaction immediately after applying tension. After the initial elastic reaction, the stretch relaxes and the fluid begins to flow viscously. The elastic behavior of fluids is believed to significantly aid the transport of solid particles.
    The viscosity of a viscoelastic fluid can also vary with the tension or speed of stretch applied. In the case of shear deformations, it is very common for the fluid's viscosity to drop with increasing cutting speed or shear stress. This behavior is commonly referred to as “cut thickness reduction”. The viscoelasticity of fluids that is caused by surfactants can manifest its own thinning behavior with shear. When this fluid is passed through a pump or is in the vicinity of a rotating drill, for example, the fluid is in a high cutting speed environment and the viscosity is low, which results in low friction pressures. and savings in pumping energy. When shear stress is reduced, the fluid returns to a higher viscosity condition. This is because the viscoelastic behavior is caused by aggregations of surfactant in the fluid. These aggregations will adjust to the fluid conditions and will form different aggregate shapes under different shear stresses. In this way, you can have a fluid that behaves like a fluid with high viscosity at low cutting speeds and a fluid with low viscosity at higher cutting speeds. High viscosities with low cutting speed are good for transporting solids.
    The elastic component of a viscoelastic fluid can also manifest itself in an yield stress value. This allows a viscoelastic fluid to suspend an insoluble material, such as drill cuttings or sand, for a longer period of time than a viscous fluid of the same apparent viscosity. Yield voltages that are too high are not good for drilling as they can make it very difficult to restart the bit and cause a condition called “clogged pipe”.
    Another function of viscoelastic fluids in oil drilling applications is permeability modification. Secondary oil recovery from reservoirs involves artificially supplementing the natural energy inherent in the reservoir to recover the oil. When oil is stored in porous rock, for example, it is often recovered by directing a pressurized fluid, such as brine, through one or more drill holes (injection wells) in the reservoir formation to force the oil to a well hole from which it can be retrieved. The rock often has, however, areas with high and low permeability. The injected brine can lead its way through areas with high permeability, leaving unrecovered oil in areas with low permeability.
    The aqueous viscoelastic fluid according to the present invention comprises at least one viscoelastic gelling agent and/or surfactant with the general formula:
    wherein R1 is a saturated or unsaturated hydrocarbon group having about 17 to about 29 carbon atoms and, in another embodiment, about 18 to about 21 carbon atoms. In one embodiment, R1 is a fatty aliphatic derived from natural oils or fats that have an iodine value from about 1 to about 140, in another embodiment about 30 to about 90, and in another embodiment, from 40 to about 70. R1 can be restricted to a single chain length or it can be of mixed chain length, such as groups derived from natural oils and fats or petroleum stocks. Examples are tallow alkyl, hardened alkyl tallow, canola alkyl, hardened canola alkyl, tall oil alkyl, hardened tall oil alkyl, coconut alkyl, oleyl, erucil or soybean alkyl. R2 and R3 are selected, independently of each other, from a straight or branched chain alkyl or hydroxyalkyl group having one to about six carbon atoms, in another embodiment having one to four carbon atoms, and in yet another embodiment, with one to three carbon atoms. R4 is selected from H, OH, alkyl or hydroxyalkyl groups having one to about four carbon atoms; in another embodiment, ethyl, hydroxyethyl, OH or methyl. Among the remaining substituents, k is an integer from 2 to 20, in another embodiment from 2 to 12, in yet another embodiment from 2 to 6, and in yet another embodiment from 2 to 4; m is an integer from 1 to 20, in another embodiment from 1 to 12, in yet another embodiment from 1 to 6, and in yet another embodiment from 1 to 3; en is an integer from 0 to 20, in another embodiment from 0 to 12, in yet another embodiment from 0 to 6, and in yet another embodiment from 0 to 1.
    The gelling agents disclosed and described herein are surfactants that can be added singly or can be used as a primary component in the thickened aqueous compositions according to the present invention. Examples of gelling agents contemplated by the present invention include, but are not limited to, those selected from the group consisting of erucamidopropyl hydroxypropyl sulfobetaine, erucamidopropyl hydroxyethyl sulfobetaine, erucamidopropyl hydroxymethyl sulfobetaine, mixtures thereof, and the like. Erucamidopropyl hydroxypropyl sulfobetain, also known as erucamido hydroxysultaine, is an example of a gelling agent normally employed in the viscoelastic fluid in accordance with the present invention.
    In an example of a process for preparing the gelling agents according to the present invention, erucamidopropyl hydroxypropyl sulfobetaine, N-(3-dimethylaminopropyl)erucamide is reacted with sodium 3-chloro-2-hydroxy-1-propanesulfonate (HOPAX "CHOPSNA") in the presence of SCA 40B ethanol (co-solvent 1), deionized water (co-solvent 2), propylene glycol (co-solvent 3) and NaOH under N2. The reaction mixture is heated to 112-115 °C with stirring until the amine salt and free amine contents are both less than 1%. Adjustment of NaOH is carried out if the amine salt content is more than 1%. After confirming that the free amine and amino salt are within specifications, the reaction mixture is cooled to 65°C and depressurized. Water is then added to the batch to dissolve all salts. The final water concentration range is generally about 15-25% and, in another embodiment, 15-17.5%.
    For optimal performance, various solvents are used in preparing and using the composition according to the present invention. A first solvent is a dihydric or polyhydric alcohol, which can be oligomeric or polymeric. Examples include, but are not limited to, ethylene glycol, butylene glycol, diethylene glycol, polypropylene glycol, polyethylene glycol, glycerin, propylene glycol, tetramethylene glycol, tetramethylethylene glycol, trimethylene glycol and the like. Propylene glycols (such as 1,2-propanediol) are preferred glycols.
    A second co-solvent, such as an alcohol, is also used. Alcohols useful herein as a co-solvent are generally monohydric alcohols and can be alkanols or alcohol alkoxylates. Methanol, ethanol and butanol are non-limiting examples. In one embodiment, ethanol is an example of an alcohol usefully employed in the context of the present invention. Water is the third solvent.
    The relative amounts and order of addition of the co-solvents are important to prevent gelling of the reaction mass, dissolve the salts for a filter-free process, prevent the formation of a small upper ethanol phase in the product, and minimize the melting point of the product. product. In this regard, a glycol, such as propylene glycol, is usually added initially to avoid potential gelation of the batch. The amount of propylene glycol added is generally in the range of about 10% by weight to about 16% by weight; in another embodiment, about 12% by weight to about 15% by weight; and, in another embodiment, 13% by weight or 14% by weight.
    The second co-solvent, such as ethanol, is added in an amount of from about 16% by weight to about 22% by weight; in another embodiment, about 17% by weight to about 21% by weight; and, in another embodiment, 18% by weight, 19% by weight or 20% by weight.
    The total weight percent of ethylene + propylene glycol is from about 25% by weight to about 40% by weight; in another embodiment, about 30 to 35% by weight, and in yet another embodiment, 31% by weight, 32% by weight, 33% by weight, or 34% by weight. The weight range between ethanol and propylene glycol can range from about 1.0 to 2.2 to avoid batch gel formation and the formation of a higher ethanol liquid phase. The total amount of ethanol and propylene glycol is kept constant with respect to the amount of N-(3-dimethylaminopropyl)erucamide that is used. The melting point of the final product is about 20°C if the propylene glycol is removed from the solution, but it is reduced to about 12°C by the addition of propylene glycol.
    The final concentration range of the third solvent, water, is generally about 15-25% and, in another embodiment, 15-17.5%. In one embodiment, a minimum water content of the final solution in batches of about 15% is used to ensure that all salts are dissolved (sodium chloride by-product and excess CHOPSNa). Also, too little ethanol in the batch compared to water can cause the batch to gel. The nominal weight ratio range between ethanol and water is typically about 1.0 to 1.175 to avoid potential gel formation situation.
    The viscoelastic fluid according to the present invention does not undergo phase separation over extended periods of time and exhibits high heat stability.
    In one embodiment, the present invention relates to an aqueous viscoelastic fluid useful as a fracture-forming fluid and to a method of fracturing an underground formation. These fluids create channels or fractures in oil-producing reservoir zones in order to increase oil production by providing a high permeability path from reservoir rock to the wellbore. Typically, in areas with low permeability, fracture-forming fluids are pumped under pressures that exceed the loading weight of the rock formation, in order to cause splits and fractures in the formation rock. Bracing agents (such as particulate material) are added to the fluid to prevent the induced fractures from closing after the pumping phase is completed by bracing the induced cracks and fractures. Gelling agents are added to the fluid to transport these bracing agents and reduce fluid leakage. In areas with higher permeability, different methods can be used, but fluid thickeners are often used.
    The viscoelastic compositions described herein provide several advantages over polymers (such as polysaccharides) currently used as gelling agents for below-the-orifice fluids. The gelling agents defined herein, when used to fluid down the orifice, for example, produce less residue on the formation, which can result in formation damage during and after the downhole process. In addition, it is easier to prepare the gelled fluid compared to polymers that typically need to be hydrated and the gelled fluid can be designed to “break” with forming temperatures or other factors such as oxidizers or acids. It is also possible to "break" the gelled fluid using solvents such as hydrocarbons, alcohols or even petroleum produced by the formation. The gelling agents defined below are useful over a wide temperature range, depending on chain length, and can assist in removing oil from the formation.
    For the purposes of selectively modifying the permeability of underground rock formations, the viscoelastic composition according to the present invention can first be mixed with water and different types and amounts of organic and inorganic salts to form a viscoelastic fracture-forming fluid which it is then injected into the rock formation in an amount effective to reduce the permeability of the more permeable zone(s) of the formation. The concentration of viscoelastic composition in the fluid can be from about 0.5% to about 10%, preferably about 2% to about 8%, and most preferably about 3% to about 5% by weight.
    In another embodiment, the present invention contemplates an acidic thickened aqueous composition comprising one or more gelling agents and acid in aqueous solution as described below. The thickened acid gels disclosed and described herein may conveniently be employed as an acidifying fluid. An important part of the world's hydrocarbon reserves is found in rock carbonate structures that are known to have very low permeability. In many sandstone reservoirs, the rock structure can be cemented by carbonate or carbonate scales can accumulate near production wells as a result of the release of carbon dioxide from the solution due to a pressure drop. Another type of scale that can accumulate around production wells is iron scale, particularly iron oxides and hydroxides. Low permeability, drilling damage and scale build-up impede the flow of oil to the production well and the conventional method used to open channels around the well hole to increase flow velocity is acid injection known as acid stimulus or acidification.
    There are two types of acid treatments: fracture acidification, that is, acid injection at speeds above the fracture pressure to corrode the faces of the resulting fractures, and matrix acidification, where acid injection is performed at speeds below the pressure to dissolve flow channels in rock or remove scale or damage caused by drilling. Acid treatments are employed in all types of oil wells and occasionally water wells: they can be used to open fractures or remove damage to newly drilled wells or to rehabilitate old wells whose production has dropped. Acid is pumped into the cavity, where it reacts with calcium carbonate according to the following reaction:
    Calcium chloride (CaCl2) is highly soluble in water and the acid corrodes channels in the rock to increase the flow of oil or gas towards the production well. Hydrochloric acid reacts immediately with carbonate rock and tends to form some large channels known as “wormholes” through the rock, rather than opening up the pore structure. The acid penetration distance is limited to a maximum of a few meters.
    As hydrochloric acid reacts very quickly when in contact with carbonate rock, several products have been developed that are intended to reduce the reaction rate, allowing further penetration of the acid into the formation or its reaction more evenly around the wellbore. The hydrochloric acid reaction can be slowed down by gel formation of the acid according to the present invention. Furthermore, it has been shown that the acid thickened gel according to the present invention thickens with calcium carbonate up to about 13 to 17% and at that point the gel phases separate, causing rapid reduction. of thickness.
    The acetic acid reaction is naturally slowed down because the accumulation of the reaction product, carbon dioxide, slows down the reaction. As carbon dioxide leaks into the formation or is absorbed by oil, water or hydrocarbon gas, the acetic acid reaction continues.
    Hydrocarbon wells in carbonate reservoirs are conventionally acidified immediately after drilling, before production begins, and often repeated treatments are conducted every two to three years.
    Thickened acid gels in accordance with the present invention are also useful in forming matrix fractures, where fractures are created by injecting sand suspended in an aqueous fluid (known as a strut) into a well at speeds above the fracture pressure. When the injection pressure is removed, the sand remains in place, supporting the open fracture. It is very unusual for an anchored fracture to be subsequently treated with hydrochloric acid, as the high rate of reaction between the acid and the rock can cause the fracture to collapse. Damage can be caused, however, by the filtration of gels from the strut suspension over the fracture faces and this can substantially reduce the velocity of oil or gas flow into the fracture.
    Conventionally, oil wells are drilled vertically in the oil reservoir and through the reservoir floor. Oil flows into the vertical well hole. In recent years, drilling of vertical wellbore wells in a horizontal direction through the reservoir has become widespread. In many cases, horizontal wells have increased hydrocarbon production by several orders of magnitude. Removing the risk of drilling caused by the accumulation of drilling mud filter agglomerate and fine rock particles from horizontal wells is a very expensive process, due to the need to use specialized methods, such as acid injection through coiled tubing, to prevent corrosion of wellhead equipment and avoid consumption of hydrochloric acid before it reaches the far end of the horizontal well. The purpose of an acid treatment or acidification of the formation is to remove formation damage along as much of the hydrocarbon flow path as possible. An effective treatment must therefore remove as much damage as possible along the entire flow path. The fluids and methods in accordance with the present invention allow maximum penetration of the acid, which results in more effective treatment.
    Finally, when a reservoir has been depleted due to a reduction in the reservoir's natural pressure, water or carbon dioxide gas can be injected to recover an additional percentage of the oil on site. Water or gas is injected through a part of the wells in the reservoir (injection wells), in order to push the oil towards the producing wells. In some reservoirs, the water injection speed is low and therefore the oil production speed is low. Acid treatments using the acid gels according to the present invention can be used to increase the injection capacity of injector wells.
    The gelling agents described herein provide several advantages over polymers (such as polysaccharides) currently used as gelling agents for below-the-orifice fluids. The compounds defined herein, when used as gelling agents for down-the-hole fluid, for example, produce less residue on the formation, which can result in formation damage during and after the down-hole process.
    In addition, it is easier to produce the gelled fluid compared to polymers that typically need to be hydrated and the gelled fluid can be designed to “break” with forming temperatures or other factors such as oxidizers. One can also "break" the gelled fluid using solvents such as hydrocarbons, alcohols or even petroleum from the formation. The gelling agents defined below are useful over a wide range of temperatures, depending on chain length, and can assist in removing oil from the formation.
    For purposes of selectively modifying the permeability of underground rock formations, one or more gelling agents may first be mixed with an aqueous acidic composition of desired strength to form a thickened acidic viscoelastic fluid which is then injected into the rock formation in an amount effective to modify the permeability of the formation. Optionally, the concentration of gelling agent in the acidic fluid can be from about 0.5% to about 10%, preferably about 2% to about 8%, and most preferably about 4% to about 6% by weight. It is also important that the gelling agent contain less than about 1% free fatty acid for optimal performance.
    A sequestrant can also be used to stabilize the product at higher temperatures during storage. A preferred scavenger is a phosphonate salt, such as the phosphonate salts sold by Solutia® under the trade name Dequest®. A preferred product is Dequest® 2010. The sequestrant can be added during the process of making the gelling agent composition according to the present invention or at any time thereafter.
    The concentration of gelling agent composition preferably ranges from about 1% to about 10%, depending on the desired viscosity, more preferably about 3% to 8% and most preferably about 4% to about 6% .
    The gelling agents in accordance with the present invention have been shown to effectively thicken acidic solutions of HCl from 0 to 15%.
    The compositions according to the present invention may also contain inorganic salts (such as brines containing alkali metal salts, alkaline earth metal salts and/or ammonium salts) and other viscosity modifying additives (such as cellulosics). Brines gelled with these agents are conveniently used as water deflection agents, propellant fluids, fracture fluids, drilling muds, gravel packing fluids, drilling fluids, working fluids, finishing fluids and the like.
    The acidic gelled compositions according to the present invention can also be used in cleaning and sanitizing formulations, water-based coatings (such as paints), detergent formulations, personal care formulations, water-based asphalt systems, concrete, construction products (such as cement, concrete, joining compounds and the like), agricultural diversion control agents, in oil well stimulus applications, and the like.
    When used in simulation applications, fluids thickened in accordance with the present invention can optionally include lubricants, corrosion inhibitors and various other additives.
    Lubricants can include metal or amine salts of an organosulfur, phosphorus, boron or carboxylic acid. Typical of such salts are carboxylic acid salts having one to 22 carbon atoms and include aromatic and aliphatic acids; sulfur acids such as alkyl and aromatic sulfonic acids and the like; phosphorus acids, such as phosphoric acid, phosphorous acid, phosphinic acid, acid phosphate esters and the like sulfur homologues, such as thiophosphoric and dithiophosphoric acid and related acid esters; mercaptobenzothiozole; boron acids, including boric acid, acidic borates and the like; and lauric acid amine salts.
    Corrosion inhibitors can include alkali metal nitrites, nitrates, phosphates, silicates and benzoates. Representative suitable organic inhibitors include acid compounds neutralized by hydrocarbyl amine and hydroxy-substituted hydrocarbyl amine, such as neutralized phosphates and hydrocarbyl phosphate esters, neutralized fatty acids (such as those containing from eight to about 22 carbon atoms), acids neutralized aromatic carboxylic acids (such as 4-(t-butyl)-benzoic acid), neutralized naphthenic acids and neutralized hydrocarbyl sulfonates. Esters of mixed salts of alkylated succinimides are also useful. Corrosion inhibitors can also include alkanolamines such as ethanolamine, diethanolamine, triethanolamine and the corresponding propanolamines, as well as morpholine, ethylenediamine, N,N-diethylethanolamine, alpha and gammapicoline, piperazine and isopropylaminoethanol.
    Stimulus fluids may also include application-specific additives to optimize fluid performance. Examples include dyes; dyes; deodorants such as citronella; bactericides and other antimicrobials; chelating agents such as an ethylene diamine tetraacetate sodium salt or nitrilotriacetic acid; antifreeze agents such as ethylene glycol and analogous polyoxyalkylene polyols; defoamers such as silicone containing agents and shear stabilizing agents such as commercially available polyoxyalkylene polyols. Anti-wear agents, friction modifiers, lubricity and anti-slip agents can also be added. Extreme pressure additives such as zinc phosphate and dialkyl dithiophosphate esters are also included.
    Thickened acid gels in accordance with the present invention may also be usefully employed in cleaning and sanitizing formulations, water-based coatings (such as paints), detergent formulations, personal care formulations, water-based asphalt systems. , concrete, construction products (such as cement, concrete, joint compounds and the like), agricultural diversion control agents, in other oilfield applications and oil well stimulation and the like.
    The present invention will now be illustrated by the following examples. Example 1
    Synthesis of erucamidopropyl hydroxypropylsultaine (Armovis EHS):
    A filter-free reaction sequence for making Armovis EHS is summarized below: To a pressure rated reaction vessel of two liters are added: 1. 500 g of N-(3-dimethylaminopropyl)erucamide; 2. 260 g of sodium 3-chloro-2-hydroxy-1-propanesulfonate (HOPAX "CHOPSNA"); 3. 285.0 g of SCA 40B ethanol (co-solvent 1); 4. 160.0 g of deionized water (co-solvent 2); 5. 195 g of propylene glycol (co-solvent 3); and 6. 6.0 g of 50% NaOH under N2.
    The mixture is heated to 112-115°C and the well is shaken for about six hours before sampling to confirm that the free amine and amine salt content is less than 1% for both. NaOH adjustment is necessary if the amine salt content is more than 1%. After confirming that the free amine and amine salt are within specifications, the reaction mixture is cooled to 65 °C and depressurized. Water is then added to the batch to dissolve all salts. The final water concentration range is 15 to 17.5%. The final solution is discharged at about 65 °C into a collection vessel. The material is a pale yellow liquid.
    Remarks regarding co-solvents (ethanol, propylene glycol and water): The relative amounts and order of addition of the co-solvents are important to avoid gelling of the reaction mass, dissolve salts for a free filtration process, avoid the formation of a small higher ethanol phase in the product and minimize the melting point of the product. 1. Propylene glycol is added initially to avoid potential gelling of the batch. 2. The weight range between ethanol and propylene glycol can range from about 1.0 to 2.2 to avoid batch gel formation and formation of a higher ethanol liquid phase. The total amount of ethanol and propylene glycol is kept constant with respect to the amount of N-(3-dimethylaminopropyl)erucamide that is used. 3. An upper liquid ethanol phase can be formed if the propylene glycol is removed or the weight ratio of ethanol to propylene glycol increases above 2.2. 4. Ethanol to propylene glycol weight ratio below 1.0 can result in batch gelling. 5. The melting point of the product is about 20°C if the PG is removed from the solution. The melting point is reduced to about 12°C by adding PG. 5 6. The minimum water content of the final batch solution is about 15% to ensure that all salts are dissolved (sodium chloride by-product and excess CHOPSNa). 7. Too little ethanol in batch compared to 10 in water can cause batch gelling. The nominal weight ratio range between ethanol and water is about 1.0 to 1.175 to avoid potential gel formation situation.
    A typical batch has the following composition:

    Note 1. Sodium chloride was calculated from the inorganic chloride content. 2. CHOPSNa was calculated as the difference between sodium and inorganic chloride tests. 3. Activity was calculated as % solids - % free amine - % amine salt - % sodium chloride - % CHOPSNa. Example 2
    General Armovis EHS (VES) Gel Elaboration Procedures and Rheology Testing: A brine solution containing 4 to 8% by weight of 5 salt was stirred in a 500 ml stainless steel mixer.
    For this solution, a certain amount (by volume) of Armovis EHS concentrate (40% to 50% by weight in a mixed solvent system containing ethanol, propylene glycol and water) was added to the brine solution. The resulting mixture was stirred for three minutes at 2000-3000 rpm in a mixer. The resulting gel was then centrifuged at 1000 rpm for fifteen minutes to remove air bubbles. Rheological performance was evaluated using a Grace Instruments Rheometer (model M5600) at constant cutting speed and different temperatures. A pressure of 27.579 bar was applied to minimize sample evaporation, especially at high temperatures.
    Fracture of an underground formation requires a thickened fluid through a well hole and formation to initiate and extend a fracture in the formation. High viscosity fluid is used to prevent fluid leakage and lead the strut to fracture. Polymers have been used to prepare a thickened fluid in the past, but several disadvantages have been noted for polymer-based fracture fluids: 1) They are sensitive to shear. Fracture fluids based on synthetic polymers are non-Newtonian shear thinning fluids. Viscosity is low at high cutting speed and does not build up again when cutting speed drops. 2) They are not salt tolerant. Polymers often precipitate from solutions with high salinity and can cause severe damage to the formation. 3) Biopolymers are not very thermally stable. In addition, oxygen or biocide extraction is required to prevent biodegradation. 4) A breaker needs to be used to break down the gel viscosity. The decomposition efficiency, however, is usually very low, even with the use of a breaker. To overcome all these disadvantages, tensoactive-based fracture fluids were generated to obtain a much cleaner system for underground formation. Fluids are often made in NH4Cl or 4-8% KCl solutions to stabilize clay/shale formation.
    Examples 3 to 6 illustrate the effect of Armovis EHS concentration on the rheology performance of different fluids for fracture-forming fluids. Example 3


    Drilling and finishing fluids are usually made in CaCl2, CaBr2, ZnBr2 etc solutions. The salt concentration depends on the depth of the well. The deeper the well, the heavier the fluids, as they must exert sufficient hydrostatic pressure against the formation below the surface. In addition, the fluids must be viscous enough to prevent loss of circulation and drive the drill cuts to the surface. Examples 7 to 9 illustrate the use of Armovis EHS 10 in accordance with the present invention for use in drilling and finishing fluids.


    The ZnBr2 solution is this strong brine (17.2 ppg) and is normally used in the deep well. No good rheological performance has been observed at high temperatures before, however, when the surfactant is mixed with ZnBr2 solution. EHS is the only VES system that exhibits good viscosity in a brine and ZnBr2 system.
    Example 7 present invention at 20% exhibits Armovis EHS according to gel with high in weight of ZnBr2 Example 9
    Most reservoirs are heterogeneous and permeability varies from one layer to another. During the acidification treatment, the acid will flow into the areas with high permeability, as they are less resistant. Only a limited amount of acid flows into areas with low permeability or damaged areas. This uneven distribution of injected acid can cause important economic loss. The method that can effectively solve this problem is the use of acid bypass method. Acid based surfactants have been effectively used recently as one of the diversion systems. After the acid reacts with the carbonate rock, the pH increases and the concentrations of divalent cations (Ca (II) and Mg (II)) increase in the spent acid. Both factors cause the surfactant molecules to form micelles similar to long rods that will significantly increase the apparent viscosity of the solution and force the acid to flow into the low permeable zone. Example 10
    Illustrates the use of Armovis EHS in accordance with the present invention to simulate the end point of HCl acidification applications to carbonate reservoirs.

    The Armeen APA-E® starting material is used to prepare Armovis EHS in accordance with the present invention. The unreacted amine apparently has the adverse effect on the rheological performance of the surfactant system. Example 11
    Shows the effect of Armeen APA-E® amine impurity on the rheological performance of a gelling system for use in acidifying fluids.
    The gel contained 30% CaCl2, 6% Armovis EHS ex% Armeen APA-E®. Percent APA-E is the percentage ratio between the concentration of Armeen APA-E® and the active concentration of Armovis EHS.

    权利要求:
    Claims (6)
    [0001]
    1. AQUEOUS VISCOELASTIC FLUID, comprising at least one gelling agent composition, characterized in that said gelling agent composition comprises at least one viscoelastic surfactant with the general formula:
    [0002]
    2. FLUID according to claim 1, characterized in that R1 is a saturated or unsaturated hydrocarbon group with 18 to 21 carbon atoms, R2 and R3 are independently selected from a straight or branched chain alkyl or hydroxyalkyl group with a to three carbon atoms, R4 is selected from H, alkyl or hydroxyalkyl groups of one to three carbon atoms, k is an integer from 2 to 6, m is an integer from 1 to 6 and n is an integer from 0 to 6.
    [0003]
    3. METHOD OF ACIDIFICATION OF UNDERGROUND FORMATION, characterized in that it comprises the injection of an acidifying fluid into the formation, wherein the acidifying fluid comprises at least one acid and from 0.5% to 10% in relation to the concentration of the viscoelastic fluid of claim 1 .
    [0004]
    4. METHOD according to claim 3, characterized in that at least one acid is selected from the group consisting of mineral acids, organic acids and their mixtures.
    [0005]
    5. UNDERGROUND FORMATION FRACTURE METHOD, characterized by comprising the steps of pumping an aqueous fracturing fluid, through a well hole and into an underground formation under sufficient pressure to fracture the formation, wherein the aqueous fracturing fluid comprises from 0.5% to 10% with respect to the concentration of the viscoelastic fluid, as defined in claim 1.
    [0006]
    6. METHOD according to claim 5, characterized in that the formation is a hydrocarbon reservoir or a water reservoir.
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    同族专利:
    公开号 | 公开日
    RU2598959C2|2016-10-10|
    CA2835511C|2017-09-12|
    AU2012260957A1|2013-11-07|
    CN103502386A|2014-01-08|
    EP2714839B1|2015-05-13|
    US9341052B2|2016-05-17|
    WO2012160008A1|2012-11-29|
    US20140076572A1|2014-03-20|
    AU2012260957B2|2015-07-02|
    EP2714839A1|2014-04-09|
    CN103502386B|2017-03-08|
    AU2012260957C1|2015-11-26|
    RU2013155892A|2015-06-27|
    BR112013028865A2|2017-08-01|
    CA2835511A1|2012-11-29|
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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]|
    2020-09-15| B07A| Application suspended after technical examination (opinion) [chapter 7.1 patent gazette]|
    2021-02-09| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-04-20| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 21/05/2012, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
    申请号 | 申请日 | 专利标题
    US201161489058P| true| 2011-05-23|2011-05-23|
    US61/489,058|2011-05-23|
    EP11180016.5|2011-09-05|
    EP11180016|2011-09-05|
    PCT/EP2012/059320|WO2012160008A1|2011-05-23|2012-05-21|Thickened viscoelastic fluids and uses thereof|
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