MX2012010431A - Methods relating to modifying flow patterns using in-situ barriers. - Google Patents

Abstract

A method comprises providing a fluid source in a subterranean formation; providing a wellbore in the subterranean formation; and providing an in-situ barrier, wherein the in-situ barrier is disposed within the subterranean environment and modifies the flow pattern of at least one fluid within the subterranean formation that is provided by the fluid source and flows towards the wellbore.

Description

METHODS RELATED TO THE MODIFICATION OF FLOW PATTERNS USING IN-SITU BARRIERS FIELD OF THE INVENTION The present invention relates generally to the production of hydrocarbons, and more particularly to a method for increasing the production of hydrocarbons in an existing well by forming an in-situ barrier for the flow of one or more fluids to modify flow patterns. or.

BACKGROUND OF THE INVENTION In certain underground formations, the fluid is injected into a tank to displace or sweep the hydrocarbons out of the tank. This method of stimulating production is sometimes referred to as an enhanced oil recovery (EOR) method and can be called water flooding, gas flooding, steam injection, etc. For the purpose of this specification, the general process will be defined as injecting a fluid (gas or liquid) into a reservoir in order to displace, drive, or increase the production of existing hydrocarbons in a production well. The main problem with injecting fluid to improve oil recovery is how to sweep the hydrocarbon deposit in the most efficient way possible. Due to the geological differences in a deposit, the permeability within the deposit may not be homogeneous. Due to these differences in permeability between the vertical and horizontal directions or the existence of veins with higher permeability, the injection fluid can exceed some of the deposit and create a trajectory inside the production well.

The industry has come up with methods to improve the efficiency of sweeping in individual wells. These methods include fracturing and the use of deviated wells. The industry currently uses horizontal wells as injectors in an attempt to expose more of the deposit to the injection fluid. The goal is to create injection fluid movement evenly through the reservoir. This is sometimes referred to as line driving.

Part of the efficiency of the sweep is to reduce the production of the injection fluid. The industry has created several techniques that involve the use of chemicals that block the injection fluid, to injection fluids that improve matrix flow through the reservoir to reduce channeling. As used herein, "channelization" refers to a condition in which a fluid flows through a permeability path rather than uniformly through a region or zone. Some injection programs include attempts to connect high permeability sales and natural fractures in the tank. This is done to force the injection fluid inward from over the tank to displace hydrocarbons.

When the injection fluid, such as water, is produced, it is usually removed from the hydrocarbon on the surface using multiple phase separation devices. One drawback of these devices is that they may require additional maintenance or repair if solids are part of the fluid stream that is produced. An additional drawback, and perhaps the greatest of these solutions, is that they do not increase to maximize the amount of hydrocarbons that are being produced. Its focus is to remove the water from production.

Specialized tools have also been developed for the interior of the wells, which separate the hydrocarbon water into the well. These tools are designed to leave the water in the formation while the hydrocarbons are being produced. While these devices can remove a significant amount of water from hydrocarbons, they are also less than perfect in removing water from hydrocarbons. They also suffer from the same drawback of surface separation devices that do nothing to increase or maximize the amount of hydrocarbons that are being produced.

BRIEF DESCRIPTION OF THE INVENTION The present invention relates generally to the production of hydrocarbons, and more particularly to a method for increasing the production of hydrocarbons in an existing well by forming an in-situ barrier for the flow of one or more fluids to modify flow patterns.

In one aspect of the invention, a method comprises providing a source of fluid in an underground formation; provide a well in the underground formation; and providing an in-situ barrier, wherein the in-situ barrier is placed within the underground environment and modifies the flow pattern of at least one fluid within the underground formation that is provided by the fluid source and flows into the well .

In another aspect of the invention, one method comprises providing a plurality of wells in an underground formation, wherein at least one well comprises a fracture; providing at least one injection well in the underground formation; and providing an in-situ barrier by placing a sealant in the fracture of said at least one well; wherein the sealant modifies the flow pattern of at least one fluid provided by the injection well within the underground formation. A well placed in the underground formation to produce a production fluid from the underground formation; and an in-situ barrier placed within the underground formation, wherein the in-situ barrier modifies the flow of at least one fluid driven by the fluid driving force within the underground formation.

In one embodiment, the in-situ barrier comprises a fracture with a sealant placed therein.

In one embodiment, the in-situ barrier is a non-selective barrier.

In one embodiment, the sealant comprises at least one composition selected from the group consisting of: a cement, a mixture of linear polymer, a mixture of linear polymer with a crosslinker, a mixture of polymerized monomer in-situ a resin-based fluid, an epoxy-based fluid, a magnesium-based slurry, a drilling mud, drilling sediments, slag, a clay-based slurry, an emulsion, a precipitate, an in-situ precipitate, and any combination thereof.

In one embodiment, the sealant comprises an inflatable elastomer that swells in the presence of an aqueous base fluid and a petroleum base fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting of: ethylene propylene, an ethylene-propylene-diene terpolymer rubber, a butyl rubber, a brominated butyl rubber, a chlorinated butyl rubber, a chlorinated polyethylene, a neoprene rubber, a styrene butadiene copolymer rubber, a sulfonated polyethylene, a ethylene acrylate rubber, a copolymer of ethylene oxide of epichlorohydrin, a silicone rubber, a fluorosilicone rubber, and any combination thereof.

In one embodiment, the in-situ barrier is a selective barrier.

In one embodiment, the sealant comprises swellable elastomer that swells in the presence of an aqueous-based fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting of: a graft copolymer of starch-polyacrylate acid, a graft copolymer of polyvinyl alcohol cyclic acid anhydride, a polyacrylamide, poly (acrylic acid acrylamide), a poly (2-hydroxyethyl methacrylate), a poly (2-hydroxypropyl methacrylate), an anhydride maleic isobutylene, acrylic acid type polymers, a vinyl acetate-acrylate copolymer, a polyethylene oxide polymer, a carboxymethyl cellulose-type polymer, a starch-polyacrylonitrile graft copolymer, a polymer comprising an expansive or swelling clay mineral, a polymer comprising a salt, and any combination thereof.

In one embodiment, the sealant comprises an inflatable elastomer that swells in the presence of an oil base fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting of: a natural rubber, a natural rubber, an acrylate butadiene rubber, an isoprene rubber, a chloroprene rubber, a butyl rubber, a rubber brominated butyl, a chlorinated butyl rubber, a chlorinated polyethylene, a neoprene rubber, a styrene butadiene copolymer rubber, a chlorinated polyethylene, a sulfonated polyethylene, an ethylene acrylate rubber, an ethylene oxide copolymer of epichlorohydrin, a epichlorohydrin terpolymer, an ethylene-propylene rubber, an ethylene vinyl acetate copolymer, an ethylene-propylene-diene terpolymer rubber, an ethylene vinyl acetate copolymer, a nitrile rubber, an acrylonitrile butadiene rubber, a rubber of hydrogenated acrylonitrile butadiene, a carboxylated high-acrylonitrile butadiene copolymer, a mixture of polyvinylchloride-nitrile butadiene, a fluorosilicone rubber, a silicone rubber, a poly 2, 2, 1-bicyclo heptene, an alkyl styrene, a polyacrylate rubber, an ethylene-acrylate terpolymer, a fluorocarbon polymer, copolymers of poly (vinylidene fluoride) and hexafluoropropylene, a terpolymer of poly (vinylidene fluoride) -hexafluoropropylene-tetrafluororethene, a polymer of poly (vinylidene fluoride) -polyvinyl methyl ether-tetrafluororetylene, perfluororelastomer, a highly fluorinated elastomer, a butadiene rubber, a polychloroprene rubber, a polyisoprene rubber, a polysulfide rubber, a polyurethane, a silicone rubber, a vinyl silicone rubber, a fluoromethyl silicone rubber, a fluorovinyl silicone rubber, a phenylmethyl silicone rubber, a styrene-butadiene rubber, a copolymer of isobutylene and isoprene, a brominated copolymer of isobutylene and isoprene, a chlorinated copolymer of isobutylene and isoprene, and any combination thereof.

In one embodiment, the sealant comprises a relative permeability modifier.

In one embodiment, the relative permeability modifier comprises a water soluble polymer, wherein the water soluble polymer comprises a hydrophobically modified polymer, wherein the hydrophobically modified polymer comprises a polymer backbone and a hydrophobic branch, wherein the branching hydrophobic comprises an alkyl chain of about 4 to about 22 carbons.

In one embodiment, the relative permeability modifier comprises a hydrophobically modified polymer, wherein the relative permeability modifier comprises a reaction product of at least one hydrophobic compound and at least one hydrophilic polymer.

In one embodiment, the relative permeability modifier comprises a hydrophobically modified polymer synthesized from a polymerization reaction comprising a hydrophilic monomer and a hydrophobically modified hydrophilic monomer, wherein the hydrophobically modified polymer comprises a hydrophobic branch, and wherein the hydrophobic branch comprises an alkyl chain of about 4 to about 22 carbons.

In one embodiment, the relative permeability modifier comprises a hydrophilically modified polymer, wherein the hydrophilically modified polymer is soluble in water.

The features and advantages of the present invention will be apparent to those skilled in the art. While many changes can be made by those skilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS These drawings illustrate certain aspects of some of the embodiments of the present invention, and should not be used to limit or define the invention.

Figure 1 illustrates a cross-sectional view of a modality of an underground environment with a well placed therein.

Figure 2 illustrates another cross-sectional view of a modality of an underground environment with a well placed therein.

Figure 3 illustrates an overhead view of a water saturation profile of an underground formation.

Figure 4 illustrates an overhead view of a water saturation profile of an underground formation according to an embodiment of the present invention.

Figure 5 illustrates a set of simulated results for total oil production according to one embodiment of the present invention.

Figure 6 illustrates a set of simulated results for total water production according to an embodiment of the present invention.

Figure 7 illustrates a side view of a water saturation profile of an underground formation in accordance with an embodiment of the present invention.

Figure 8 illustrates an overhead view of a water saturation profile of an underground formation in accordance with an embodiment of the present invention.

Figure 9 illustrates a set of simulated results for total oil production according to one embodiment of the present invention.

Figure 10 illustrates a set of simulated results for total water production according to one embodiment of the present invention.

Figure 11 illustrates an overhead view of a water saturation profile of an underground formation in accordance with an embodiment of the present invention.

Figure 12 illustrates an overhead view of a water saturation profile of an underground formation.

Figure 13 illustrates a set of simulated results for total oil production according to one embodiment of the present invention.

Figure 14 illustrates a set of simulated results for total water production according to one embodiment of the present invention.

Figure 15 illustrates an aerial view of a simulated underground well track useful to show one embodiment of the present invention.

Figure 16 illustrates an overhead view of a water saturation profile of an underground formation in accordance with an embodiment of the present invention.

Figure 17 illustrates another overhead view of a water saturation profile of an underground formation in accordance with an embodiment of the present invention.

Figure 18 illustrates yet another aerial view of a water saturation profile of an underground formation in accordance with an embodiment of the present invention.

DETAILED DESCRIPTION OF THE INVENTION The present invention relates generally to the production of hydrocarbons, and more particularly to a method and system for increasing the production of hydrocarbons in an existing well by forming an in-situ barrier to the flow that one or more fluids to modify the flow.

The methods and systems disclosed in this document can be conveniently used to modify the flow pattern within a reservoir to increase the amount of hydrocarbons recovered from the underground formation and decrease the amount of water produced from the underground formation. The system and method described in this document can be used with an existing well in an existing formation to allow the additional recovery of hydrocarbons without having to drill new wells, although new wells can be used in one modality. A number of exemplary forms are disclosed to carry out these functions.

In one embodiment, the present invention improves the production efficiency of hydrocarbons from a production reservoir by: providing a source of fluid in an underground formation, providing a well in an underground formation, providing an in-situ barrier in the underground formation that modifies the flow pattern of at least one fluid provided by the source of fluid flowing into the well.

The present invention provides improved methods, systems, and materials for modifying the flow pattern in a reservoir. The methods, systems, and materials can be used in vertical, deviated or horizontal wells, in consolidated and unconsolidated formations, in "open well" and / or under reamed endings, as well as in lined wells. If used in a coated well, the coating may be perforated to provide fluid communication between the well and the underground formation. The term "vertical well" is used in this document to refer to the portion of a well that will be finished that is substantially vertical or deviated from the vertical in an amount of up to about 15 °. The term "horizontal well" is used in this document to refer to the portion of a well that will be finished that is substantially horizontal, or at an angle of the vertical in the range of about 75 ° to about 105 °. All other angular positions refer to a deviated or inclined well. Since the present invention is applicable in horizontal and inclined wells, the terms "upper and lower" and "upper and lower part" as used herein are relative terms and are intended to apply for the respective positions within a well in particular, while the term "levels" refers to the respective spaced positions along the well. In the present description, the terms "upper", "upper part", and "above" refer to the portion of a well closest to the surface or well head while the terms "lower", "lower part" , and "below" refer to the portion of a well farthest from the surface or wellhead, regardless of the true vertical depth of any portion of the well.

The present invention can be used to form an in-situ barrier for fluid flow in an underground formation. For purposes of illustration, the present invention can be described in the context of a typical water pollution problem in which water is produced with hydrocarbons. Nevertheless, the methods and materials of the present invention may have application to other situations where blocking of the flow of fluids in addition to water or all fluids is necessary. Such applications include, without limitation, any operation of EOR including water flooding, gas flooding, steam injection, in-situ combustion operations, or any other operation designed to increase the production of hydrocarbons using a fluid.

With reference more particularly to the drawing, the Figure 1 illustrates a well 110 for producing hydrocarbons from an underground formation. Well 110 can be drilled using conventional drilling techniques, for example directional drilling techniques or other similar methods. The precise method used is not an important aspect of the present invention. In a certain exemplary embodiment, the well 110 is run with a coating column. The coating column can be cemented to the formation. There are a number of factors involved in deciding whether to coat the well 110 and whether to cement the lining to the formation. A person skilled in the art should know if well 110 needs to be coated. In most cases, it will be beneficial to do so.

The well 110 may extend through an underground formation area containing hydrocarbons 112 and into an interior water area 114. As used herein, the term "water" refers to any aqueous fluid and may include, for example, fresh water, salt water (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), or any combination thereof. As is commonly known in the art, there is generally no clear water-hydrocarbon boundary. The boundary may be more like an area composed of a mixture of varying proportions of hydrocarbon water. For the purpose of description, the water-hydrocarbon boundary area is illustrated as a broad line 116, it being understood, of course, that the water-hydrocarbon boundary area may be much more irregular and larger than the line. In one embodiment, water may come from a variety of sources, including but not limited to, in-situ water, injected water, or water entering the reservoir from an external source. For example, water can be introduced into the formation through an injection well 124 that can inject water into the reservoir through one or more fractures 126 as part of an EOR operation.

The lower end of the well is illustrated extending to a location below the boundary 116. Typically, while the hydrocarbons are produced (removed) from the area surrounding the well, the water boundary 116 rises until it is in contact with the fractures. at the end of the bottom of the well 118. In fact, hydrocarbons can be produced at a rate that causes the water boundary to extend up or "cone" around the well, accelerating the production of large volumes of water with hydrocarbons.

According to the present invention, a fracture 120 opens to extend from the well and may be located generally above the water boundary 116. The fracture 120 in this case is generally disk-shaped extending from the well 110 in all cases. the directions. As will be described, fracture technology exists to create open fractures of wells that extend in selected directions and distances and that have selected shapes. In one embodiment, it may be that the fracture is formed to extend from all sides about 152.4 m to about 304.8 m (about 500 feet to about 1000 feet) from the well through larger fractures. In this embodiment, the fracture 120 is filled with a sealant 122. Any fracture located below the water boundary, for example, the fracture 118, may also be filled with a sealant. The sealant 122 can be pumped into the fracture 120 as part of a treatment fluid, for example, in a slurry form and also within any fluid path in the form of holes intersecting the fracture.

One or more fractures can be formed in or along the well 110 using a variety of techniques. In an exemplary embodiment, the plurality of fractures are formed using a jet injection tool, such as that used in the SurgiFrac® fracturing service offered by Halliburton Energy Services in Duncan, Oklahoma. In this mode, the jet injection tool forms each fracture, one at a time. Each fracture can be formed by the following steps: (i) position the jet injection tool in the well at the location where the fracture will be formed, (ii) drill the deposit at the location where the fracture will be formed , and (iii) injecting a fracture fluid into the perforation at sufficient pressure to form a fracture along the perforation. How those experienced in the field will appreciate, there are many variations in this modality. For example, the fracture fluid can be pumped simultaneously down the ring while being pumped out of the jet injection tool to initiate the fracture. Alternatively, the fracture fluid can be pumped down the ring and not through the jet injection tool to initiate and propagate the fracture. In this version, the jet injection tool mainly forms the perforations..

In one embodiment, one or more fractures can be formed by stepwise fracturing. Stage fracturing can be carried out by a method comprising (i) detonating a charge in the well 110 at the location where a fracture is to form to form at least one hole in the deposit at that location, (ii) pump a fracture fluid into the perforation at sufficient pressure to propagate the fracture, (iii) install a plug in the well out of the fracture well, (iv) repeat steps (i) through (iii) until the desired number of fractures has been formed; and (v) removing the plugs after the completion of step (iv). As those experienced in the art will appreciate, there are many variants in the method of stage fracturing.

Fractures can take a variety of geometries including, but not limited to, transverse fractures, longitudinal fractures (eg, curtain wall fractures), or fractures that extend at an angle to the longitudinal axis of the well (p. eg, fractures that may extend along natural fracture lines). In some modalities, fractures may be formed along natural fracture lines and may be generally parallel to each other. The shape, size and orientation of the fracture can be determined by the orientations of the fluid nozzles and the movement of the same. When using jet injection radially from a vertical well, a fracture that extends transversely and can extend from about 15.24 m to about 304.8 m (about 50 feet to about 1000 feet) from the well can be formed. In other applications, such as water flooding, longitudinally extending fractures (eg, parallel to the well) can be formed to create a curtain wall fracture that can be used to form an in-situ curtain wall barrier. In one embodiment, fractures that are used to form in-situ barriers in multiple adjacent wells can be used to form in-situ barriers in cooperation.

After the well 110 has been coated and a fracture formed, the fracture may have a sealant placed therein. The sealant can be placed in the pressure fracture inside the fracture. This can be achieved by first isolating the perforations adjacent to the fracture using a plug (eg, a pierceable, recoverable or inflatable plug seated hydraulically) at the pipe end and establishing the plug in the casing; then pump the sealant in a fluid state through the pipe, then through the perforations and into the fracture to be sealed until a sufficient volume of sealant has been placed within the transverse fracture to provide the In-situ barrier to flow.

In one embodiment, the sealant that is used to provide the in-situ barrier can be any material capable of selectively or non-selectively reducing the flow of one or more fluids within an underground formation. As used in this context, a non-selective barrier is an in-situ barrier that is intended to substantially seal the fracture. A selective barrier is an in-situ barrier that is intended to modify the permeability or relative permeability (as described above) to allow fluids to selectively flow through the fracture. The sealant may comprise a cement, a linear polymer mixture, a linear polymer mixture with a crosslinker, a mixture of in-situ polymerized monomer, a resin-based fluid, an epoxy-based fluid, a magnesium-based slurry, a clay-based slurry (eg, a bentonite-based slurry), an emulsion, a precipitate (eg, a polymeric precipitate), or an in-situ precipitate. As used herein, an in-situ precipitate is a precipitate that forms within the underground formation, for example, using a polymer solution that is introduced into an underground formation followed by an activator. All of these sealants are capable of being placed in a fluid state with the property of becoming a viscous fluid or solid barrier for fluid migration after or during placement within the fracture. In one embodiment, the sealant is H2Zero ™ available from Halliburton Energy Services, Inc., Duncan, OK. Other sealants may include particles, drilling mud, sediments, and slag. Exemplary particles can be soil sediments in such a way that there would be a wide range of particle sizes and would produce permeability compared to the surrounding deposit. As used herein, the term "drilling mud" includes all types of drilling mud known to those experienced in the art including, but not limited to, petroleum-based muds, inverted emulsions, polymer-based muds, sludges based on clay (eg, drilling mud based on bentonite), and weighted mud.

In one embodiment, the sealant may comprise inflatable particles. As used herein, a particle is characterized as inflatable when swollen upon contact with an aqueous fluid (e.g., water), a petroleum-based fluid (e.g., petroleum), or a gas. Suitable inflatable particles are described in the following references, each of which is incorporated by reference herein in its entirety: U.S. Patent No. 3,385,367, U.S. Patent No. 7,059,415, U.S. Patent No. 7,578,347, U.S. Patent Application No. 2004/0020662, U.S. Patent Application No. 2007/0246225, U.S. Patent Application No. 2009/0032260 and O2005 / 116394.

The inflatable particles suitable for use with the embodiments of the present invention can be swollen generally up to 200% of their original size on the surface. Under conditions inside the well, this swelling can be more, or less, depending on the present conditions. For example, the swelling can be at least 10% under the conditions inside the well. In some embodiments, swelling can be up to 50% under conditions inside the well. Although the swelling rate can be of hours in some modalities, in certain modalities the swelling rate can be measured in minutes. The swelling rate is defined as the amount of time required by the swollen composition to substantially reach a state of equilibrium, where the swelling is within 5% of its final equilibrium state. However, as those skilled in the art, with the benefit of this disclosure, will appreciate, the actual swelling when the inflatable particles are included in a sealant may depend on, for example, the concentration of the inflatable particles included in the sealant, the temperature, the pressure, and the other components present in the well.

An example of an inflatable particle that may be suitable for use with the embodiments of the present invention comprises an inflatable elastomer that swells in the presence of a petroleum-based fluid or an aqueous-based fluid. Some specific examples of suitable swellable elastomers that swell in the presence of a petroleum-based fluid include, but are not limited to, natural rubbers, butadiene acrylate rubbers, isoprene rubbers, chloroprene rubbers, butyl rubbers, butyl rubbers. brominated, chlorinated butyl rubbers, chlorinated polyethylenes, neoprene rubbers, styrene butadiene copolymer rubbers, chlorinated polyethylene, sulfonated polyethylenes, ethylene acrylate rubbers, ethylene oxide epichlorohydrin copolymers, epichlorohydrin terpolymer, ethylene-propylene rubbers, copolymers of ethylene vinyl acetate, ethylene-propylene-diene terpolymer rubbers, ethylene vinyl acetate copolymer, nitrile rubbers, acrylonitrile butadiene rubbers, hydrogenated acrylonitrile butadiene rubbers, carboxylated high-acrylonitrile butadiene copolymers, butadiene blends of polyvinylchloride-nitrile, fluorosilicone rubbers, rubbers silicone, poly 2, 2, 1-bicyclic heptenes (polynorbornene), alkyl styrenes, polyacrylate rubbers such as ethylene-acrylate copolymer, ethylene-acrylate terpolymers, fluorocarbon polymers, copolymers of poly (vinylidene fluoride) and hexafluoropropylene, terpolymers of poly (vinylidene fluoride), hexafluoropropylene, and tetrafluororetylene, terpolymers of poly (vinylidene fluoride), polyvinyl methyl ether and tetrafluororetylene, perfluororelastomers such as perfluororelastomers of tetrafluororetylene, highly fluorinated elastomers, butadiene rubber, polychloroprene rubber, polyisoprene rubber , polinorbornenes, polysulphide rubbers, polyurethanes, silicone rubbers, vinyl silicone rubbers, fluoromethyl silicone rubber, fluorovinyl silicone rubbers, phenylmethyl silicone rubbers, styrene-butadiene rubbers, isobutylene and isoprene copolymers known as butyl rubbers, brominated copolymers of isobutylene and isoprene, chlorinated copolymers of isobutylene and isoprene, and any combination thereof . An example of a commercially available product comprising such swellable particles may include a product commercially available from Easy Well Solutions of Norway under the trade name "EASYWELL".

Suitable examples of fluoroelastomers that swell in the presence of a petroleum-based fluid are copolymers of vinylidene fluoride and hexapropylene and terpolymers of vinylidene fluoride, hexafluoropropylene and tetrafluoroethylene. Fluoroelastomers suitable for use in the disclosed invention are elastomers which may comprise one or more units of vinylidene fluoride (VF2 or VdF), one or more units of hexafluoropropylene (HFP), one or more units of tetrafluoroethylene (TFE). , one or more units of chlorotrifluoroethylene (CTFE), and / or one or more units of perfluoro (alkyl vinyl ether) (PEVE), and perfluoropropyl vinyl ether (PPVE). These elastomers can be homopolymers or copolymers. Particularly suitable are fluoroelastomers containing vinylidene fluoride units, hexafluoropropylene units, and occasionally, tetrafluoroethylene units and fluoroelastomers containing vinylidene fluoride units, perfluoroalkyl perfluorovinyl units, and tetrafluoroethylene units, such as the fluoroelastomer type vinylidene fluoride known under the trade designation "AFLAS®" available from Asahi Glass Co., Ltd. of Tokyo, Japan. Especially suitable are the copolymers of vinylidene fluoride and hexafluoropropylene units. If the fluoropolymers contain vinylidene fluoride units, the polymers may contain VF2 units of up to 40 mole%, eg, 30-40 mole%. If the fluoropolymers contain hexafluoropropylene units, the polymers can contain HFP units of up to 70 mole%. If the fluoropolymers contain tetrafluoroethylene units, the polymers may contain TFE units of up to 10 mol%. When the fluoropolymers contain chlorotrifluoroethylene, the polymers may contain CTFE units of up to 10% by mole. When the fluoropolymers contain perfluoro (methyl vinyl ether) units, the polymers may contain PMVE units of up to 5 mole%. When the fluoropolymers contain perfluoro (ethyl vinyl ether) units, the polymers may contain PEVE units of up to 5 mole%. When the fluoropolymers contain perfluoro (propyl vinyl ether) units, the polymers may contain PPVE units of up to 5 mole%. The fluoropolymers can contain 66% -70% fluorine. A commercially available suitable fluoroelastomer is the one known under the trade designation "TECHNOFLON FOR HS®" sold by Ausimont USA of Thorofare, New Jersey. This material contains "Bisphenol AF" manufactured by Halocarbon Products Corp. of River Edge, New Jersey. Another commercially available fluoroelastomer is known under the trade designation "VITON® AL 200", by DuPont Performance Elastomers of La Place, Louisiana, which is a terpolymer of VF2, HFP, and TFE monomers containing 67% fluorine. Another commercially available suitable fluoroelastomer is "VITON® AL 300", by DuPont Performance Elastomers of La Place, Louisiana. A mixture of known terpolymers can also be used under the trade designations "VITON® AL 300" and "VITON® AL 600" (eg, one third of AL-600 and two thirds of AL-300); both available from DuPont Performance Elastomers of La Place, Louisiana. Other useful elastomers include products known under the trade designations "7182B" and "7182D" from Seáis Eastern of Red Bank, N.J .; the product known under the trade designation "FL80-4" available from Oil States Industries, Inc., of Arlington, Texas; and the product known under the trade designation "DMS005" available from Duromould, Ltd. of Londonderry, Northern Ireland.

A process for making an inflatable elastomer useful in the present invention may involve grafting an unsaturated organic acid molecule. A common example of an unsaturated organic acid used for this purpose is maleic acid. Other molecules that can be used include mono- and di-sodium salts of maleic acid and potassium salts of maleic acid. Although in principle other unsaturated carboxylic acids can also be grafted onto commercial unsaturated elastomers, acids that exist in solid form may not require additional steps or manipulation, as will be readily apparent to those who have reasonable experience in the matter of chemistry. Mixing other unsaturated acids such as acrylic acid and methacrylic acid is also possible but may be more difficult since they are liquid at room temperature. Unsaturated acids such as palmitoleic acid, oleic acid, linoleic acid, and linolenic acid can also be used. The initial reaction leads to a relatively non-porous "graft of acid" rubber. In order to improve the lynching of the elastomers, the addition of a small amount of alkali such as soda ash, together with or separated from the unsaturated acid, leads to the formation of an inflatable porous acid graft rubber. In the composition, micro-porosities are formed, allowing a fluid to quickly reach the interior region of a molded part and increase the rate and extent of swelling. An organic peroxide vulcanization agent can be employed to produce a vulcanized, porous, swellable, acid graft rubber formulation. In one embodiment, 100 phr of EPDM, 5-100 phr of maleic acid, 5-50 phr of sodium carbonate, and 1-10 phr of dicumyl peroxide as vulcanizing agent showed at least 150% swelling of the elastomer when exposed both to water at 100 ° C for 24 hours and at room temperature for 24 hours in kerosene. Other commercially available grades of peroxide may be employed as organic, as well as other vulcanization agents. The resulting elastomeric compositions can be described as non-porous, or porous and swollen, acid graft rubbers that may or may not be vulcanized. The terms "vulcanized" and "crosslinked" are used interchangeably in this document, although vulcanization technically refers to a physical-chemical change that results from crosslinking the unsaturated hydrocarbon chain of polyisoprene with sulfur, usually with the application of hot. Relatively hydrophobic linear or branched-chain polymers and relatively hydrophilic water-soluble monomers, whether inserted into the polymer backbone or mixed therein, can act together to profitably increase the swelling capacity in water and / or oil of petroleum reservoir elements comprising one or more apparatuses of the invention. In particular, the use of unsaturated organic acids, anhydrides, and their salts (for example maleic acid, maleic anhydride, and their salts), offer a commercially feasible way to develop inexpensive composites with good swelling capacity in water and / or hydrocarbon fluid, depending on the type of inorganic additives and monomers used.

Elastomers such as nitrile rubber, hydrogenated nitrile rubber (HNBR), fluoroelastomers, or acrylate-based elastomers, or their precursors, if added in varying amounts to an EPDM polymer or its precursor monomer mixture, together with a sufficient amount (1 to 10 phr) of an unsaturated organic acid, anhydride, or salt thereof, such as maleic acid, optionally combined with a sufficient amount (of 1 to 10 phr) of an inorganic swelling agent such as sodium carbonate, Sodium, can produce an inflatable elastomer in water that has a variable capacity of little oil swelling. The addition to the monomer mixture, or to the elastomer after polymerization, of a sufficient amount (from 0.5 to 5 phr) of a highly unsaturated compound such as 2-acrylamido-2-methylpropane sulfonic acid (AMPS), it results in a water swellable elastomer having a swelling capacity in variable petroleum, and which is further inflatable in low pH fluids such as determination fluids containing zinc bromide. A second addition of a sufficient amount (from 1 to 10 phr more than the original addition) of inorganic swelling agent improves the swelling capacity in brine at low pH, high concentration. Finally, the addition of a sufficient amount (1 to 20 phr) of zwitterionic polymer or copolymer of a zwitterionic monomer with an unsaturated monomer results in a crosslinked elastomer. The amounts of the different ingredients in each stage can be varied as is suitable for the particular purpose in the hand. For example, if one simply wants to produce a highly cross-linked elastomer, moderately water-swellable (100% swelling) that has very low swelling capacity in oil but very high swelling capacity in low pH fluids, one would use a recipe for 60 to 80 phr of EPDM, and 20 to 40 phr of nitrile or HNBR, and 4 to 5 phr of AMPS, as well as about 15 to 20 phr of polymer or zwitterionic monomer.

Another reaction scheme useful in the present invention, which enables a low-cost process for making inflatable elastomers, involves the use of AMPS monomer and similar sulfonic acid monomers. Since the AMPS monomer is chemically stable up to 350 ° F (177 ° C), mixtures of EPDM and AMPS monomer that may or may not be inserted into the EPDM will function as a water-swellable elastomer resistant to high temperatures. The use of similar AMPS and monomer can be similarly used to functionalize any commercial elastomer to make a water-swellable elastomer resistant to high temperatures. One advantage of using AMPS is that it is routinely used in the oil industry in lossy circulation fluids and is very resistant to chemicals and environments within the well.

Other inflatable elastomers which behave similarly with respect to aqueous fluids may also be suitable. Some specific examples of suitable swellable elastomers that swell in the presence of an aqueous base fluid include, but are not limited to, starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, polyacrylamide, poly (acrylic acid-co-acrylamide), poly (2-hydroxyethyl methacrylate), poly (2-hydroxypropyl methacrylate), isobutylene maleic anhydride, acrylic acid-type polymers, vinyl acetate-acrylate copolymer, oxide polymers, polyethylene, carboxymethyl cellulose type polymers, starch-polyacrylonitrile graft copolymers and the like and swelling or expansive clay minerals such as sodium bentonite having montmorillonite as the main ingredient, and any combination thereof.

Additional particles swellable in water may comprise particulate matter embedded in a matrix material. An example of such particulate matter is salt, preferably dissociation, which may be composed uniformly in a base rubber. Suitable salts may include, but are not limited to, acetates, bicarbonate, carbohydrates, formations, halides (MxHy) (H = Cl, Br or I), hydrosulfides, hydroxides, imides, nitrates, nitrides, nitrites, phosphates, sulphides, sulfates , and any combination thereof. Also, other salts may be applied where the cation is a NH4C1 similar to non-metallic. CaCl2 may be useful in view of its divalent characteristic and due to its reduced tendency to leach out a base rubber due to the reduced mobility of the relatively large Ca atom in the base rubber.

To limit the leaching of the salt from the swellable elastomer, the swellable particles suitably include a hydrophilic polymer containing polar groups of either hydrogen or nitrogen in the main chain or side groups of polymer matrix material. These side groups may be partially or completely neutralized. Hydrophilic polymers of this type are, for example, alcohols, acrylates, methacrylates, acetates, aldehydes, ketones, sulfonates, anhydrides, maleic anhydrides, nitriles, acrylonitriles, amines, amides, oxides (polyethylene oxide), types of cellulose which include all derivatives of these types, all copolymers including one of all the inserted variants mentioned above. In one case, a ternary system can be applied which includes an elastomer, a polar SAP and a salt, whereby the polar SAP is inserted into the main chain of the elastomer. Said system has the advantage that the polar SAP particles tend to retain the salt particles in the elastomer matrix thereby reducing the leaching of the elastomer salt. The polar salt is bound by electrostatic forces to the polar SAP molecules that are grafted to the rubber backbone.

It is also possible to use combinations of suitable swelling elastomers. In certain embodiments, some of the elastomers that swell in petroleum-based fluids may also be swollen in water-based fluids. Suitable elastomers that can swell in both water-based and petroleum-based fluids include, but are not limited to, ethylene propylene rubbers, ethylene-propylene-diene terpoly rubbers, butyl rubbers, brominated butyl rubbers, chlorinated butyl rubbers, chlorinated polyethylenes, neoprene rubbers, styrene butadiene copolymer rubbers, sulfonated polyethylenes, ethylene acrylate rubbers, ethylene oxide copolymer of epichlorohydrin, silicone rubbers and fluorosilicone rubbers, and any combination thereof. Those skilled in the art, with the benefit of this disclosure, will know the proper fluid to use in order to inflate the composition of the particular swellable elastomer.

In certain embodiments, the inflatable elastomers may be crosslinked and / or highly crosslinked. Other swellable elastomers that behave in a similar manner with respect to fluids may also be suitable. Those skilled in the art, with the benefit of this disclosure, will be able to select the appropriate swelling elastomers based on a variety of factors, including the application in which the composition will be used and the desired swelling characteristics.

When used, the swellable particles can generally be included in the sealant embodiments in an amount sufficient to provide the desired barrier properties. In some embodiments, the inflatable particles may be placed in a fracture or space in a treatment fluid comprising an amount of up to 50% by volume of the treatment fluid. In some embodiments, the inflatable particles may be present in a range of 5% to 95% by volume of the treatment fluid that is used to place the particles.

In addition, the inflatable particles that are used can have a wide variety of individual particle shapes and sizes suitable for use with the embodiments of the present invention. By way of example, the inflatable particles can have a well-defined physical form as well as an irregular geometry, including the physical form of platelets, chips, fibers, flakes, slats, bars, ribbons, spheroids, beads, pills, tablets, or any another physical form. In some embodiments, the inflatable particles may have a particle size in the range of about 5 microns to about 1500 microns. In some embodiments, the inflatable particles may have a particle size in the range of about 20 microns to about 500 microns. However, particle sizes outside these defined ranges may also be suitable for particular applications.

In one embodiment, the sealant may comprise a cement. Any suitable cement known in the art can be used as the sealant. An example of a suitable cement includes hydraulic cement, which may comprise calcium, aluminum, silicon, oxygen, and / or sulfur and which is set and hardened by reaction with water. Examples of hydraulic cements include, but are not limited to a Portland cement, a pozzolanic cement, a gypsum cement, a high alumina segment, a silica cement, a high alkalinity cement, or combinations thereof. Preferred hydraulic cements are Portland cements of the type described in Specification 10 of the American Petroleum Institute (API, American Petroleum Institute), Fifth Edition, July 1, 1990, which is hereby incorporated by reference herein in its entirety. The cement may be, for example, a Portland cement of class A, B, C, G, or H. Another example of a suitable cement is microfine cement, for example, ICRODUR RU microfine cement available from Dyckerhoff GmBH of Lengerich, Germany. It is also possible to use combinations of cements and inflatable particles.

In one embodiment, the sealant may comprise a water-soluble relative permeability modifier. As used herein, "relative permeability modifier" refers to a compound that is capable of reducing the permeability of an underground formation for water-based fluids without substantially changing its permeability to hydrocarbons. Generally, water-soluble relative permeability modifiers suitable for use in the present invention can be any water-soluble relative permeability modifier suitable for use in underground operations. In some embodiments, water-soluble high relative modifiers of weakness include a hydrophobically modified polymer. As used herein, "hydrophobically modified" refers to the incorporation into the hydrophilic polymer structure of hydrophobic groups, wherein the alkyl chain length is from about 4 to about 22 carbons. In other embodiments, the water-soluble relative permeability modifiers comprise a hydrophilically modified polymer. As used herein, "hydrophilically modified" refers to the incorporation into the hydrophilic polymer structure of hydrophilic groups. In still another embodiment, the water-soluble relative permeability modifiers comprise a water-soluble polymer without hydrophobic or hydrophilic modification.

Hydrophobically modified polymers suitable for use in the present invention typically have molecular weights in the range of about 100,000 to about 10,000,000. In some embodiments, a molar ratio of a hydrophilic monomer with the hydrophobic compound in the hydrophobically modified polymer is in the range of about 99.98: 0.02 to about 90:10, wherein the hydrophilic monomer is a calculated amount present in the hydrophilic polymer. In certain embodiments, the hydrophobically modified polymers may comprise a polymer backbone, the polymer backbone comprising polar heteroatoms. Generally, polar heteroatoms within the polymer backbone of the hydrophobically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorus.

In one embodiment, the hydrophobically modified polymers can be a reaction product of a hydrophilic polymer and a hydrophobic compound. Hydrophilic polymers suitable for forming the hydrophobically modified polymers that are used in the present invention must be capable of reacting with hydrophobic compounds. Suitable hydrophilic polymers include, homo-, co-, or terpolymers such as, but not limited to, polyacrylamides, polyvinylamides, poly (vinylamines / vinyl alcohols), and alkyl acrylate polymers in general. Further examples of alkyl acrylate polymers include, but are not limited to, polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly (acrylamide / dimethylaminoethyl methacrylate), poly (methacrylic acid / dimethylaminoethyl methacrylate), poly (2-acrylamide-2) -methyl propane sulfonic acid / dimethylaminoethyl methacrylate), poly (acrylamide / dimethylaminopropyl methacrylamide), poly (acrylic acid / dimethylaminopropyl methacrylamide), and poly (methacrylic acid / dimethylaminopropyl methacrylamide). In certain embodiments, the hydrophilic polymers comprise a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophobic compounds. In some embodiments, the hydrophilic polymers comprise pendant dialkyl amino groups. In some embodiments, the hydrophilic polymers comprise a pendant dimethyl amino group and at least one monomer comprising dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide. In certain embodiments, the hydrophilic polymers comprise a polymer backbone, the polymer backbone comprises polar heteroatoms, wherein the polar heteroatoms present within the polymer backbone of the hydrophilic polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorus. Suitable hydrophilic polymers comprising polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers such as, but not limited to, celluloses, chitosans, polyamides, polyetherramides, polyethyleneimines, polyhydroxyetheramines, polyisins, polysulfones, gums, starches , and derivatives thereof. In one embodiment, the starch is a cationic starch. A suitable cationic starch can be formed by reacting a starch, such as corn, waxy corn, potato, and tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.

Hydrophobic compounds that are capable of reacting with the hydrophilic polymers include, but are not limited to, alkyl halides, their formats, sulfates, and organic acid derivatives. Examples of organic acid derivatives include, but are not limited to, octenyl succinic acid; dodecenyl succinic acid; and anhydrides, esters, and octenyl succinic acid amides or dodecenyl succinic acid. In certain embodiments, the hydrophobic compounds can have an alkyl chain length of about 4 to about 22 carbons. For example, where the hydrophobic compound is an alkyl halide, the reaction between the hydrophobic compound and the hydrophilic polymer can result in the quaternization of at least some of the hydrophilic polymer amino groups with an alkyl halide, wherein the length Alkyl chain is about 4 to about 22 carbons.

In other embodiments, the hydrophobically modified polymers that are used in the present invention must be prepared from the polymerization reaction of at least one hydrophilic monomer and at least one hydrophobically modified hydrophilic monomer. Examples of suitable methods of their preparation are described in U.S. Patent No. 6,476,169, the disclosure of which is hereby incorporated by reference in its entirety.

A variety of hydrophilic monomers can be used to form the hydrophobically modified polymers useful in the present invention. Examples of suitable hydrophilic monomers include, but are not limited to homo-, co-, and terpolymers of acrylamide, 2-acrylamide-2-methyl propane sulfonic acid,?,? -dimethyl acrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropyl methacrylamide, vinyl amine, vinyl acetate, trimethylammonioethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulphonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N, N-diallylacetamide, dimethyldiallyl halide ammonium, itaconic acid, styrene sulfonic acid, methacrylamidoethylmethyl ammonium halide, quaternary acrylamide salt derivatives, and quaternary salt derivatives of acrylic acid.

A variety of hydrophobically modified hydrophilic monomers can also be used to form the hydrophobically modified polymers useful in the present invention. Examples of suitable hydrophobically modified hydrophilic monomers include, but are not limited to, alkyl acrylates, alkyl methacrylates, alkyl acrylamides, alkyl methacrylamides, dimethylammoniomethyl alkyl methacrylate halides, and dimethylammonium propyl alkyl methacrylamide halides, wherein the groups of alkyl have from about 4 to about 22 carbon atoms. In certain embodiments, the hydrophobically modified hydrophilic monomer comprises octadecyldimethylammonioethyl methacrylate bromide, hexadecyldimethylammonioethyl methacrylate bromide, hexadecyldimethylammonium propyl methacrylamide bromide, 2-ethylhexyl methacrylate, or hexadecyl methacrylamide.

The hydrophobically modified polymers formed from the above-described polymerization reaction can have molecular weights estimated in the range of about 100,000 to about 10,000,000 and molar ratios of hydrophilic monomer (s) with hydrophilic monomer (s) modified (s) hydrophobically in the range of about 99.98: 0.02 to about 90:10. Suitable hydrophobically modified polymers having molecular weights and molar ratios in the ranges set forth above include, but are not limited to, acrylamide / copolymer of octadecyldimethylammoniomethyl methacrylate bromide, dimethylaminoethyl methacrylate / copolymer of hexadecyldimethylammoniomethyl methacrylate bromide, dimethylaminoethyl methacrylate / vinyl pyrrolidone / terpolymer of hexadecyldimethylammoniomethyl methacrylate bromide and acrylamide / propane sulphonic acid of 2-acrylamido-2-methyl / terpolymer of 2-ethylexyl methacrylate.

In other embodiments, the water-soluble relative permeability modifiers comprise a hydrophilically modified polymer. Polymers modified hydrophilically suitable for use with the present invention typically have molecular weights in the range of about 100,000 to about 10,000,000. In ain embodiments, the hydrophilically modified polymers comprise a polymer backbone, the polymer backbone comprises polar heteroatoms. Generally the polar heteroatoms within the polymer backbone of the hydrophilically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorus.

In ain embodiments, the hydrophilically modified polymer can be a reaction product of a hydrophilic polymer and a hydrophilic compound. Suitable hydrophilic polymers for forming the hydrophilically modified polymers that are used in the present invention must be capable of reacting with the hydrophilic compounds. In ain embodiments, suitable hydrophilic polymers include homo-, co-, or terpolymers such as but not limited to, polyacrylamides, polyvinylamides, poly (inilaminas / vinyl alcohol), and polymers of alkyl acrylate in general. Additional examples of polymers of acrylate include, but are not limited to methacrylate, polydimethylaminoethyl, methacrylamide polidimetilarrtinopropilo, poly (acrylamide / dimethylaminoethyl methacrylate), poly (methacrylic acid / dimethylaminoethyl methacrylate acid), poly (2-acrylamide-2 propane sulfonic -methyl / dimethylaminoethyl methacrylate) acid, poly (acrylamide / dimethylaminopropyl methacrylamide), poly (acrylic acid / dimethylaminopropyl methacrylamide) and poly (methacrylic acid / methacrylamide dimethylaminopropyl). In ain embodiments, the hydrophilic polymers comprise a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophilic compounds. In some embodiments, the hydrophilic polymers comprise pendant dialkyl amino groups. In some embodiments, the hydrophilic polymers comprise a pendant dimethyl amino group and at least one monomer comprising dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide. In other embodiments, the hydrophilic polymers comprise a polymer backbone comprising polar heteroatoms, wherein the polar heteroatoms present in the polymer backbone of the hydrophilic polymers include, but are not limited to, oxygen, nitrogen, sulfur, or match. Suitable hydrophilic polymers comprising polar heteroatoms within the backbone polymer include homopolymers, copolymers, or terpolymers such as but not limited to, celluloses, chitosans, polyamides, polyetheramides, polyethyleneimines, polihidroxieteraminas, poliisinas, polysulfones, gums, starches , and derivatives thereof. In one embodiment, the starch is a cationic starch. A suitable cationic starch can be formed by reacting a starch, such as corn, waxy maize, potato, tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.

Hydrophilic compounds suitable for the reaction with the hydrophilic polymers include polyethers comprising halogens; sulfonates; and organic acid derivatives. Examples of suitable polyethers include, but are not limited to, polyethylene oxides, polypropylene oxides, and polybutylene oxides, and copolymers, terpolymers, and mixtures thereof. In some embodiments, the polyether comprises a methyl ether of polyethylene oxide terminated from epichlorohydrin.

Hydrophilically modified polymers that are formed from the reaction of a hydrophilic polymer with a hydrophilic compound can have molecular weights estimated in the range of about 100,000 to 10,000,000 and can have weight ratios of hydrophilic polymers with polyethers in the range from 1: 1 to about 10: 1. Suitable hydrophilically modified polymers having molecular weights and weight ratios in the ranges set forth above include, but are not limited to, the reaction product of polydimethylaminoethyl methacrylate and methyl ether of polyethylene oxide terminated by epichlorohydrin; the reaction product of polydimethylaminopropyl methacrylamide and methyl ether of polyethylene oxide terminated by epichlorohydrin; and the reaction product of poly (acrylamide / dimethylaminopropyl methacrylamide) and methyl ether of polyethylene oxide terminated by epichlorohydrin. In some embodiments, the hydrophilically modified polymer comprises the reaction product of polydimethylaminoethyl methacrylate and methyl ether of polyethylene oxide terminated by epichlorohydrin having a weight ratio of polydimethylaminoethyl methacrylate with methyl ether of polyethylene oxide terminated by epichlorohydrin. about 3: 1.

In yet other embodiments, the water-soluble relative permeability modifiers comprise a water-soluble polymer without hydrophobic or hydrophilic modification. Examples of suitable water-soluble polymers without hydrophobic or hydrophilic modification include, but are not limited to, homo-, co-, and terpolymers of acrylamide, 2-acrylamide-2-methyl propane sulfonic acid, N, N-dimethylacrylamide, vinyl pyrrolidone , dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinyl amine, vinyl acetate, trimethylammonioethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulphonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N , N-diallylacetamide, dimethyldiallylammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethylmethyl ammonium halide, quaternary acrylamide salt derivatives, and quaternary salt derivatives of acrylic acid.

In one embodiment, a hydrocarbon deposit in an underground formation may have one or more production wells. In addition, the hydrocarbon reservoir may have one or more injection wells to provide a source of fluid to supply a fluid driving force for the production of hydrocarbons. As used herein, a "fluid source" refers to any source of one or more fluids flowing through the underground formation between perforations or fractures in an individual well or between separate wells. An injection well can be drilled for the specific purpose of injecting fluids to provide the fluid source, or an existing well can be converted from a production well to an injection well. In another embodiment, a natural source of fluid that provides a driving force may be present in the underground formation in the form of existing water, external water entering the reservoir, or natural gas pressure within the underground formation. Alternatively, water can flow into the underground formation from a nearby water source (eg, an aquifer at the edge) to create a source of fluid that provides a driving force within the underground formation. In this case, the underground formation may not require injection wells for the production of hydrocarbons.

The flow of hydrocarbon fluids within the reservoir can be modified through the use of an in-situ barrier comprising a fracture containing a sealant. The use of an in-situ barrier can be used with selective or non-selective flow barriers to modify the flow pattern within an entire deposit. In one embodiment, a relative permeability modifier may allow oil to selectively flow through the in-situ barrier relative to an aqueous fluid. In another embodiment, a plurality of in-situ barriers may have variable permeability, whose placement and geometries may act as a series of barriers or deflectors to guide the flow of at least one desired fluid to a production well. Without wishing to be bound by theory, it is believed that a plurality of selectively placed fractures with selective or non-selective barriers for the fluid to flow can be used to modify the flow regime within the hydrocarbon reservoir to improve the volumetric efficiency of sweeping hydrocarbons in the formation. In addition, the sealant and fluid used to provide the driving force for the flow and sweep of the hydrocarbon fluids can be selected to maximize the amount of hydrocarbons recovered in a hydrocarbon reservoir. Flow patterns within the hydrocarbon reservoir can be determined by using a simulator program using any simulator capable of calculating the flow regime within an underground environment. Suitable simulators for use in hydrocarbon deposits are known to those skilled in the art.

In an embodiment shown in Figure 1, an injection well 124 can be drilled remote from, but generally parallel to, the existing well 110. In one embodiment, the well 110 can be drilled for the purpose of modifying the flow of at least one fluid inside the underground reservoir. In a certain embodiment, the injection well 124 is pierced close to the sealed fractures 118, 120. As those skilled in the art will appreciate, the injection well 124 may alternatively be formed prior to the formation of the well 110, or it may be a converted production well. Once the injection well 124 has been formed and the selected fracture or fractures 118, 120 sealed, flood fluid can be pumped into the injection well 124. While the flood fluid is pumped into the reservoir 112 is a flood propagation front. The flood front can be diverted around the sealed fracture 120. At the same time, the hydrocarbons are drained into the fractures 128. While the production fracture 128 begins to produce high rates of flood fluid, it can be sealed. A bridge plug or other zone isolation device can be installed in the well 110 out of the fracture well 128 when the fracture is sealed. A new production fracture can then be created to additionally produce hydrocarbons from the hydrocarbon deposit. This isolation process is repeated while producing sufficiently high flood fluid ratios from successive transverse fractures until all transverse fractures have been sealed.

In one embodiment, the flow of fluids in a hydrocarbon reservoir can be modified on a broad field basis. The injection well 124 may be located in an existing injection pattern as is known to those skilled in the art. For example, existing injection patterns of 5 points, 7 points, or line driving may have existing injection wells for use in this method. As will be appreciated by those skilled in the art, the selection of a well for use as an injection well can change during the life of the hydrocarbon deposit. The production well 110 may be an existing well or may be drilled for the purpose of recovering fluids. In another embodiment, the well 110 and any fracture associated with the well 110 may be drilled or used for the purpose of modifying the flow pattern of at least one fluid within an underground reservoir without being used to produce a fluid. The selection of fractures or locations to create new fractures can be chosen to increase the sweep efficiency of fluids moving through the formation.

In an exemplary variant of the method illustrated in Figure 1, the fracture 120 may only be partially sealed in the area near the well instead of completely sealed all the way to its tip. The benefit of sealing the area near the well is that if the injection fluid moves faster in this area the flow of the injection fluid can be partially diverted to improve the sweep.

As for Figure 2, another embodiment of the method for increasing the production of hydrocarbons according to the present invention is disclosed. In this embodiment, the flood fluid is introduced into the tank 212 through a pipe 260, which is installed inside the well 224 instead of a separate injection well. The pipe 260 injects the flood fluid into the tank 212 from the foot 240 of the well 224, which may include one or more fractures 242 through which the fluid is injected into the formation. The hydrocarbons can be produced through one or more fractures 290 to the ring 265 that is formed between the pipe 260 and the liner 262. The shutter 270 can be used to seal the end of the pipe 260, so that the flood fluid does not enter the ring 265. In this embodiment, additional wells 210, 280 can be used to produce fluids that can be conducted at least in part by the fluids that are injected from the well 224. These additional wells may have one or more fractures 286, 288 with a sealant composition 222 placed therein to affect the flow pattern in the hydrocarbon reservoir. As will be appreciated by one skilled in the art, a plurality of fractures of different shapes can be used to affect the flow of fluids within the hydrocarbon reservoir. In another embodiment, wells 210, 280 and any fracture associated with the wells (eg, fractures 286, 288) can be drilled or used for the purpose of modifying the flow pattern of at least one fluid within a underground reservoir without being used to produce a fluid. In this mode, the additional well (not shown in Figure 2) can be used to produce one or more fluids from the underground reservoir.

Once the flood fluid ratio reaches a high enough value, fractures used for production 290 can be sealed using the techniques described above and new fractures or production drilling can be created. This process can be repeated for successive fractures while the flood front 216 moves to the area near the production well.

This document also discloses that it may be useful to increase the production of hydrocarbons and / or reduce the production of water from an underground formation. The system generally comprises a source of fluid within an underground formation to provide a fluid driving force within the underground formation, a well placed in the underground formation to produce a production fluid from the underground formation, and an internal barrier. situ placed within the underground formation, where the in-situ barrier modifies the flow of at least one fluid driven by the fluid driving force within the underground formation. Each component of the system is as described above and may include any of the optional features disclosed in this document. As those skilled in the art will appreciate from the disclosure, there are many different ways to accommodate and provide wells, in-situ barriers to flow, and the fluid provided by the fluid source, and many different ways to recover the hydrocarbons in the deposit.

To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are provided. In no way should the following examples be read to limit, or define, the scope of the invention.

Example 1 A reservoir simulation is used to simulate an in-situ barrier placed in an underground formation using a horizontal well for this prophetic example. Such a simulator is a QuikLook finite difference numerical simulator version 4.1 provided by Halliburton Energy Services, Inc. The horizontal well has a production length of about 475.5 m (1560 ft). The input properties for the underground formation simulation include: 792.5 m by 792.5 m (2600 ft by 2600 ft), 149.3 m (490 ft) thick with an average formation porosity of 0.24, horizontal permeability in the direction longitudinal 30 md, horizontal permeability in the latitudinal direction of 45 md and vertical permeability of 3 md. The initial saturation of water in the oil zone is 0.37. There is an active and aquifer edge at the bottom as the source of invasion of water flow to the production well.

Figure 3 depicts a water saturation profile in the formation after 911,476 days without an in-situ barrier using deposit simulation. Water saturation is shown on a scale of 0.00 to 1.00 with 1.00 being 100% water saturation. The water saturation scale is shown in the sidebar. The results of the simulation show that the water front begins to break through the production well.

For comparison, Figure 4 depicts a water saturation profile in the formation after 914.01 days with an in-situ barrier using deposit simulation. The results of the simulation show that the water front is being blocked effectively from the production well. The saturation of water, in about 914 days, is lower in the horizontal production well than in the case without an in-situ barrier. It is expected that the increased sweeping of the water will result in an increased production of hydrocarbons from the well.

Figure 5 and Figure 6 represent the total oil production and total water production for both the base case without an in-situ barrier and the case of comparison with the in-situ barrier that are represented in Figure 4. The figures show that water production is higher (line 508) and oil production is lower (line 502) without an in-situ barrier compared to water production (line 506) and production of oil (line 504) with an in-situ barrier. The increase in oil production is approximately 5.4% and the decrease in water production is approximately 6.41%. The increase in oil production is worth millions of dollars and the decrease in water production represents significant savings in the cost of wasting water disposal.

Example 2 The same deposit simulation described above in Example 1 is used to simulate an injector and a producer in a line driving configuration for this predictive example. A well is located between the injector and the producer and is used to place an in-situ barrier within the formation.

Figure 7 represents a side view of a water saturation profile in the formation after about 3614 days with an in-situ barrier using the deposit simulation. The results of the simulation show that the water front is effectively slowed down by the in-situ barrier between the injector and the producer. Figure 8 depicts an aerial view of the water saturation profile shown in Figure 7. Figure 8 similarly represents that the water front is forced to move around the in-situ barrier in the formation in order to reach the production well.

Figure 9 and Figure 10 represent the total oil production and total water production for the simulation shown in Figure 7 and Figure 8. In addition to the simulation results shown in Figure 7 and Figure 8, Figure 9 and Figure 10 show the results for a simulation without an in-situ barrier between the producer and the injector and for a case where the in-situ barrier moves closer to the production well. Figure 9 shows that oil production is lower without an in-situ barrier (line 510) than any of the cases with an in-situ barrier (line 514) or the nearest in-situ barrier (line 512). Figure 10 shows that water production is greater without an in-situ barrier (line 520) than any of the cases with an in-situ barrier (line 516) or the nearest in-situ barrier (line 518). The results indicate that through a production of about 20 years (about 7300 days), total oil production can be increased above 20% and total water production can be reduced above 40%. As someone experienced in the field could understand, this represents a significant increase in the production of oil from the deposit and a significant reduction in the amount of waste of water that must be processed and disposed of.

Example 3 The same deposit simulation described above in Example 1 is used to simulate a deposit with a 5-point well configuration for this predictive example. In this example, a well is modeled with an in-situ barrier between the injector and a producer.

Figure 11 shows an aerial view of a water saturation profile in the formation after about 6378 days with an in-situ barrier using the deposit simulation. The simulation results show that the water front is effectively forced to flow around the in-situ barrier between the injector and the producer. Figure 12 depicts an overhead view of the water saturation profile for the configuration shown in Figure 11 without an in-situ barrier. Figure 11 shows that the water front also advances without the in-situ barrier between the injection well and the production well.

Figure 13 and Figure 14 represent the total oil production and total water production for the simulations shown in Figure 11 and Figure 12. Figure 13 shows that oil production is less without an internal barrier. situ (line 522) than the case with an in-situ barrier (line 524). Figure 14 shows that the production of water is greater without an in-situ barrier (line 528) than the case with an in-situ barrier (line 526). The results indicate that a production of about 20 years, total oil production can be increased by 9% and total water production can be reduced by 8% through the use of an in-situ barrier. As someone experienced in the field could understand, this represents a significant increase in oil production from the deposit and a significant reduction in the amount of waste water that must be processed and disposed of.

Example 4 The same deposit simulator described above in Example 1 is used to simulate an in-situ barrier comprising a relative permeability modifier for this predictive example. The relative permeability modifier comprises a compound that is capable of reducing the permeability of an underground formation to aqueous-based fluids without substantially changing its permeability to hydrocarbons, as described above. The model also assumes a change in the wettability of the fracture so that it is preferentially wet with oil in the fracture creating a capillarity barrier for the entry of an aqueous fluid. The parameters are essentially the same as for Example 1 with the additional inclusion of a high permeability channel of 500 md.

In this example, the flow of a fluid is modeled from a strong edge aquifer inside a formation penetrated by a horizontal well. The horizontal well is modeled in a high permeability channel in order to simulate a strong influx of oil. Said channel also acts as a conduit for the inflow of an aqueous fluid.

Three cases are used to model the results of about 2000 production days. The first case represented a case of base production without an in-situ barrier. The second case represented an in-situ barrier that blocked both oil and water. The permeability of the in-situ barrier is established at 1 * 10 ~ 6 milidarcios (md) for the second case. Finally, the third case represented an in-situ barrier using a relative permeability modifier that selectively blocks the flow of an aqueous fluid relative to the oil and affects the wet oil state of the formation. For the third case, the absolute permeability of the in-situ barrier is set at 1 md.

Figure 15 represents an aerial view of a profile of permeability in the formation with respect to the horizontal well and the high permeability channel. Figure 16 shows an aerial view of the water saturation profile for the first case without in-situ barrier. The first case shows the channeling of water along the high permeability channel. Figure 17 depicts an overhead view of a water saturation profile for the second case comprising an in-situ barrier. The simulation results show that the water cone around the in-situ barrier and that flows along the high permeability channel to the well. Figure 18 depicts an overhead view of a water saturation profile for the third case with an in-situ barrier comprising a relative permeability modifier. The results of the simulation show that the flow of water blocked by the barrier - that and the lack of cone due to the ability of the oil to flow through the barrier but not the aqueous fluid.

The resulting cumulative production values after 2000 days of oil and water (in millions of barrels or MMBBL) are: 12.8 MMBBL of oil and 7.1 MMBBL of water for the first case without in-situ barrier, 17.1 MMBBL of oil and 2.8 MMBBL of water for the second case with an in-situ barrier, and 18.7 MMBBL of oil and 1.3 MMBBL of water for the third case with an in-situ barrier comprising a relative permeability modifier. This example shows the potential to "design" absolute permeability, relative permeability, and capillary pressure within an underground formation to divert water, while allowing oil to flow more preferentially through the in-situ barrier to a production well . As someone experienced in the field could understand, this represents a significant increase in the production of oil from the deposit and a significant reduction in the amount of waste of water that must be processed and disposed of.

Example 5 Using the same simulation described in Example 1 using a horizontal well with edge water conduction, an in-situ barrier is modeled using a partial flow barrier for this predictive example. The production is for about 4000 days. No high permeability vein is present in the model. Four cases were modeled to determine the difference between different types of in-situ barriers. The first case was the base case without an in-situ barrier. In the second case, a partial barrier with a permeability of 1 md was modeled and a relative permeability modifier is not present. In the third case, a partial barrier with a permeability of 1 md was modeled and a relative permeability modifier is present. In the fourth case, the in-situ barrier comprised a complete barrier for fluid flow.

The resulting cumulative production values after 2000 days of oil and water (in millions of barrels or MMBBL) are: 28.8 MMBBL of oil and 11.2 MMBBL of water for the first case without in-situ barrier, 30.4 MMBBL of oil and 9.6 MMBBL of water for the second case with a partial in-situ barrier, 30.7 MMBBL of oil and 9.3 MMBBL of water for the third case with a partial in-situ barrier comprising a relative permeability modifier, and 30.7 MMBBL of oil and 9.3 MMBBL of water for the fourth case with an in-situ barrier that comprises a complete barrier for the flow.

Therefore, the present invention is well adapted to achieve the ends and advantages mentioned as well as those inherent in this respect. The particular embodiments disclosed above are illustrative only, since the present invention can be modified and practiced in different but apparent ways for those skilled in the art who have the benefit of the teachings herein. On the other hand, no limitation is intended to the details of construction or design shown in this document, other than those described in the following claims. It is therefore evident that the particular illustrative embodiments disclosed above can be altered or modified and all such variations are considered within the scope and spirit of the present invention. While the compositions and methods are described in terms of "comprising", "containing", or "including" different components or steps, the compositions and methods may also "consist essentially of" or "consist of" the different components and steps. All numbers and ranges disclosed above may vary by some amount.

Whenever a range with a lower limit and upper limit is disclosed, any number and any included range that falls within the range is specifically disclosed. In particular, each range of values disclosed in this document (in the form, "from a to a b", or equivalently, "from approximately a to b", or, equivalently, "from approximately ab") should be understand that it establishes any number and range that is encompassed within the broadest range of values. Also, the terms of the claims have their ordinary, flat meaning unless explicitly and clearly defined otherwise by the patent holder. On the other hand, the indefinite articles "a" or "an", as the claims are used, are defined herein in the sense of one or more of one of the elements they introduce. If there is any conflict in the uses of a word or term in this specification and one or more patents or other documents that may be incorporated herein by reference, definitions that are consistent with this specification shall be adopted.

Claims (23)

NOVELTY OF THE INVENTION Having described the present invention as above, it is considered as a novelty and, therefore, the content of the following is claimed as property: CLAIMS

1. A method comprising: provide a source of fluid in an underground formation; provide a well in the underground formation; and providing an in-situ barrier, wherein the in-situ barrier is placed within the underground environment and modifies the flow pattern of at least one fluid within the underground formation that is provided by the fluid source and flows into the well .

2. A method according to claim 1, characterized in that the in-situ barrier comprises a fracture with a sealant placed therein.

3. A method according to claim 2, characterized in that the in-situ barrier is a non-selective barrier.

4. A method according to claim 3, characterized in that the sealant comprises at least one composition selected from the group consisting of: a cement, a mixture of linear polymer, a mixture of linear polymer with a crosslinker, a mixture of monomer polymerized in-situ , a resin-based fluid, an epoxy-based fluid, a magnesium-based slurry, a drilling mud, drilling sediments, slag, a clay-based slurry, an emulsion, a precipitate, an in-situ precipitate, and any combination of them.

5. A method according to claim 3, characterized in that the sealant comprises an inflatable elastomer that swells in the presence of an aqueous base fluid and a petroleum base fluid, wherein the sealant comprises at least one swellable elastomer selected from the group which consists of: an ethylene propylene rubber, an ethylene-propylene-diene terpolymer rubber, a butyl rubber, a brominated butyl rubber, a chlorinated butyl rubber, a chlorinated polyethylene, a neoprene rubber, a styrene copolymer rubber butadiene, a sulfonated polyethylene, an ethylene acrylate rubber, an ethylene oxide copolymer of epichlorohydrin, a silicone rubber, a fluorosilicone rubber, and any combination thereof.

6. A method according to claim 2, characterized in that the in-situ barrier is a selective barrier.

7. A method according to claim 6, characterized in that the sealant comprises an inflatable elastomer that swells in the presence of an aqueous-based fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting of: a copolymer of starch-polyacrylate acid graft, a graft copolymer of polyvinyl alcohol cyclic acid anhydride, a polyacrylamide, poly (acrylic acid acrylamide), a poly (2-hydroxyethyl methacrylate), a poly (methacrylate) 2-hydroxypropyl), a maleic isobutylene anhydride, acrylic acid-type polymers, a vinyl acetate-acrylate copolymer, a polyethylene oxide polymer, a carboxymethyl cellulose-type polymer, a starch-polyacrylonitrile graft copolymer, a polymer comprising an expansive clay mineral, a polymer comprising a salt, and any combination thereof.

8. A method according to claim 6, characterized in that the sealant comprises an inflatable elastomer that swells in the presence of a petroleum base fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting of: a rubber natural, an acrylate butadiene rubber, an isoprene rubber, a chloroprene rubber, a butyl rubber, a brominated butyl rubber, a chlorinated butyl rubber, a chlorinated polyethylene, a neoprene rubber, a styrene copolymer rubber butadiene, a chlorinated polyethylene, a sulfonated polyethylene, an ethylene acrylate rubber, an ethylene oxide copolymer of epichlorohydrin, a terpolymer of epichlorohydrin, an ethylene-propylene rubber, an ethylene vinyl acetate copolymer, an ethylene-propylene-diene terpolymer rubber, a copolymer of ethylene vinyl acetate, a nitrile rubber, an acrylonitrile butadiene rubber, a hydrogenated acrylonitrile butadiene rubber, a carboxylated high-acrylonitrile butadiene copolymer, a mixture of polyvinylchloride-nitrile butadiene, a fluorosilicone rubber, a silicone rubber, a poly 2, 2, 1-bicyclo heptene, an alkyl styrene , a polyacrylate rubber, an ethylene-acrylate terpolymer, a fluorocarbon polymer, copolymers of poly (vinylidene fluoride) and hexafluoropropylene, a terpolymer of poly (vinylidene fluoride) -hexafluoropropylene-tetrafluororethene, a polymer of poly (fluoride), vinylidene) -polyvinyl methyl ether-tetrafluoroethylene, perfluororelastomer, a highly fluorinated elastomer, a butadiene rubber, a polychloroprene rubber, a rubber polyisoprene rubber, a polysulphide rubber, a polyurethane, a silicone rubber, a vinyl silicone rubber, a fluoromethyl silicone rubber, a fluorovinyl silicone rubber, a phenylmethyl silicone rubber, a styrene-rubber butadiene, a copolymer of isobutylene and isoprene, a brominated copolymer of isobutylene and isoprene, a chlorinated copolymer of isobutylene and isoprene, and any combination thereof.

9. A method according to claim 6, characterized in that the sealant comprises a relative permeability modifier.

10. A method according to claim 9, characterized in that the relative permeability modifier comprises an aqua-soluble polymer, wherein the water-soluble polymer comprises a hydrophobically modified polymer, wherein the hydrophobically modified polymer comprises a polymer backbone and a hydrophobic branch, and wherein the hydrophobic branch comprises an alkyl chain of about 4 to about 22 carbons.

11. A method according to claim 9, characterized in that the relative permeability modifier comprises a hydrophobically modified polymer, wherein the relative permeability modifier comprises a reaction product of at least one hydrophobic compound and at least one hydrophilic polymer.

12. A method according to claim 9, characterized in that the relative permeability modifier comprises a hydrophobically modified polymer synthesized from a polymerization reaction comprising a hydrophilic monomer and a hydrophobic modified hydrophilic monomer, wherein the hydrophobically modified polymer comprises a hydrophobic branch, and wherein the hydrophobic branch comprises an alkyl chain of about 4 to about 22 carbons.

13. A method according to claim 9, characterized in that the relative permeability modifier comprises a hydrophilically modified polymer, wherein the hydrophilically modified polymer is soluble in water.

14. A method comprising: providing a plurality of wells in an underground formation, wherein at least one well comprises a fracture; provide at least one injection well in the underground formation; Y provide an in-situ barrier by placing a sealant in the fracture of at least one well where the sealant modifies the flow pattern of at least one fluid provided by the injection well within the underground formation.

15. A method according to claim 14, characterized in that the in-situ barrier is a selective barrier.

16. A method according to claim 15, characterized in that the in-situ barrier is a non-selective barrier.

17. A method according to claim 15, characterized in that the sealant comprises at least one sealant selected from the group consisting of: an inflatable elastomer that swells in the presence of a water-based fluid, a swellable elastomer that swells in the presence of a petroleum base fluid, and a relative permeability modifier.

18. A system comprising: a source of fluid within an underground formation to provide a fluid driving force within the underground formation; a well placed in the underground formation to produce a production noise from the underground formation; Y an in-situ barrier placed within the underground formation, where the in-situ barrier modifies the flow of at least one fluid driven by the fluid driving force within the underground formation.

19. A system according to claim 18, characterized in that the fluid source comprises an injection well.

20. A system according to claim 18, characterized in that the source of fluid comprises a natural source of fluid, wherein the natural source of fluid comprises at least one source of fluid selected from the group consisting of: water existing in the underground formation, external water entering the underground formation, pressure of natural gas within the underground formation, and any combination thereof.

21. A system according to claim 18, further comprises a plurality of in-situ barriers placed within the underground formation, wherein the plurality of in-situ barriers form a deflector guiding said at least one fluid driven by the driving force. of fluid.

22. A system according to claim 18, characterized in that the in-situ barrier comprises a fracture with a sealant placed therein.

23. A system according to claim 22, characterized in that the sealant comprises at least one sealant selected from the group consisting of: an inflatable elastomer that swells in the presence of a water-based fluid, an inflatable elastomer that swells in the presence of a petroleum base fluid, and a relative permeability modifier.