WO2011110802A1 - Methods relating to modifying flow patterns using in-situ barriers - Google Patents
Methods relating to modifying flow patterns using in-situ barriers Download PDFInfo
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- WO2011110802A1 WO2011110802A1 PCT/GB2011/000302 GB2011000302W WO2011110802A1 WO 2011110802 A1 WO2011110802 A1 WO 2011110802A1 GB 2011000302 W GB2011000302 W GB 2011000302W WO 2011110802 A1 WO2011110802 A1 WO 2011110802A1
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
- C09K8/588—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific polymers
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/84—Compositions based on water or polar solvents
- C09K8/86—Compositions based on water or polar solvents containing organic compounds
- C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
Definitions
- the present invention relates generally to hydrocarbon production, and more particularly to a method of increasing hydrocarbon production in an existing well by forming an in-situ barrier to the flow of one or more fluids to modify flow patterns.
- fluid is injected into a reservoir to displace or sweep the hydrocarbons out of the reservoir.
- This method of stimulating production is sometimes referred to as a method of "Enhanced Oil Recovery” ("EOR") and may be called water flooding, gas flooding, steam injection, etc.
- EOR Enhanced Oil Recovery
- 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 the existing hydrocarbons into a producing well.
- the primary issue with injecting fluid to enhance oil recovery is how to sweep the reservoir of the hydrocarbon in the most efficient manner possible. Because of geological differences in a reservoir, the permeability within the reservoir may not be homogenous. Because of such permeability differences between the vertical and horizontal directions or the existence of higher permeability streaks, the injecting fluid may bypass some of the reservoir and create a path into the producing well.
- a drawback of these devices is that they can require additional maintenance or repair if solids are part of the produced fluid stream.
- a further, and perhaps greatest drawback of these solutions, is that they do not increase or maximize the amount of hydrocarbons being produced. Their focus is removing the water from the production.
- the present invention relates generally to hydrocarbon production, and more particularly to a method of increasing hydrocarbon production in an existing well by forming an in-situ barrier to the flow of one or more fluids to modify flow patterns.
- 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.
- a method comprises providing a plurality of wellbores in a subterranean formation, wherein at least one wellbore comprises a fracture; providing at least one injection wellbore in the subterranean formation; and providing an in-situ barrier by disposing a sealant in the fracture of the at least one wellbore; wherein the sealant modifies the flow pattern of at least one fluid provided by the injection wellbore within the subterranean formation.
- a system comprises a fluid source within a subterranean formation for providing a fluid driving force within the subterranean formation; a wellbore disposed in the subterranean formation for producing a production fluid from the subterranean formation; and an in-situ barrier disposed within the subterranean formation, wherein the in-situ barrier modifies the flow of at least one fluid driven by the fluid driving force within the subterranean formation.
- the in-situ barrier comprises a fracture with a sealant disposed therein.
- the in-situ barrier is a non-selective barrier.
- the sealant comprises at least one composition selected from the group consisting of: a cement, a linear polymer mixture, a linear polymer mixture with a cross-linker, an in-situ polymerized monomer mixture, a resin-based fluid, an epoxy based fluid, a magnesium based slurry, a drilling mud, drilling cuttings, slag, a clay based slurry, an emulsion, a precipitate, an in-situ precipitate, and any combination thereof.
- a cement a linear polymer mixture, a linear polymer mixture with a cross-linker, an in-situ polymerized monomer mixture, a resin-based fluid, an epoxy based fluid, a magnesium based slurry, a drilling mud, drilling cuttings, slag, a clay based slurry, an emulsion, a precipitate, an in-situ precipitate, and any combination thereof.
- the sealant comprises a swellable elastomer that swells in the presence of an aqueous-based fluid and an oil-based fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting 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 butadiene copolymer rubber, a sulphonated polyethylene, an ethylene acrylate rubber, an epichlorohydrin ethylene oxide copolymer, a silicone rubber, a fluorosilicone rubber, and any combination thereof.
- the sealant comprises at least one swellable elastomer selected from the group consisting of: an ethylene propylene rubber, an ethylene-propylene-diene terpol
- the in-situ barrier is a selective barrier.
- the sealant comprises a 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 starch-polyacrylate acid graft copolymer, a polyvinyl alcohol cyclic acid anhydride graft copolymer, a polyacrylamide, poly(acrylic acid-co-acrylamide), a poly(2-hydroxyethyl methacrylate), a poly(2- hydroxypropyl methacrylate), an isobutylene maleic anhydride, an acrylic acid type polymers, a vinylacetate-acrylate copolymer, a polyethylene oxide polymer, a carboxymethyl cellulose type polymer, a starch-polyacrylonitrile graft copolymer, a polymer comprising a swelling clay mineral, a polymer comprising a salt, and any combination thereof.
- the sealant comprises a swellable elastomer that swells in the presence of an oil-based fluid, wherein the sealant comprises at least one swellable elastomer selected from the group consisting of: a natural rubber, an acrylate butadiene rubber, an isoprene rubber, a chloroprene rubber, a butyl rubber, a brominated 11 000302
- butyl rubber a chlorinated butyl rubber, a chlorinated polyethylene, a neoprene rubber, a styrene butadiene copolymer rubber, a chlorinated polyethylene, a sulphonated polyethylene, an ethylene acrylate rubber, an epichlorohydrin ethylene oxide copolymer, an 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 hydrogenated acrylonitrile butadiene rubber, a carboxylated high-acrylonitrile butadiene copolymer, a polyvinylchloride-nitrile butadiene blend, a fluorosilicone rubber, a silicone rubber, a poly 2,2,1-bic
- the sealant comprises a relative permeability modifier.
- 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, and wherein the hydrophobic branch comprises an alkyl chain of about 4 to about 22 carbons.
- 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.
- the relative-permeability modifier comprises a hydrophobically modified polymer synthesized from a polymerization reaction that comprises 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.
- the relative-permeability modifier comprises a hydrophilically modified polymer, wherein the hydrophilically modified polymer is water soluble.
- Figure 1 illustrates a cross-sectional view of an embodiment of a subterranean environment with a wellbore disposed therein.
- Figure 2 illustrates another cross-sectional view of an embodiment of a subterranean environment with a wellbore disposed therein.
- Figure 3 illustrates an aerial view of a water saturation profile of a subterranean formation.
- Figure 4 illustrates an aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.
- Figure 5 illustrates a set of simulated results for total oil production according to an 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 a subterranean formation according to an embodiment of the present invention.
- Figure 8 illustrates an aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.
- Figure 9 illustrates a set of simulated results for total oil production according to an embodiment of the present invention.
- Figure 10 illustrates a set of simulated results for total water production according to an embodiment of the present invention.
- Figure 1 1 illustrates an aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.
- Figure 12 illustrates an aerial view of a water saturation profile of a subterranean formation.
- Figure 13 illustrates a set of simulated results for total oil production according to an embodiment of the present invention.
- Figure 14 illustrates a set of simulated results for total water production according to an embodiment of the present invention.
- Figure 15 illustrates an aerial view of a simulated subterranean wellbore layout useful to show an embodiment of the present invention.
- Figure 16 illustrates an aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.
- Figure 17 illustrates another aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.
- Figure 18 illustrates still another aerial view of a water saturation profile of a subterranean formation according to an embodiment of the present invention.
- the present invention relates generally to hydrocarbon production, and more particularly to a method and system for increasing hydrocarbon production in an existing well by forming an in-situ barrier to the flow of one or more fluids to modify flow patterns.
- the methods and systems disclosed herein may be advantageously used to modify the flow pattern within a reservoir to increase the amount of hydrocarbons recovered from the subterranean formation and decreasing the amount of water produced from the subterranean formation.
- the system and method described herein may be used with an existing well in an existing formation to allow for the additional recovery of hydrocarbons without having to drill new wells, though new wells can be used in an embodiment. A number of exemplary ways of performing these functions are disclosed herein.
- the present invention improves the production efficiency of hydrocarbons from a producing reservoir by: providing a fluid source in a subterranean formation, providing a wellbore in the subterranean formation, providing an in- situ barrier in the subterranean formation that modifies the flow pattern of at least one fluid provided by the fluid source that flows toward the wellbore.
- 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 either vertical, deviated or horizontal wellbores, in consolidated and unconsolidated formations, in "open-hole” and/or under reamed completions, as well as in cased wells.
- the casing may be perforated to provide for fluid communication between the wellbore and the subterranean formation.
- vertical wellbore is used herein to mean the portion of a wellbore to be completed which is substantially vertical or deviated from vertical in an amount up to about 15°.
- horizontal wellbore is used herein to mean the portion of a wellbore to be completed which is substantially horizontal, or at an angle from vertical in the range of from about 75° to about 105°. All other angular positioning relates to a deviated or inclined wellbore. Since the present invention is applicable in horizontal and inclined wellbores, the terms “upper and lower” and “top and bottom” as used herein are relative terms and are intended to apply to the respective positions within a particular wellbore, while the term “levels” is meant to refer to respective spaced positions along the wellbore.
- the terms “upper,” “top,” and “above” refer to the portion of a wellbore nearer to the surface or wellhead while the terms “lower,” “bottom,” and “below” refer to the portion of a wellbore further from the surface or wellhead, irrespective of the true vertical depth of any portion of the wellbore.
- the present invention can be used in forming an in-situ barrier to fluid flow in a subterranean formation.
- the present invention may be described in the context of a typical water contamination problem in which water is produced with the hydrocarbons.
- the methods and materials of the present invention may have application to other situations where blocking the flow of fluids other than water or all fluids is needed.
- Such applications include, without limitation, any EOR operation 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.
- FIG. 1 illustrates a wellbore 110 for producing hydrocarbons from a subterranean formation.
- Wellbore 1 10 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 000302
- the wellbore 110 is lined with a casing string.
- the casing string may then be cemented to the formation.
- a person of ordinary skill in the art should know whether the wellbore 1 10 needs to be cased. In most cases, it will be beneficial to do so.
- the wellbore 1 10 may extend through a hydrocarbon-containing subterranean formation area 1 12 and into a water-bearing area 1 14.
- water refers to any aqueous fluid and may include, for example, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated saltwater), or any combination thereof.
- saltwater e.g., water containing one or more salts dissolved therein
- brine e.g., saturated saltwater
- the water- hydrocarbon boundary area is illustrated as a broad line 1 16, it being understood, of course, that the water-hydrocarbon boundary area may be much more irregular and larger than the line.
- the 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.
- the water may be introduced into the formation through an injection wellbore 124 that may inject water into the reservoir through one or more fractures 126 as part of an EOR operation.
- the lower end of the wellbore is illustrated extending to a location beneath the boundary 1 16.
- the water boundary 1 16 rises until it is in contact with fractures at the lower end of the wellbore 118.
- hydrocarbons can be produced at a rate that will cause the water boundary to extend upward or "cone" around the wellbore, speeding up the production of significant volumes of water with the hydrocarbons.
- a fracture 120 is opened up to extend from the wellbore and may generally be located above the water boundary 116.
- the fracture 120 in this case is generally disk shaped extending from the wellbore 110 in all directions.
- fracturing technology exists to create open fractures from wellbores extending in selected directions, distances and having selected shapes.
- the fracture is formed to extend from all sides about 500 ft to about 1,000 ft from the wellbore though longer fractures may be possible.
- the fracture 120 is filled with a sealant 122. Any fractures located below the water boundary, for example, fracture 118, may also be filled with a sealant.
- the sealant 122 may be pumped into the fracture 120 as part of a treatment fluid, for example, in a slurry form and also into any flow paths in the form of voids intersecting the fracture 120.
- One or more fractures may be formed in or along the wellbore 1 10 using a variety of techniques.
- the plurality of fractures are formed by using a hydra jetting tool, such as that used in the SurgiFrac® fracturing service offered by Halliburton Energy Services in Duncan, Oklahoma.
- the hydra jetting tool forms each fracture, one at a time.
- Each fracture may be formed by the following steps: (i) positioning the hydra jetting tool in the wellbore at the location where the fracture is to be formed, (ii) perforating the reservoir at the location where the fracture is to be formed, and (iii) injecting a fracture fluid into the perforation at sufficient pressure to form a fracture along the perforation.
- fracture fluid can be simultaneously pumped down the annulus while it is being pumped out of the hydra jetting tool to initiate the fracture.
- the fracturing fluid may be pumped down the annulus and not through the hydra jetting tool to initiate and propagate the fracture.
- the hydra jetting tool primarily forms the perforations.
- one or more fractures may be formed by staged fracturing.
- Staged fracturing may be performed by a method comprising (i) detonating a charge in the wellbore 1 10 at the location where a fracture is to be formed so as to form at least one perforation in the reservoir at that location, (ii) pumping a fracture fluid into the perforation at sufficient pressure to propagate the fracture, (iii) installing a plug in the wellbore uphole of the fracture, (iv) repeating steps (i) through (iii) until the desired number of fractures have been formed; and (v) removing the plugs following the completion of step (iv).
- staged fracture method there are many variants on the staged fracture method.
- the fractures may take a variety of geometries including, but not limited to, transverse fractures, longitudinal fractures (e.g., curtain wall fractures), or fractures extending at an angle with respect to the wellbore longitudinal axis (e.g., deviated fractures that may extend along natural fracture lines).
- the fractures may be formed along natural fracture lines and may generally be parallel to one another.
- the fracture's shape, size and orientation can be determined by the orientation of the fluid nozzles and movement thereof.
- a transversely extending fracture can be formed and may extend from about 50 ft to about 1000 ft from the wellbore.
- longitudinal extending fractures may be formed to create a curtain wall fracture that may be used to form a curtain wall in-situ barrier.
- fractures used to form in-situ barriers in multiple adjacent wells may be used to form co-operating in-situ barriers.
- the fracture may have a sealant disposed therein.
- the sealant may be disposed in the fracture by squeezing it into the fracture. This may be accomplished by first isolating the perforations adjacent to the fracture using a packer (e.g., a hydraulically set drillable, retrievable or inflatable packer) on the end of tubing and setting the packer in the casing; then pumping the sealant in a fluid state through the tubing, then through the perforations and into the fracture to be sealed until a sufficient volume of sealant has been placed into the transverse fracture to provide the in-situ barrier to flow.
- a packer e.g., a hydraulically set drillable, retrievable or inflatable packer
- the sealant used to provide the in-situ barrier may be any material capable of selectively or non-selectively reducing the flow of one or more fluids within a subterranean formation.
- a non-selective barrier is an in-situ barrier intended to substantially seal the fracture.
- a selective barrier is an in-situ barrier intended to modify the permeability or relative permeability (as described above) to allow fluids to selectively flow through the facture.
- the sealant may comprise a cement, a linear polymer mixture, a linear polymer mixture with cross-linker, an in-situ polymerized monomer mixture, a resin-based fluid, an epoxy based fluid, a magnesium based slurry, a clay based slurry (e.g., a bentonite based slurry), an emulsion, a precipitate (e.g., a polymeric precipitate), or an in-situ precipitate.
- an in-situ precipitate is a precipitate formed within the subterranean formation, for example, using a polymeric solution that is introduced into a subterranean formation followed by an activator.
- sealants are capable of being placed in a fluid state with the property of becoming a viscous fluid or solid barrier to fluid migration after or during placement into the fracture.
- the sealant is H 2 ZeroTM available from Halliburton Energy Services, Inc., Duncan, OK.
- Other sealants could include particles, drilling mud, cuttings, and slag. Exemplary particles could be ground cuttings so that a wide range of particle sizes would exist and produce a low permeability as compared to the surrounding reservoir.
- drilling mud includes all types of drilling mud known to those of ordinary skill in the art including, but not limited to, oil based muds, invert emulsions, polymer based muds, clay based muds (e.g., bentonite based drilling mud), and weighted muds.
- the sealant may comprise swellable particles.
- a particle is characterized as swellable when it swells upon contact with an aqueous fluid (e.g., water), an oil-based fluid (e.g., oil), or a gas.
- aqueous fluid e.g., water
- oil-based fluid e.g., oil
- gas e.g., a gas
- Suitable swellable particles are described in the following references, each of which is incorporated by reference herein in its entirety: U.S. Pat. No. 3,385,367, U.S. Pat. No. 7,059,415, U.S. Pat. No. 7,578,347, U.S. Pat. App. No. 2004/0020662, U.S. Pat. App. No. 2007/0246225, U.S. Pat. App. No. 2009/0032260 and WO2005/1 16394.
- Swellable particles suitable for use with embodiments of the present invention may generally swell by up to about 200% of their original size at the surface. Under downhole conditions, this swelling may be more, or less, depending on the conditions present. For example, the swelling may be at least 10% under downhole conditions. In some embodiments, the swelling may be up to about 50%» under downhole conditions. Although the rate of swelling may be hours in some embodiments, in certain embodiments the rate of swelling may be measured in minutes. The rate of swelling is defined as the amount of time required for the swelled composition to substantially reach an equilibrium state, where swelling is within 5% of its final equilibrium state.
- the actual swelling when the swellable particles are included in a sealant may depend on, for example, the concentration of the swellable particles included in the sealant, the temperature, the pressure, and the other components present in the wellbore.
- An example of a swellable particle that may be suitable for use with embodiments of the present invention comprises a swellable elastomer that swells in the presence of an oil-based fluid or an aqueous-based fluid.
- suitable swellable elastomers that swell in the presence of an oil-based fluids include, but are not limited to, natural rubbers, acrylate butadiene rubbers, isoprene rubbers, chloroprene rubbers, butyl rubbers, brominated butyl rubbers, chlorinated butyl rubbers, chlorinated poly ethylenes, neoprene rubbers, styrene butadiene copolymer rubbers, chlorinated polyethylene, sulphonated polyethylenes, ethylene acrylate rubbers, epichlorohydrin ethylene oxide copolymers, epichlorohydrin terpolymer, ethylene-propylene rubbers, ethylene vinyl acetate copoly
- Suitable examples of useable fluoroelastomers that swell in the presence of an oil-based fluid are copolymers of vinylidene fluoride and hexafluoropropylene and terpolymers of vinylidene fluoride, hexafluoropropylene and tetrafluoroethylene.
- the fluoroelastomers suitable for use in the disclosed invention are elastomers that may comprise one or more vinylidene fluoride units ("VF2”or “VdF”), one or more hexafluoropropylene units (“HFP”), one or more tetrafluoroethylene units (“TFE”), one or more chlorotrifluoroethylene (“CTFE”) units, and/or one or more perfluoro(alkyl vinyl ether) units (“PAVE”), such as perfluoro(methyl vinyl ether) (“PMVE”), perfluoro(ethyl vinyl ether) (“PEVE”), and perfluoropropyl vinyl ether (“PPVE”).
- VF2 vinylidene fluoride units
- HFP hexafluoropropylene units
- TFE tetrafluoroethylene
- CTFE chlorotrifluoroethylene
- PAVE perfluoro(alkyl vinyl ether) units
- PMVE perfluoro(methyl vinyl ether
- copolymers of vinylidene fluoride and hexafluoropropylene units are particularly suitable.
- the polymers may contain up to 40 mole% VF 2 units, e.g., 30-40 mole%. If the fluoropolymers contain hexafluoropropylene units, the polymers may contain up to 70 mole% HFP units. If the fluoropolymers contain tetrafluoroethylene units, the polymers may contain up to 10 mole% TFE units. When the fluoropolymers contain chlorotrifluoroethylene the polymers may contain up to 10 mole% CTFE units. When the fluoropolymers contain perfluoro(methyl vinyl ether) units, the polymers may contain up to 5 mole% PMVE units.
- the polymers may contain up to 5 mole% PEVE units.
- the fluoropolymers may contain perfluoro(propyl vinyl ether) units.
- the polymers may contain up to 5 mole% PPVE units.
- the fluoropolymers may contain 66%-70% fluorine.
- One suitable commercially available fluoroelastomer is that 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.
- fluoroelastomer 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 VF 2 , HFP, and TFE monomers containing 67% fluorine.
- Another suitable commercially available fluoroelastomer is "VITON ® AL 300,” by DuPont Performance Elastomers of La Place, Louisiana.
- a blend of the terpolymers known under the trade designations "VITON ® AL 300” and “VITON ® AL 600” can also be used (e.g., one-third AL-600 and two-thirds AL-300); both are available from DuPont Performance Elastomers of La Place, Louisiana.
- elastomers include products known under the trade designations "7182B” and “7182D” from Seals 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.
- One process for making a swellable elastomer useful in the present invention may involve grafting an unsaturated organic acid molecule.
- 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.
- unsaturated carboxylic acids may 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 having reasonable skill in the chemical art. Mixing other unsaturated acids such as acrylic acid and methacrylic acid is also possible but may be more difficult since they are liquids at room temperature.
- Unsaturated acids such as palmitoleic acid, oleic acid, linoleic acid, and linolenic acid may also be used.
- the initial reaction leads to a relatively non-porous "acid-grafted rubber.”
- addition of a small amount of alkali such as soda ash, along with or separate from the unsaturated acid leads to formation of a porous, swellable acid grafted rubber.
- Micro-porosities are formed in the composition, allowing a fluid to rapidly reach the interior region of a molded part and increase the rate and extent of swelling.
- An organic peroxide vulcanizing agent may be employed to produce a vulcanized, porous, swellable acid-grafted rubber formulation.
- 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 percent swelling of elastomer when exposed to both water at 100 °C. for 24 hrs and at room temperature for 24 hrs in kerosene.
- Other commercially available grades of organic peroxides, as well as other vulcanization agents, may be employed.
- the resulting elastomeric compositions may be described as non-porous, or porous and swelled, acid- grafted rubbers, which may or may not be vulcanized.
- vulcanized and “crosslinked” are used interchangeably herein, although vulcanization technically refers to a physicochemical change resulting from crosslinking of the unsaturated hydrocarbon chain of polyisoprene with sulfur, usually with the application of heat.
- the relatively hydrophobic linear or branched chain polymers and relatively hydrophilic water-soluble monomers, either grafted onto the polymer backbone or blended therein, may act together to cost-effectively increase the water- and/or oil-swellability of oilfield elements that comprise one or more apparatus of the invention.
- unsaturated organic acids, anhydrides, and their salts offer a commercially feasible way to develop inexpensive composites materials with good water, and/or hydrocarbon fluid swellability, 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 variable amounts to an EPDM polymer or its precursor monomer mixture, along with a sufficient amount (from about 1 to 10 phr) of an unsaturated organic acid, anhydride, or salt thereof, such as maleic acid, optionally combined with a sufficient amount (from 1 about to 10 phr) an inorganic swelling agent such as sodium carbonate, may produce a water-swellable elastomer having variable low-oil swellability.
- HNBR hydrogenated nitrile rubber
- a second addition of a sufficient amount (from 1 to 10 phr more than the original addition) of inorganic swelling agent enhances swellability in low pH, high concentration brines.
- Another reaction scheme useful in the present invention involves the use of AMPS monomer and like sulfonic acid monomers. Since AMPS monomer is chemically stable up to at least 350° F. (177°C), mixtures of EPDM and AMPS monomer which may or may not be grafted on to EPDM will function as a high-temperature resistant water-swellable elastomer.
- the use of AMPS and like monomers maybe used in like fashion to functionalize any commercial elastomer to make a high-temperature water-swellable elastomer.
- An advantage of using AMPS is that it is routinely used in oilfield industry in loss circulation fluids and is very resistant to down hole chemicals and environments.
- swellable elastomers that behave in a similar fashion with respect to aqueous fluids also may be suitable.
- suitable swellable elastomers that swell in the presence of an aqueous-based 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, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-polyacrylonitrile graft copolymers and the like, and highly swelling clay minerals such as sodium bentonite having montmorillonite as main ingredient, and any combination thereof.
- Additional water swellable particles may comprise particulate matter embedded in a matrix material.
- salt preferably dissociating salt, which can be uniformly compounded into a base rubber.
- MxHy halides
- H CI, Br or I
- hydrosulphides hydroxides
- imides nitrates, nitrides, nitrites, phosphates, sulphides, sulphates, and any combination thereof.
- other salts can be applied wherein the cation is a non-metal like NH4CI .
- CaCl 2 may be useful in view of its di
- the swellable particles include a hydrophilic polymer containing polar groups of either oxygen or nitrogen in the backbone or side groups of the polymer matrix material. These side groups can be partially or fully neutralized.
- Hydrophilic polymers of such type are, for example, alcohols, acrylates, methacrylates, acetates, aldehydes, ketones, sulfonates, anhydrides, maleic anhydrides, nitriles, acrylonitriles, amines, amides, oxides (polyethylene oxide), cellulose types including all derivatives of these types, all copolymers including one of the above all grafted variants.
- a ternary system may be applied which includes an elastomer, a polar SAP and a salt, whereby the polar SAP is grafted onto the backbone of the elastomer.
- a ternary system has the advantage that the polar SAP particles tend to retain the salt particles in the elastomer matrix thereby reducing leaching of the salt from the elastomer.
- the polar salt is attracted by electrostatic forces to the polar SAP molecules which are grafted onto the backbone of the rubber.
- Suitable swellable elastomers may also be used.
- some of the elastomers that swell in oil-based fluids may also swell in aqueous-based fluids.
- Suitable elastomers that may swell in both aqueous-based and oil- based fluids include, but are not limited to ethylene propylene rubbers, ethylene-propylene- diene terpolymer rubbers, butyl rubbers, brominated butyl rubbers, chlorinated butyl rubbers, chlorinated polyethylene, neoprene rubbers, styrene butadiene copolymer rubbers, sulphonated polyethylenes, ethylene acrylate rubbers, epichlorohydrin ethylene oxide copolymer, silicone rubbers and fluoro silicone rubbers, and any combination thereof.
- ethylene propylene rubbers ethylene-propylene- diene terpolymer rubbers
- butyl rubbers brominated but
- the swellable elastomers may be crosslinked and/or lightly crosslinked. Other swellable elastomers that behave in a similar fashion with respect to fluids may also be suitable. Those of ordinary skill in the art, with the benefit of this disclosure, will be able to select appropriate swellable elastomers based on a variety of factors, including the application in which the composition will be used and the desired swelling characteristics.
- the swellable particles generally may be included in the embodiments of the sealant in an amount sufficient to provide the desired barrier properties.
- the swellable particles may be placed in a fracture or void in a treatment fluid comprising an amount up to about 50% by volume of the treatment fluid.
- the swellable particles may be present in a range of about 5% to about 95% by volume of the treatment fluid used to place the particles.
- the swellable particles that are utilized may have a wide variety of shapes and sizes of individual particles suitable for use with embodiments of the present invention.
- the swellable particles may have a well-defined physical shape as well as an irregular geometry, including the physical shape of platelets, shavings, fibers, flakes, ribbons, rods, strips, spheroids, beads, pellets, tablets, or any other physical shape.
- the swellable particles may have a particle size in the range of about 5 microns to about 1,500 microns.
- the swellable particles may have a particle size in the range of about 20 microns to about 500 microns. However, particle sizes outside these defined ranges also may be suitable for particular applications.
- the sealant may comprise a cement.
- Any suitable cement known in the art may 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 sets and hardens by reaction with water.
- hydraulic cements include, but are not limited to a Portland cement, a pozzolan cement, a gypsum cement, a high alumina content cement, a silica cement, a high alkalinity cement, or combinations thereof.
- Preferred hydraulic cements are Portland cements of the type described in American Petroleum Institute (API) Specification 10, 5 th Edition, Jul. 1, 1990, which is incorporated by reference herein in its entirety.
- API American Petroleum Institute
- the cement may be, for example, a class A, B, C, G, or H Portland cement.
- Another example of a suitable cement is microfine cement, for example, MICRODUR RU microfine cement available from Dyckerhoff GmBH of Lengerich, Germany. Combinations of cements and swellable particles may also be used.
- the sealant may comprise a water soluble relative permeability modifier.
- relative permeability modifier refers to a compound that is capable of reducing the permeability of a subterranean formation to aqueous-based fluids without substantially changing its permeability to hydrocarbons.
- the water- soluble relative permeability modifiers suitable for use with the present invention may be any suitable water-soluble relative permeability modifier that is suitable for use in subterranean operations.
- the water-soluble relative permeability modifiers comprise a hydrophobically modified polymer.
- 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.
- the water-soluble relative permeability modifiers comprise a hydrophilically modified polymer.
- hydrophilically modified refers to the incorporation into the hydrophilic polymer structure of hydrophilic groups.
- the water- soluble relative permeability modifiers comprise a water-soluble polymer without hydrophobic or hydrophilic modification.
- the hydrophobically modified polymers suitable for use in the present invention typically have molecular weights in the range of from about 100,000 to about 10,000,000.
- a mole ratio of a hydrophilic monomer to the hydrophobic compound in the hydrophobically modified polymer is in the range of from about 99.98:0.02 to about 90:10, wherein the hydrophilic monomer is a calculated amount present in the hydrophilic polymer.
- the hydrophobically modified polymers may comprise a polymer backbone, the polymer backbone comprising polar heteroatoms.
- the polar heteroatoms present within the polymer backbone of the hydrophobically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.
- the hydrophobically modified polymers may be a reaction product of a hydrophilic polymer and a hydrophobic compound.
- the hydrophilic polymers suitable for forming the hydrophobically modified polymers used in the present invention should be capable of reacting with hydrophobic compounds.
- Suitable hydrophilic polymers include, homo-, co-, or terpolymers such as, but not limited to, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in general.
- alkyl acrylate polymers include, but are not limited to, polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacryl amide, poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide).
- 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.
- the hydrophilic polymers comprise dialkyl amino pendant groups.
- the hydrophilic polymers comprise a dimethyl amino pendant group and at least one monomer comprising dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide.
- the hydrophilic polymers comprise a polymer backbone, the polymer backbone comprising 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 phosphorous.
- Suitable hydrophilic polymers that comprise polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers, such as, but not limited to, celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetheramines, polylysines, polysulfones, gums, starches, and derivatives thereof.
- the starch is a cationic starch.
- a suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, and tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.
- the hydrophobic compounds that are capable of reacting with the hydrophilic polymers include, but are not limited to, alkyl halides, sulfonates, sulfates, and organic acid derivatives.
- suitable organic acid derivatives include, but are not limited to, octenyl succinic acid; dodecenyl succinic acid; and anhydrides, esters, and amides of octenyl succinic acid or dodecenyl succinic acid.
- the hydrophobic compounds may have an alkyl chain length of from about 4 to about 22 carbons.
- the reaction between the hydrophobic compound and hydrophilic polymer may result in the quaternization of at least some of the hydrophilic polymer amino groups with an alkyl halide, wherein the alkyl chain length is from about 4 to about 22 carbons.
- the hydrophobically modified polymers used in the present invention may 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. Pat. No. 6,476,169, the disclosure of which is incorporated herein by reference in its entirety.
- hydrophilic monomers may be used to form the hydrophobically modified polymers useful in the present invention.
- suitable hydrophilic monomers include, but are not limited to homo-, co-, and terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, ⁇ , ⁇ -dimethyl acrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N,N- diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, it
- hydrophobically modified hydrophilic monomers also may be used to form the hydrophobically modified polymers useful in the present invention.
- suitable hydrophobically modified hydrophilic monomers include, but are not limited to, alkyl acrylates, alkyl methacrylates, alkyl acrylamides, alkyl methacrylamides alkyl dimethylammoniumethyl methacrylate halides, and alkyl dimethylammoniumpropyl methacrylamide halides, wherein the alkyl groups have from about 4 to about 22 carbon atoms.
- the hydrophobically modified hydrophilic monomer comprises octadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumpropyl methacrylamide bromide, 2-ethylhexyl methacrylate, or hexadecyl methacrylamide.
- the hydrophobically modified polymers formed from the above- described polymerization reaction may have estimated molecular weights in the range of from about 100,000 to about 10,000,000 and mole ratios of the hydrophilic monomer(s) to the hydrophobically modified hydrophilic monomer(s) in the range of from about 99.98:0.02 to about 90:10.
- Suitable hydrophobically modified polymers having molecular weights and mole ratios in the ranges set forth above include, but are not limited to, acrylamide/ octadecyldimethylammoniumethyl methacrylate bromide copolymer, dimethylaminoethyl methacrylate/hexadecyldimet ylarnmoniumethyl methacrylate bromide copolymer, dimethylaminoethyl methacrylate/ vinyl pyrrolidone/ hexadecyldimethylammoniumethyl methacrylate bromide terpolymer and acrylamide/2-acrylamido-2-methyl propane sulfonic acid/2-ethylhexyl methacrylate terpolymer.
- the water-soluble relative permeability modifiers comprise a hydrophilically modified polymer.
- the hydrophilically modified polymers suitable for use with the present invention typically have molecular weights in the range of from about 100,000 to about 10,000,000.
- the hydrophilically modified polymers comprise a polymer backbone, the polymer backbone comprising polar heteroatoms.
- the polar heteroatoms present within the polymer backbone of the hydrophilically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.
- the hydrophilically modified polymer may be a reaction product of a hydrophilic polymer and a hydrophilic compound.
- the hydrophilic polymers suitable for forming the hydrophilically modified polymers used in the present invention should be capable of reacting with hydrophilic compounds.
- suitable hydrophilic polymers include, homo-, co-, or terpolymers, such as, but not limited to, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in general.
- alkyl acrylate polymers include, but are not limited to, polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide).
- 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.
- the hydrophilic polymers comprise dialkyl amino pendant groups.
- the hydrophilic polymers comprise a dimethyl amino pendant group and at least one monomer comprising dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide.
- the hydrophilic polymers comprise a polymer backbone comprising 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 phosphorous.
- Suitable hydrophilic polymers that comprise polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers, such as, but not limited to, celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetheramines, polylysines, polysulfones, gums, starches, and derivatives thereof.
- the starch is a cationic starch.
- a suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.
- the hydrophilic compounds suitable for reaction with the hydrophilic polymers include polyethers that comprise halogens; sulfonates; sulfates; and organic acid derivatives.
- suitable polyethers include, but are not limited to, polyethylene oxides, polypropylene oxides, and polybutylene oxides, and copolymers, terpolymers, and mixtures thereof.
- the polyether comprises an epichlorohydrin- terminated polyethylene oxide methyl ether.
- hydrophilically modified polymers formed from the reaction of a hydrophilic polymer with a hydrophilic compound may have estimated molecular weights in the range of from about 100,000 to about 10,000,000 and may have weight ratios of the hydrophilic polymers to the polyethers in the range of from about 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 epichlorohydrin-terminated polyethyleneoxide methyl ether; the reaction product of polydimethylaminopropyl methacrylamide and epichlorohydrin-terminated polyethyleneoxide methyl ether; and the reaction product of poly(acrylamide/dimethylaminopropyl methacrylamide) and epichlorohydrin-terminated polyethyleneoxide methyl ether.
- the hydrophilically modified polymer comprises the reaction product of a polydimethylaminoethyl methacrylate and epichlorohydrin-terminated polyethyleneoxide methyl ether having a weight ratio of polydimethylaminoethyl methacrylate to epichlorohydrin-terminated polyethyleneoxide methyl ether of about 3: 1.
- the water-soluble relative permeability modifiers comprise a water-soluble polymer without hydrophobic or hydrophilic modification.
- suitable water-soluble polymers without hydrophobic or hydrophilic modification include, but are not limited to, homo-, co-, and terpolymers of acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, ⁇ , ⁇ -dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N,N- diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic
- a hydrocarbon reservoir in a subterranean formation may have one or more producing wells.
- the hydrocarbon reservoir may have one or more injection wells for providing a fluid source to supply a driving force for the production of hydrocarbons.
- a "fluid source” refers to any source of one or more fluids that flow through the subterranean formation between perforations or fractures in an individual wellbore or between separate wellbores.
- An injection wells may be drilled for the specific purpose of injecting fluids to provide the fluid source, or an existing wellbore may be converted from producing wells to injecting wells.
- a natural fluid source that provides a driving force may be present in the subterranean formation in the form of existing water, external water entering the reservoir, or natural gas pressure within the subterranean formation.
- water may flow into the subterranean formation from a nearby water source (e.g., an edge water aquifer) to create a fluid source that provides a driving force within the subterranean formation.
- the subterranean formation may not require injection wells for the production of hydrocarbons.
- the flow of hydrocarbon fluids within the reservoir may be modified through the use of an in-situ barrier comprising a fracture containing a sealant.
- an in-situ barrier with selective or non-selective barriers to flow may be used to modify the flow pattern within an entire reservoir.
- a relative permeability modifier may allow oil to selectively flow through the in-situ barrier in relation to an aqueous fluid.
- a plurality of in-situ barriers may have varying permeabilities, whose placement and geometries, may act as a series of barriers or baffles to guide the flow of at least one desired fluid to a producing well.
- a plurality of selectively placed fractures with selective or non-selective barriers to fluid flow may be used to modify the flow regime inside the hydrocarbon reservoir to improve the volumetric sweep efficiency of the hydrocarbons in the formation.
- the sealant and fluid used to provide the driving force for flow and sweep of the hydrocarbon fluids can be selected to maximize the amount of hydrocarbons recovered in a hydrocarbon reservoir.
- the flow patterns within a hydrocarbon reservoir may be determined through the use of a simulator program using any simulator capable of calculating the flow regime within a subterranean environment. Suitable simulators for use in hydrocarbon reservoirs are known to those skilled in the art.
- an injection well 124 may be drilled remote from, but generally parallel to, existing well 1 10.
- wellbore 110 may be drilled for the purpose of modifying the flow pattern of at least one fluid within the subterranean reservoir.
- injection well 124 is drilled proximate the sealed fractures 118, 120.
- the injection well 124 can alternatively be formed prior to the formation of the wellbore 110, or may be a converted producing wellbore.
- the flood front may be diverted around the sealed fracture 120.
- hydrocarbons are drained into fractures 128.
- the producing fracture 128 begins producing high rates of flood fluid, it may be sealed.
- a bridge plug or other zonal isolation device may be installed in the wellbore 1 10 just uphole of the fracture 128 when the fracture is sealed.
- a new producing fracture may then be created to further produce hydrocarbons from the hydrocarbon reservoir. This isolation process is repeated as sufficiently high flood fluid ratios are being produced from successive transverse fractures until all of the transverse fractures have been sealed.
- the flow of the fluids in a hydrocarbon reservoir may be modified on a field-wide basis.
- the injection well 124 may be located in an existing injection pattern as known to those of ordinary skill in the art. For example, existing 5-spot, 7-spot, or line drive injection patterns may have existing injection wells for use in this method.
- the selection of a wellbore for use as an injection well may change during the life of the hydrocarbon reservoir.
- the producing wellbore 1 10 may be an existing wellbore or may be drilled for the purpose of recovering fluids.
- the wellbore 1 10 and any fractures associated with the wellbore 1 10 may be drilled or used for the purpose of modifying the flow pattern of at least one fluid within a subterranean reservoir without being used to produce a fluid.
- the selection of fractures or locations for creating new fractures may be chosen so as to increase the sweep efficiency of fluids moving through the formation.
- the fracture 120 may only be partially sealed in the near wellbore area rather than completely sealed all the way to its tip.
- the benefit of sealing the near wellbore area is that if the injection fluid happens to move faster in this area the flow of injection fluid can be partially diverted to improve sweep.
- FIG. 2 another embodiment of the method for increasing hydrocarbon production in accordance with the present invention is disclosed.
- the flood fluid is introduced into the reservoir 212 through a tubing 260, which is installed into wellbore 224 rather than a separate injection well.
- the tubing 260 injects the flood fluid into the reservoir 212 from the toe 240 of the wellbore 224, which may include one or more fractures 242 through which the fluid is injected into the formation.
- Hydrocarbons may be produced through one or more fractures 290 up the annulus 265 formed between the tubing 260 and the casing 262.
- Packer 270 may be used to seal the end of the tubing 260, so the flood fluid does not enter into the annulus 265.
- additional wellbores 210, 280 may be used to produce fluids which may be driven at least in part by the fluids injected from wellbore 224.
- These additional wellbores may have one or more fractures 286, 288 with a sealant composition 222 placed therein to affect the flow pattern in the hydrocarbon reservoir.
- a plurality of fractures of various shapes may be used to affect the flow of fluids within the hydrocarbon reservoir.
- the wellbores 210, 280 and any fractures associated with the wellbores e.g., fractures 286, 288) may be drilled or used for the purpose of modifying the flow pattern of at least one fluid within a subterranean reservoir without being used to produce a fluid.
- additional wellbore (not shown in FIG. 2) may be used to produce one or more fluids from the subterranean reservoir.
- the fractures used for production 290 may be sealed using the techniques described above and new production fractures or perforations may be created. This process may be repeated for successive fractures as the flood front 216 moves into the area near a producing well.
- the system generally comprises a fluid source within a subterranean formation for providing a fluid driving force within the subterranean formation, a wellbore disposed in the subterranean formation for producing a production fluid from the subterranean formation, and an in-situ barrier disposed within the subterranean formation, where the in-situ barrier modifies the flow of at least one fluid driven by the fluid driving force within the subterranean formation.
- Each component of the system is as described above and may include any of the optional features disclosed herein. As those of ordinary skill in the art will appreciate from the disclosure, there are many different ways of arranging and providing the wells, the in-situ barriers to flow, and the fluid provided by the fluid source, and many different ways of recovering the hydrocarbons from the reservoir.
- a reservoir simulation is used to simulate an in-situ barrier placed in a subterranean formation using a horizontal well for this prophetic example.
- One such simulator is a numerical finite difference simulator QuikLook version 4.1 provided by Halliburton Energy Services, Inc.
- the horizontal well has a production length of about 1560 ft.
- Input properties for the subterranean formation simulation include: Area of 2600 ft by 2600 ft., thickness of 490 ft with an average formation porosity of 0.24, horizontal permeability in the longitudinal direction of 30 md, horizontal permeability in the latitudinal direction of 45 md and vertical permeability of 3 md.
- the initial water saturation in the oil zone is 0.37.
- There is an active edge and bottom-water aquifer as the source of encroaching water flow to the producing well.
- FIG. 3 depicts a water saturation profile in the formation after 911.476 days without an in-situ barrier using the reservoir 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 simulation results show that the water front is beginning to break through to the production well.
- FIG. 4 depicts a water saturation profile in the formation after 914.01 days with an in-situ barrier using the reservoir simulation.
- the simulation results show that the water front is being effectively blocked from the production well.
- Water saturation, at about 914 days, is lower at the horizontal production well than in the case without an in-situ barrier.
- the increased sweep of the water is expected to result in an increased production of hydrocarbons from the well.
- FIG. 5 and FIG. 6 depict the total oil production and total water production for both the base case without an in-situ barrier and the comparison case with the in-situ barrier depicted in FIG. 4.
- the figures show the production of water is greater (line 508) and the production of oil lower (line 502) without an in-situ barrier as compared to the production of water (line 506) and the production of oil (line 504) with an in-situ barrier.
- the increase in oil production is about 5.4% and the decrease in water production is about 6.41%.
- the increase in oil production is worth millions of dollars and the decline in water production represents a significant savings in the cost of waste water disposal.
- Example 2 The same reservoir simulation described above in Example 1, is used to simulate an injector and a producer in a line drive configuration for this prophetic example.
- a well is located between the injector and producer and is used to dispose an in-situ barrier into the formation.
- FIG. 7 depicts a side view of a water saturation profile in the formation after about 3,614 days with an in-situ barrier using the reservoir simulation.
- the simulation results show that the water front is effectively slowed down by the in-situ barrier between the injector and producer.
- FIG. 8 depicts an aerial view of the water saturation profile shown in 2
- FIG. 7 similarly depicts that the water front is forced to move around the in-situ barrier in the formation in order to reach the producing well.
- FIG. 9 and FIG. 10 depict the total oil production and total water production for the simulation shown in FIG. 7 and FIG. 8.
- FIG.9 and FIG. 10 show the results for a simulation without an in-situ barrier between the producer and injector and for a case in which the in-situ barrier is moved closer to the producing well.
- Figure 9 shows the production of oil is less without an in-situ barrier (line 510) than either the case with an in-situ barrier (line 514) or the closer in-situ barrier (line 512).
- Figure 10 shows the production of water is greater without an in-situ barrier (line 520) than either the case with an in-situ barrier (line 516) or the closer in-situ barrier (line 518).
- the results indicate that over about a 20 year production (about 7,300 days), the total oil production can be increased by over 20% and the total water production can be reduced by over about 40%. As one of ordinary skill in the art would understand, this represents a significant increase in the production of oil from the reservoir and a significant reduction in the amount of waste water that must be processed and disposed.
- Example 1 is used to simulate a reservoir with a 5-spot well configuration for this prophetic example.
- a well with an in-situ barrier is modeled between the injector and a producer.
- FIG. 1 1 depicts an aerial view of a water saturation profile in the formation after about 6,378 days with an in-situ barrier using the reservoir simulation.
- the simulation results show that the water front is effectively forced to flow around the in- situ barrier between the injector and producer.
- FIG. 12 depicts an aerial view of the water saturation profile for the configuration shown in FIG. 1 1 without an in-situ barrier.
- FIG. 11 shows that the water front is further advanced without the in-situ barrier between the injection well and production well.
- FIG. 13 and FIG. 14 depict the total oil production and total water production for the simulations shown in FIG. 1 1 and FIG. 12.
- Figure 13 shows the production of oil is less without an in-situ barrier (line 522) than the case with an in-situ barrier (line 524).
- Figure 14 shows 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 over about a 20 year production, the total oil production can be increased by about 9% and the total water production can be reduced by about 8% through the use of an in-situ barrier. As one of ordinary skill in the art would understand, this represents a significant increase in the production of oil from the reservoir and a significant reduction in the amount of waste water that must be processed and disposed.
- the same reservoir simulator described above in Example 1, is used to simulate an in-situ barrier comprising a relative permeability modifier for this prophetic example.
- the relative permeability modifier comprises a compound that is capable of reducing the permeability of a subterranean 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 to be preferentially oil-wet in the fracture creating a capillary barrier to 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.
- the flow of an aqueous fluid from a strong edge-water aquifer into a formation penetrated by a horizontal well is modeled.
- the horizontal well is modeled in a high permeability channel in order to simulate a high influx of oil.
- Such a channel also acts as a conduit for the influx of an aqueous fluid.
- the first case represented a base production case with no 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 set at l lO "6 millidarcy (md) for the second case.
- the third case represented an in-situ barrier using a relative permeability modifier that selectively blocks the flow of an aqueous fluid relative to oil and affects the oil-wet state of the formation.
- the absolute permeability of the in-situ barrier is set at 1 md.
- FIG. 15 depicts an aerial view of a permeability profile in the formation with respect to the horizontal wellbore and the high-permeability channel.
- FIG. 16 depicts an aerial view of the water saturation profile for the first case with no in-situ barrier. This first case demonstrates the channeling of water along the high permeability channel.
- FIG. 17 depicts an aerial view of a water saturation profile for the second case comprising an in-situ barrier. The simulation results show the coning of water around the in-situ barrier and flowing along the high permeability channel to the well bore.
- FIG. 18 depicts an aerial view of a water saturation profile for the third case with an in-situ barrier comprising a relative permeability modifier. The simulation results show the flow of water blocked by the in-situ barrier and a lack of coning due to the ability of the oil to flow through the barrier but not the aqueous fluid.
- the resulting cumulative production values after about 2,000 days of oil and water are: 12.8 MMBBL of oil and 7.1 MMBBL of water for the first case with no 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 potential to "design" the absolute permeability, relative permeability, and capillary pressure within a subterranean formation to baffle water, while allowing oil to more preferentially flow through the in-situ barrier to a producing well. As one of ordinary skill in the art would understand, this represents a significant increase in the production of oil from the reservoir and a significant reduction in the amount of waste water that must be processed and disposed.
- an in-situ barrier is modeled using a partial flow barrier for this prophetic example.
- the production is for about 4,000 days. No high permeability streak is present in the model.
- Four cases were modeled to determine the difference between the various types of in-situ barriers. The first case was the base case without an in-situ barrier.
- a partial barrier is modeled having a permeability of lmd and a relative permeability modifier is not present.
- a partial barrier is modeled having a permeability of lmd and a relative permeability modifier is present.
- the in-situ barrier comprised a full barrier to the flow of fluids.
- the resulting cumulative production values after about 4,000 days of oil and water are: 28.8 MMBBL of oil and 1 1.2 MMBBL of water for the first case with no in-situ barrier, 30.4 MMBBL of oil and 9.6 MMBBL of water for the second case with an in-situ partial barrier, 30.7 MMBBL of oil and 9.3 MMBBL of water for the third case with an in-situ partial 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 comprising full barrier to flow.
- this represents a significant increase in the production of oil from the reservoir and a significant reduction in the amount of waste water that must be processed and disposed.
Abstract
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AU2011225933A AU2011225933B2 (en) | 2010-03-10 | 2011-03-04 | Methods relating to modifying flow patterns using in-situ barriers |
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PCT/GB2011/000302 WO2011110802A1 (en) | 2010-03-10 | 2011-03-04 | Methods relating to modifying flow patterns using in-situ barriers |
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US (1) | US20110220359A1 (en) |
EP (1) | EP2545139A1 (en) |
AR (1) | AR080474A1 (en) |
AU (1) | AU2011225933B2 (en) |
CA (1) | CA2790891C (en) |
MX (1) | MX2012010431A (en) |
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CN104059307A (en) * | 2013-03-19 | 2014-09-24 | 河北科信特种橡塑有限公司 | Mass formula and production process for material used for seawater-swelling rubber waterstop |
CN109897554A (en) * | 2018-06-27 | 2019-06-18 | 湖北工业大学 | The modified assembling type outer wall plate splicing seams of Cellulose nanocrystal are bonded and sealed material |
CN109897554B (en) * | 2018-06-27 | 2021-01-12 | 湖北工业大学 | Cellulose nanocrystalline modified assembled external wall panel splicing seam bonding sealing material |
Also Published As
Publication number | Publication date |
---|---|
MX2012010431A (en) | 2012-10-01 |
CA2790891C (en) | 2015-11-24 |
EP2545139A1 (en) | 2013-01-16 |
AR080474A1 (en) | 2012-04-11 |
AU2011225933B2 (en) | 2014-02-06 |
CA2790891A1 (en) | 2011-09-15 |
AU2011225933A1 (en) | 2012-09-06 |
US20110220359A1 (en) | 2011-09-15 |
WO2011110802A8 (en) | 2012-10-18 |
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