WO2013112725A1 - Fluides de puits de forage utilisés avec des éléments pouvant gonfler dans l'huile - Google Patents

Fluides de puits de forage utilisés avec des éléments pouvant gonfler dans l'huile Download PDF

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Publication number
WO2013112725A1
WO2013112725A1 PCT/US2013/022971 US2013022971W WO2013112725A1 WO 2013112725 A1 WO2013112725 A1 WO 2013112725A1 US 2013022971 W US2013022971 W US 2013022971W WO 2013112725 A1 WO2013112725 A1 WO 2013112725A1
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Prior art keywords
fluid
oil
wellbore
wellbore fluid
oleaginous
Prior art date
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PCT/US2013/022971
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English (en)
Inventor
Matthew OFFENBACHER
Balkrishna Gadiyar
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M-I L.L.C.
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Publication date
Application filed by M-I L.L.C. filed Critical M-I L.L.C.
Priority to GB1414176.6A priority Critical patent/GB2513773A/en
Priority to BR112014018383-0A priority patent/BR112014018383B1/pt
Priority to NO20141016A priority patent/NO346916B1/no
Publication of WO2013112725A1 publication Critical patent/WO2013112725A1/fr
Priority to ECIEPI201415889A priority patent/ECSP14015889A/es

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Classifications

    • 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
    • C09K8/02—Well-drilling compositions
    • 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
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/426—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells for plugging
    • 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
    • C09K8/02—Well-drilling compositions
    • C09K8/03—Specific additives for general use in well-drilling compositions
    • 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
    • C09K8/02—Well-drilling compositions
    • C09K8/03—Specific additives for general use in well-drilling compositions
    • C09K8/035—Organic additives
    • 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
    • C09K8/02—Well-drilling compositions
    • C09K8/32—Non-aqueous well-drilling compositions, e.g. oil-based
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs

Definitions

  • Wellbore fluids or muds may include a base fluid, which is commonly water, diesel or mineral oil, or a synthetic compound. Weighting agents (most frequently barium sulfate or barite is used) may be added to increase density, and clays such as bentonite may be added to help remove cuttings from the well and to form a filtercake on the walls of the hole.
  • a base fluid which is commonly water, diesel or mineral oil, or a synthetic compound.
  • Weighting agents most frequently barium sulfate or barite is used
  • clays such as bentonite may be added to help remove cuttings from the well and to form a filtercake on the walls of the hole.
  • Wellbore fluids also contribute to the stability of the well bore, and control the flow of gas, oil or water from the pores of the formation in order to prevent, for example, the flow, or in undesired cases, the blow out of formation fluids or the collapse of pressured earth formations.
  • the column of fluid in the hole exerts a hydrostatic pressure proportional to the depth of the hole and the density of the fluid.
  • High-pressure formations may require a fluid with a density as high as about 10 pounds per gallon (ppg) and in some instances may be as high as 21 or 22 ppg.
  • Oil-based muds have been used because of their flexibility in meeting density, inhibition, friction reduction and rheological properties desired in wellbore fluids.
  • the drilling industry has used water-based muds (WBMs) because they are inexpensive.
  • WBMs and cuttings from wells drilled with WBMs can be readily disposed of onsite at most onshore locations. WBMs and cuttings can also be discharged from platforms in many U.S. offshore waters, as long as they meet current effluent limitations guidelines, discharge standards, and other permit limits.
  • annular fluids or packer fluids which are pumped into annular openings in a wellbore such as, for example, (1) between a wellbore wall and one or more casing strings of pipe extending into a wellbore, or (2) between adjacent, concentric strings of pipe extending into a wellbore, or (3) in one or both of an A- or B-annulus in a wellbore comprising at least an A- and B-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string, or (4) in one or more of an A-, B- or C-annulus in a wellbore comprising at least an A-, B- and C- annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other
  • said one or more strings of pipe may simply run through a conduit or outer pipe(s) to connect one or more wellbores to another wellbore or to lead from one or more wellbores to a centralized gathering or processing center; and said annular fluid may have been emplaced within said conduit or pipe(s) but external to said one or more strings of pipe therein.
  • Such packer fluids primarily serve to protect the casing but also serve to provide hydrostatic pressure in order to equalize pressure relative to the formation, to lower pressures across sealing elements or packers; or to limit differential pressure acting on the well bore, casing and production tubing to prevent collapse of the wellbore, and/or help control a well in the event of a leak in production tubing or when the packer no longer provides a seal or has been unseated. While the packer fluids may be formulated with sufficient density to perform such functions, conventionally, solid weighting agents that are often used in other wellbore fluids are avoided in packer fluids due to the concerns of solid settlement, particularly because packer fluids often remain in the annulus for extended periods of time without circulation.
  • Another category of wellbore or completion fluids include open hole fluids for uncased portions of the well.
  • the fluids are pumped into a vertical or high angle section of a wellbore where the target producing or injection formation often remains exposed during production or injection and/or may include any of the following: swellable packers, external casing packers, perforated liners, sand control screens or sand screens, basepipe, and/or selected inflow control devices which may or may not include gauges, control lines and even submersible pumps.
  • the open hole fluid is spotted in the open hole prior to and functions to facilitate the installation of any of the aforementioned.
  • the open hole fluid may provide functionality such that the packer/polymer expands, thus providing a barrier to control pressure, movement of fluids and enhance integrity of the lower installation.
  • embodiments disclosed herein relate to a method for completing a wellbore that includes introducing an oil-containing wellbore fluid into a wellbore having a water-based filtercake on walls thereof; contacting the oil-containing wellbore fluid with an oil-swellable element in the wellbore; and allowing swelling of the oil-swellable element, where the oil-containing wellbore fluid is substantially free of unassociated surfactants, emulsifiers, wetting agents, or dispersants and may include an oleaginous fluid and a weighting agent.
  • embodiments disclosed herein relate to a method of activating a oil-swellable packer system that includes introducing into a wellbore having a water- based filtercake on the walls thereof an oil-containing wellbore fluid; contacting the oil- containing wellbore fluid with an oil-swellable element in the wellbore; and allowing swelling of the oil-swellable element, where the oil-containing wellbore fluid includes an oleaginous continuous phase, wherein the oleaginous continuous phase forms substantially all of the fluid phase of the oil-containing wellbore fluid; an alkyl diamide, and an organophilic coated weighting agent having a particle size d9o of less than about 20 microns.
  • embodiments disclosed herein relate to a wellbore fluid that includes an oleaginous continuous phase, wherein the oleaginous continuous phase forms substantially all of the fluid phase of the wellbore fluid, an alkyl diamide, and an organophilic coated weighting agent having a particle size d9o of less than about 20 microns, wherein the wellbore fluid is substantially free of any unassociated surfactants, dispersants, or emulsifiers.
  • Figure 1 shows an isometric view of an example system in which embodiments of a sealing member may be implemented.
  • Figure 2 is a bar graph demonstrating the total volume increase of an oil-swellable packer when soaked in various swelling fluid formulations.
  • Figure 3 is a photograph demonstrating the compatibility of two swelling fluid formulations with a water-based filtercake.
  • Figure 4 is a bar graph demonstrating the swelling of an oil-swellable packer when soaked in a fluid sample as compared to diesel.
  • Embodiments disclosed herein relate to wellbore fluids (and methods of using such wellbore fluids) for various completion operations. Particularly, embodiments of the present disclosure relate to wellbore fluids used to activate oil-swellable polymer compositions of a swellable element for a well drilled with a water-based drilling fluid.
  • the oil-swellable elements (and thus wellbore fluids of the present disclosure) may be used in oil-swellable packer system applications such as, but not limited to, completing wells, plugging or abandoning wells, isolating zones of the well, reservoir compartmentalization or wellbore segmentation.
  • the wellbore fluids of the present disclosure may thus have several components including an oil-containing base fluid, such that there is a sufficient amount of the fluid that is free to diffuse into and swell the polymer, and a weighting agent to weight up the oleaginous fluid so that a higher density may be achieved.
  • the wellbore fluids of the present disclosure may also be used to activate a swellable polymer composition having been placed in the borehole as a packer element, in gravel packing, or other applications discussed herein.
  • the swellable composition may be oil-swellable material, which swells by diffusion of hydrocarbons into the oil-swellable material.
  • a wellbore may be drilled using a water-based drilling fluid, where the water-based drilling fluid filters into the formation to form a water-based filtercake.
  • a water-based filtecake is a filtercake that is water wet, and may be formed by any water-containing fluid, such as having water or an aqueous fluid as the major fluidic portion of the fluid and/or an any emulsion that produces a water-wet filtercake upon filtration into the formation.
  • the water-based drilling fluid may be displaced with an oil-containing wellbore fluid of the present disclosure, which is allowed to diffuse into oil-swellable materials placed downhole, such as an oil-swellable packer, for example, causing the oil-swellable materials to "activate" or swell.
  • an oil-containing wellbore fluid of the present disclosure which is allowed to diffuse into oil-swellable materials placed downhole, such as an oil-swellable packer, for example, causing the oil-swellable materials to "activate" or swell.
  • the oil-swellable packer may be incorporated in a screen assembly packer for an open hole completion prior to the production of hydrocarbons from a wellbore, in order to utilize the swellable packer to achieve zonal isolation and to block potential undesirable fluid incursion.
  • a screen assembly packer for an open hole completion prior to the production of hydrocarbons from a wellbore, in order to utilize the swellable packer to achieve zonal isolation and to block potential undesirable fluid incursion.
  • the wellbore fluid used to activate or swell the oil-swellable element may be an oil-containing fluid.
  • the fluid phase of the oil- containing wellbore fluid is formed solely or substantially entirely of an oleaginous liquid, substantially free of an aqueous component and substantially free of emulsifiers or the like.
  • the fluid phase of the wellbore fluid is formed of an oleaginous liquid, substantially free of an aqueous component and substantially free of emulsifiers, but may contain some volume of a non-aqueous, non-oleaginous fluid.
  • the oil-containing wellbore fluid may be a direct emulsion where an oleaginous fluid is a discontinuous phase within an aqueous or non-oleaginous continuous phase formulated to be substantially free of emulsifiers or the like.
  • the wellbore fluid is used to activate a swellable packer system or other swellable elements.
  • Swellable packer systems include a swellable composition that may be used to fill a space in the wellbore.
  • the swellable packer system may consist of the swellable composition alone, but in some embodiments, the swellable packer system includes the swellable composition used as a tool component in completion operations where a packer element is placed in a producing interval of the wellbore to provide annular isolation between an upper and lower section of the well.
  • the swellable composition is attached to a base pipe, liner, or even the casing. Swelling of the composition may be initiated at any time, but in some embodiments the composition swells at least after the equipment is installed in the well.
  • swellable compositions are those that swell or expand when exposed to a specific substance or substances, such as water or hydrocarbons, to a size that is larger than the size of the pre-swelled element.
  • the base fluid of the wellbore fluid used in conjunction with the swellable compositions is absorbed into the swellable packer through diffusion. Through the random thermal motion of the molecules in the liquid, the fluid diffuses into the packer. When the packer is wrapped around the outer circumference of a tubular, the result of swelling is an increase of the manufactured outside diameter of the swellable packer.
  • the fluid may continue to diffuse into the packer causing the packing element to swell so that it reaches the inside diameter of the casing or the open hole of the well, and will continue to swell until the internal stresses inside the packer material reach equilibrium. That is, the swell pressure increases until diffusion can no longer occur.
  • the swellable element may swell at least sufficiently such that the swellable element creates a seal in the annulus, such as a differentially sealing annular barrier that is created between upper and lower sections of the well.
  • the swellable packer may be used to create a barrier between designated sections of an open hole to allow selective isolation during completion or post completion.
  • the thickness of the swellable element may swell at least 5%, at least 10%, at least 15%, at least 20%, at least 25%, or at least 50%.
  • the swellable element may be constrained to expand in a radial direction only, but in other embodiments may expand both radially and axially.
  • Other embodiments may include a swellable element in a bridge plug, which is a tool that can be located and set in a wellbore in order to isolate a lower part of the wellbore from an upper part of the wellbore.
  • a swellable packer or other element such as a bridge plug may placed in a portion of a wellbore having been drilled, in embodiments, with a water-based fluid such that a water-based filtercake remains on wellbore walls.
  • a water-based fluid such that a water-based filtercake remains on wellbore walls.
  • more than one swellable element may be placed in the wellbore.
  • a combination of swellable packers and/or bridge plugs may also be placed in portions of a wellbore.
  • a swelling fluid is then introduced directly into the annulus itself, or introduced into the annulus via the tubing string or casing.
  • the swelling fluid may be allowed to contact the swellable element of the packer or bridge plug, which causes the swellable element to begin swelling.
  • the swelling fluid may be allowed to remain in contact with the swellable element for a sufficient time for the swellable element to swell and expand to a sufficient size to seal the annulus.
  • Swellable compositions used in the methods of the present disclosure may be formed from various materials that sufficiently swell or expand in the presence of hydrocarbons.
  • Illustrative swellable materials may be natural rubbers, nitrile rubbers, hydrogenated nitrile rubber, ethylene-propylene-copolymer rubber, ethylene-propylene- diene terpolymer rubber, butyl rubber, halogenated butyl rubber, brominated butyl rubber, chlorinated butyl rubber, chlorinated polyethylene, starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, isobutylene maleic anhydride, polyacrylates, acrylate butadiene rubber, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch- polyacrylonitrile graft copolymers, styrene, styrene-butadiene rubber
  • the wellbore fluid may be oil-containing.
  • the oil-containing wellbore fluid may contain an amount of an oleaginous fluid sufficient to activate the swellable composition by diffusion of the oleaginous fluid into the oil-swellable material.
  • the amount of oil that will cause sufficient swelling of the swellable element to engage and seal against the corresponding wellbore component may vary, for example, based on the size of the packer, the extent of swelling/expansion of the element required, etc.
  • the oil-containing fluids of the present disclosure may include an oleaginous fluid as the continuous phase of the fluid, whereas other embodiments may use a direct emulsion where the oleaginous fluid is a discontinuous phase within an aqueous or non-oleaginous continuous phase.
  • Oleaginous fluids may be a liquid, such as a natural or synthetic oil and in some embodiments, the oleaginous fluid may be selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids, mixtures thereof and similar compounds known to one of skill in the art; and mixtures thereof.
  • the fluids may be formulated using diesel oil or a synthetic oil as the external, continuous phase.
  • the oleaginous fluid may be present without any aqueous or non-oleaginous phase or may be substantially free of an aqueous and/or non-oleaginous fluid (such as those discussed below).
  • substantially free of an aqueous or non-oleaginous fluid may be interpreted to mean that the fluid contains less than 20 vol% of an aqueous or non-oleaginous fluid, or less than 10 vol% or 5 vol% in other embodiments.
  • the fluid may contain a non-aqueous, non-oleaginous fluid having partial miscibility (i.e., some but not total solubility, such as at least 10-25% or greater miscibility) with the oleaginous fluid in an amount that is in excess of 20 vol%.
  • a non-aqueous, non-oleaginous fluid having partial miscibility i.e., some but not total solubility, such as at least 10-25% or greater miscibility
  • mutual solvents i.e., a fluid having solubility in both aqueous and oleaginous fluids, may be present in the oleaginous fluid, including in the oleaginous fluids that are at least substantially free of an aqueous or non-oleaginous fluid.
  • Such mutual solvents include for example, isopropanol, diethylene glycol monoethyl ether, dipropylene glycol monomethyl ether, tripropylene butyl ether, dipropylene glycol butyl ether, diethylene glycol butyl ether, butylcarbitol, dipropylene glycol methylether, various esters, such as ethyl lactate, propylene carbonate, butylene carbonate, etc, and pyrolidones.
  • the fluid When formulated without or substantially free of an aqueous or non-oleaginous phase (or even if containing a non-aqueous, non-oleaginous fluid with partial miscibility with an oleaginous fluid), the fluid may also be free or substantially free of any unassociated surfactants, wetting agents, dispersants, or emulsifiers, i.e., any amphiphilic compounds possessing both hydrophilic and hydrophobic groups within the molecule.
  • unassociated refers to molecules that are not chemically bound to or otherwise chemically or physically associated with another species (such as a solid weighting agent).
  • a dispersant or wetting agent that is provided as a coating on weighting agent would be considered to be associated, not unassociated.
  • substantially free of an unassociated surfactant, wetting agent, dispersant or emulsifier means less than an amount that would generate an invert emulsion for any amount of an aqueous or non-oleaginous fluid present in the fluid. Such amounts may, for example, be less than 5 pounds per barrel (ppb) or less than 4 ppb, 3 ppb, 2 ppb, or 1 ppb, in other embodiments.
  • a wetting agent or dispersant may be provided to coat a solid weighting agent, but the amount added would not be so much that an invert emulsion could be formed with any excess wetting agent or dispersant. Such excess may be less than 5 ppb, 4 ppb, 3 ppb, 2 ppb, or 1 ppb, in various embodiments.
  • the wellbore fluid may be a direct emulsion having an aqueous or non-oleaginous fluid as a continuous phase, where the oleaginous fluid is provided as a discontinuous phase provided therein.
  • Direct emulsions may be formulated to be substantially free of an emulsifier, surfactant, dispersant, or wetting agent, as defined above.
  • Non-oleaginous fluids that may be used in the embodiments disclosed herein may be a liquid, such as an aqueous liquid.
  • the non-oleaginous liquid may be selected from the group including fresh water, sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds and combinations thereof.
  • the aqueous fluid may be formulated with mixtures of desired salts in fresh water.
  • Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example.
  • the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water.
  • Salts that may be found in seawater include, but are not limited to, sodium, calcium, aluminum, magnesium, potassium, strontium, and lithium, salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, phosphates, sulfates, silicates, and fluorides. Salts that may be incorporated in a given brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts. Additionally, brines that may be used in the wellbore fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution.
  • the density of the wellbore fluid may also be controlled by increasing the salt concentration in the brine (up to saturation).
  • a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium.
  • Specific examples of such salts include, but are not limited to, NaCl, CaCl 2 , NaBr, CaBr 2 , ZnBr 2 , NaHC0 2 , KHC0 2 , KC1, NH4CI, CsHC0 2 , MgCl 2 , MgBr 2 , KH 3 C 2 0 2 , KBr, NaH 3 C 2 0 2 and combinations thereof.
  • the wellbore fluid may contain an oleaginous fluid (to swell the oil-swellable element) in an amount that has a lower limit of any of 10 vol%, 20 vol%, 30 vol%, 40 vol% or 50 vol%, and an upper limit of any of 40 vol%, 50 vol%, 60 vol%, 70 vol%, or 80 vol%, with any lower limit being combinable with any upper limit.
  • the oleaginous fluid may form 20-70 vol% of the wellbore fluid, 30-60 vol%, or 40-50 vol%, with the balance of the fluidic portion being the non-oleaginous fluid.
  • the density of the fluid may be increased by incorporation of a solid weighting agent.
  • Solid weighting agents used in some embodiments disclosed herein may include a variety of inorganic compounds well known to one of skill in the art.
  • the weighting agent may be selected from one or more of the materials including, for example, barium sulphate (barite), calcium carbonate (calcite or aragonite), dolomite, ilmenite, hematite or other iron ores, olivine, siderite, manganese oxide, and strontium sulphate.
  • barium sulphate barite
  • calcium carbonate calcite or aragonite
  • dolomite ilmenite
  • hematite or other iron ores olivine
  • siderite manganese oxide
  • strontium sulphate calcium carbonate or another acid soluble solid weighting agent may be used.
  • the weighting agent may be formed of particles that are composed of a material of specific gravity of at least 2.3; at least 2.4 in other embodiments; at least 2.5 in other embodiments; at least 2.6 in other embodiments; and at least 2.68 in yet other embodiments. Higher density weighting agents may also be used with a specific gravity of about 4.2, 4.4 or even as high as 5.2.
  • a weighting agent formed of particles having a specific gravity of at least 2.68 may allow wellbore fluids to be formulated to meet most density requirements yet have a particulate volume fraction low enough for the fluid to be pumpable.
  • the wellbore fluid may be formulated with calcium carbonate or another acid-soluble material.
  • the solid weighting agents may be of any particle size (and particle size distribution), but some embodiments may include weighting agents having a smaller particle size range than API grade weighing agents, which may generally be referred to as micronized weighting agents. Such weighting agents may generally be in the micron (or smaller) range, including submicron particles in the nanosized range.
  • the average particle size (d50) of the weighting agents may range from a lower limit of greater than 5 nm, 10 nm, 30 nm, 50 nm, 100 nm, 200 nm, 500 nm, 700 nm, 0.5 micron, 1 micron, 1.2 microns, 1.5 microns, 3 microns, 5 microns, or 7.5 microns to an upper limit of less than 500 nm, 700 microns, 1 micron, 3 microns, 5 microns, 10 microns, 15 microns, 20 microns, where the particles may range from any lower limit to any upper limit.
  • the d90 (the size at which 90% of the particles are smaller) of the weighting agents may range from a lower limit of greater than 20 nm, 50 nm, 100 nm, 200 nm, 500 nm, 700 nm, 1 micron, 1.2 microns, 1.5 microns, 2 microns, 3 microns, 5 microns, 10 microns, or 15 microns to an upper limit of less than 30 microns, 25 microns, 20 microns, 15 microns, 10 microns, 8 microns, 5 microns, 2.5 microns, 1.5 microns, 1 micron, 700 nm, 500 nm, where the particles may range from any lower limit to any upper limit.
  • the weighting agent may have a particle size distribution other than a monomodal distribution. That is, the weighting agent may have a particle size distribution that, in various embodiments, may be monomodal, which may or may not be Gaussian, bimodal, or polymodal.
  • a weighting agent is sized such that: particles having a diameter less than 1 microns are 0 to 15 percent by volume; particles having a diameter between 1 microns and 4 microns are 15 to 40 percent by volume; particles having a diameter between 4 microns and 8 microns are 15 to 30 by volume; particles having a diameter between 8 microns and 12 microns are 5 to 15 percent by volume; particles having a diameter between 12 microns and 16 microns are 3 to 7 percent by volume; particles having a diameter between 16 microns and 20 microns are 0 to 10 percent by volume; particles having a diameter greater than 20 microns are 0 to 5 percent by volume.
  • the weighting agent is sized so that the cumulative volume distribution is: less than 10 percent or the particles are less than 1 microns; less than 25 percent are in the range of 1 microns to 3 microns; less than 50 percent are in the range of 2 microns to 6 microns; less than 75 percent are in the range of 6 microns to 10 microns; and less than 90 percent are in the range of 10 microns to 24 microns.
  • weighting agents having such size distributions has been disclosed in U.S. Patent Application Publication Nos. 2005/0277553 and 2010/0009874, which are assigned to the assignee of the current application, and herein incorporated by reference. Particles having these size distributions may be obtained any means known in the art.
  • the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (d50) of less than 10 microns that are coated with an organophilic, polymeric deflocculating agent or dispersing agent. In other embodiments, the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (d50) of less than 8 microns that are coated with a polymeric deflocculating agent or dispersing agent; less than 6 microns in other embodiments; less than 4 microns in other embodiments; and less than 2 microns in yet other embodiments.
  • the fine particle size will generate suspensions or slurries that will show a reduced tendency to sediment or sag, and the polymeric dispersing agent on the surface of the particle may control the inter-particle interactions and thus will produce lower rheological profiles. It is the combination of fine particle size and control of colloidal interactions that reconciles the two objectives of lower viscosity and minimal sag.
  • the weighting agents may be uncoated.
  • the weighting agents may be coated with an organophilic coating such as a dispersant, including carboxylic acids of molecular weight of at least 150 Daltons, such as oleic acid, stearic acid, and polybasic fatty acids, alkylbenzene sulphonic acids, alkane sulphonic acids, linear alpha-olefin sulphonic acid, and alkaline earth metal salts thereof.
  • suitable dispersants may include a polymeric compound, such as a polyacrylate ester composed of at least one monomer selected from stearyl methacrylate, butylacrylate and acrylic acid monomers.
  • the illustrative polymeric dispersant may have an average molecular weight from about 10,000 Daltons to about 200,000 Daltons and in another embodiment from about 17,000 Daltons to about 30,000 Daltons.
  • One skilled in the art would recognize that other acrylate or other unsaturated carboxylic acid monomers (or esters thereof) may be used to achieve substantially the same results as disclosed herein.
  • the coated weighting agents may be formed by either a dry coating process or a wet coating process.
  • Weighting agents suitable for use in other embodiments disclosed herein may include those disclosed in U.S. Patent Application Publication Nos. 2004/0127366, 2005/0101493, 2006/0188651, 2008/0064613, and U.S. Patent Nos. 6,586,372 and 7,176,165, each of which is hereby incorporated by reference.
  • the particulate materials as described herein may be added to a wellbore fluid as a weighting agent in a dry form or concentrated as slurry in either an aqueous medium or as an organic liquid.
  • an organic liquid may have the environmental characteristics required for additives to oil- containing wellbore fluids.
  • the oleaginous fluid may have a kinematic viscosity of less than 10 centistokes (10 mm2/s) at 40°C and, for safety reasons, a flash point of greater than 60°C.
  • Suitable oleaginous liquids are, for example, diesel oil, mineral or white oils, n-alkanes or synthetic oils such as alpha-olefin oils, ester oils, mixtures of these fluids, as well as other similar fluids known to one of skill in the art of drilling or other wellbore fluid formulation.
  • the desired particle size distribution is achieved via wet milling of the coarser materials in the desired carrier fluid.
  • Such solid weighting agents may be particularly useful in wellbore fluids formulated with an entirely oleaginous fluid phase.
  • an organophilic coated weighting agent having a particle size within any of the described ranges may be used in a fluid free of or substantially free of an aqueous phase contained therein.
  • Solid weighting agents may also be used in the direct emulsion emulsions of the present disclosure to provide additional density beyond that provided by the aqueous phase as needed.
  • the wellbore fluid may have a density of greater than about 8.0 pounds per gallon (ppg), or at least 10, 12, or 14 ppg in other embodiment.
  • the density of the wellbore fluid in some embodiments ranges from about 6 to about 18 ppg, where the weighting agent is added in an amount to increase the density of the base fluid by at least 1 ppg or by at least 2, 4, or 6 ppg in other embodiments.
  • additives that may be included in the wellbore fluids disclosed herein include, for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, and cleaning agents.
  • wetting agents for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, and cleaning agents.
  • additives may be included in the composition to modify rheological properties, such as viscosity and flow.
  • organic thixotropes suitable for addition to wellbore fluids of the present disclosure include alkyl diamides, such as those having a general formula: Rl-FTN-CO-(CH 2 ) n -CO-NH-R2, wherein n is an integer from 1 to 20, from 1 to 4, or from 1 to 2, and Rl is an alkyl groups having from 1 to 20 carbons, from 4 to 12 carbons, or 5 to 8 carbons, and R2 is hydrogen or an alkyl group having from 1 to 20 carbons, or is hydrogen or an alkyl group having from 1 to 4 carbons, wherein Rl and R2 may or may not be identical.
  • alkyl diamides may be obtained, for example, from M-I L.L.C. (Houston, TX) under the trade name of VERSAPACTM.
  • Such alkyl diamide viscosifiers may be particularly suitable for use in an oil-containing wellbore fluid substantially free of an aqueous or non-oleaginous fluid, but may also be included in direct emulsions.
  • organophilic clays such as amine treated clays, may be useful as viscosifiers in the fluid composition of the present disclosure.
  • VG-69TM and VG-PLUSTM are organoclay materials, available from M-I L.L.C, Houston, Texas, that may be used in embodiments disclosed herein.
  • organophilic clays, as well as water- based clays may be particularly useful in assisting in the formation and stabilization of a direct emulsion.
  • PGP A partially hydrolyzed polyacrylamide
  • biopolymers such as guar gum, starch, xanthan gum and the like
  • bentonite attapulgite
  • sepiolite polyamide resins
  • polyamide resins polyanionic carboxymethylcellulose (PAC or CMC)
  • PAC or CMC polyanionic carboxymethylcellulose
  • polyacrylates lignosulfonates, as well as other water soluble polymers.
  • the viscosifier may be incorporated to increase the viscosity and thus miscibility of the two phases, such that a direct (oil-in-water) emulsion is formed upon mixing in a high shear mixer, as that term is understood by those of ordinary skill in the art, operating at at least 3500 rpm, or at least 5000 or 7000 rpm in other embodiments.
  • fumed silicas and/or precipitated silica may be used as a viscosifying agent.
  • precipitated silicas may advantageously be used to provide both weighting and viscosifying of the oleaginous base fluid.
  • the precipitated silicas may be used in addition to or in place of the weighting agents described above.
  • the relative amounts of the weighting agent and the precipitated silica in the wellbore fluid formulation may be adjusted such that the wellbore fluid has both the desired density and flow properties.
  • Precipitated silicas have a porous structure and may be prepared from the reaction of an alkaline silicate solution with a mineral acid.
  • Alkaline silicates may be selected, for example, from one or more of sodium silicate, potassium silicate, lithium silicate and quaternary ammonium silicates.
  • Precipitated silicas may be produced by the destabilization and precipitation of silica from soluble silicates by the addition of a mineral acid and/or acidic gases.
  • the reactants thus include an alkali metal silicate and a mineral acid, such as sulfuric acid, or an acidulating agent, such as carbon dioxide.
  • Precipitation may be carried out under alkaline conditions, for example, by the addition of a mineral acid and an alkaline silicate solution to water with constant agitation.
  • the choice of agitation, duration of precipitation, the addition rate of reactants, temperature, concentration, and pH may vary the properties of the resulting silica particles.
  • Precipitated silicas useful in embodiments herein may include finely-divided particulate solid materials, such as powders, silts, or sands, as well as reinforced floes or agglomerates of smaller particles of siliceous material.
  • the precipitated silica (or agglomerates thereof) may have an average particle size (D50) of less than 50 microns; less than 20 microns in other embodiments; and in the range from about 1 micron to about 10 microns, such as about 4 to about 6 microns, in yet other embodiments.
  • precipitated silicas having a larger initial average particle size may be used, where shear or other conditions may result in comminution of the particles, such as breaking up of agglomerates, resulting in a silica particle having a useful average particle size.
  • Precipitated silicas may contain varying amounts of residual alkali metal salts that result from the association of the corresponding silicate counterion with available anions contributed by the acid source.
  • Residual salts may have the basic formula MX, where M is a group 1 alkali metal selected from Li, Na, K, Cs, a group 2 metal selected from Mg, Ca, and Ba, or organic cations such as ammonium, tetraalkyl ammonium, imidazolium, alkyl imidazolium, and the like; and X is an anion selected from halides such as F, CI, Br, I, and/or sulfates, sulfonates, phosphonates, perchlorates, borates, and nitrates.
  • MX is a group 1 alkali metal selected from Li, Na, K, Cs, a group 2 metal selected from Mg, Ca, and Ba, or organic cations such as ammonium, tetraalkyl ammonium, imidazolium, alkyl imidazolium, and the like
  • X is an anion selected from halides such as F, CI, Br, I
  • the residual salts may be selected from one or more of a 2 S0 4 and NaCl, and the precipitated silica may have a residual salt content (equivalent Na2S04) of less than about 2 wt.%.
  • the pH of the resulting precipitated silicas may vary, embodiments of the silicas useful in embodiments disclosed herein may have a pH in the range from about 6.5 to about 9, such as in the range from about 6.8 to about 8.
  • surface-modified precipitated silicas may be used.
  • the surface-modified precipitated silica may include a lipophilic coating, for example.
  • the surface modification may be added to the silica after precipitation.
  • the silica may be precipitated in the presence of one or more of the surface modification agents described above.
  • surface-modified precipitated silicas according to embodiments herein may advantageously provide for both weighting and viscosifying of the oleaginous base fluid.
  • Precipitated silicas according to embodiments herein are useful for providing wellbore fluids having enhanced thermal stability in temperature extremes, while exhibiting a substantially constant rheological profile over time.
  • the surface of the silica particles may be chemically modified by a number of synthetic techniques.
  • Surface functionality of the particles may be tailored to improve solubility, dispersibility, or introduce reactive functional groups. This may be achieved by reacting the precipitated silica particles with organosilanes or siloxanes, in which reactive silane groups present on the molecule may become covalently bound to the silica lattice that makes up the particles.
  • Non-limiting examples of compounds that may be used to functionalize the surface of the precipitated silica particles include aminoalkylsilanes such as aminopropyltriethoxy silane, aminomethyltriethoxysilane, trimethoxy[3-(phenylamino)propyl]silane, and trimethyl[3- (triethoxysilyl)propyl] ammonium chloride; alkoxyorganomercapto silanes such as bis(3- (triethoxysilylpropyl) tetrasulfide, bis(3-(triethoxysilylpropyl) disulfide, vinyltrimethoxy silane, vinyltriethoxy silane, 3-mercaptopropyltrimethoxy silane; 3- mercaptopropyltriethoxy silane; 3-aminopropyltriethoxysilane and 3- aminopropyltrimethoxysilane; and alkoxysilanes.
  • aminoalkylsilanes such
  • organo-silicon materials that contain reactive end groups may be covalently linked to the surface of the silica particles.
  • Reactive polysiloxanes may include, for example, diethyl dichlorosilane, phenyl ethyl diethoxy silane, methyl phenyl dichlorosilane, 3,3,3-trifluoropropylmethyl dichlorosilane, trimethylbutoxy silane, sym -diphenyltetramethyl disiloxane, octamethyl trisiloxane, octamethyl cyclotetrasiloxane, hexamethyl disiloxane, pentamethyl dichlorosilane, trimethyl chlorosilane, trimethyl methoxy silane, trimethyl ethoxysilane, methyl trichlorosilane, methyl triethoxysilane, methyl trimethoxysilane, hexamethyl cyclotrisilox
  • the surface-modified precipitated silicas may have a BET-5 nitrogen surface area of less than about 200 m 2 /g. In some embodiments, the surface area of the surface- modified precipitated silica may be less than about 150 m 2 /g. In other embodiments, the surface area may be in the range from about 20 m 2 /g to about 70 m 2 /g.
  • the precipitated silica has a BET-5 nirtogen surface area of 20 m 2 /g to 70 m 2 /g, as calculated from the surface adsorption of 2 using the BET-1 point method, a pH in the range of pH 7.5 to pH 9, and an average particle diameter in the range of 20 nm to 100 nm.
  • precipitated silicas useful in embodiments herein may include those as disclosed in U.S. Patent Application Publication Nos. 2010/0292386, 2008/0067468, 2005/0131107, 2005/0176852, 2006/0225615, 2006/0228632, and 2006/0281009, each of which is incorporated herein by reference.
  • Fluid loss control agents may act to prevent the loss of fluid to the surrounding formation by reducing the permeability of the barrier of solidified wellbore fluid.
  • Suitable fluid loss control agents may include those such as modified lignites, asphaltic compounds, gilsonite, organophilic humates prepared by reacting humic acid with amides or polyalkylene polyamines, and other fluid loss additives such as a methylstyrene/acrylate copolymer.
  • Such fluid loss control agents may be employed in an amount which is at least from about 0.5 to about 15 pounds per barrel.
  • the fluid-loss reducing agent should be tolerant to elevated temperatures, and inert or biodegradable.
  • ECOTROL RDTM an oil-soluble polymeric fluid control agent that may be used in the wellbore fluid, is commercially available from M-I L.L.C., Houston, Texas.
  • annular sealing member (packer) is deployed in a wellbore.
  • Figure 1 depicts an embodiment of an annular sealing member 100 including portions made of the swellable composition.
  • the sealing member 100 can include a support member 110 having an outer swellable element 120 disposed about an outer diameter thereof.
  • the support member 110 can also have an inner swellable element 130 disposed about an inner diameter thereof.
  • the support member 110 can have apertures 115 formed therethrough allowing the outer swellable element 120 to unitize with the inner swellable element 130.
  • the outer swellable element 120 can be disposed about the support member 110 and can be configured to engage a wall of a wellbore or other structure disposed about the outer swellable element 120.
  • the inner swellable element 130 can be configured to swell within the support member 110 about a tubular or other object at least partially disposed within the support member 110.
  • the swellable elements 120 and 130 are unitized, allowing the sealing member 100 to resist differential pressure.
  • the swellable elements 120 and 130 can be made of the swellable composition.
  • an oil-containing wellbore fluid (such as any of those described above) is formed by mixing a base fluid with a weighting agent (such as a micronized weighting agent) along with additives that provide for the proper rheological properties required for the well.
  • the wellbore fluid is then pumped downhole (either directly into the annulus or through a tubing string) and allowed to come into contact with the swellable elements placed in the wellbore (previously or subsequently placed therein).
  • the oil-containing wellbore fluid may displace a water-based wellbore fluid used to drill at least a portion of the wellbore.
  • the water based drilling fluid may be first displaced with a conditioned mud, a solids free mud, or a brine prior to introduction to the oil-containing fluid of the present disclosure.
  • the oil-containing fluid may be pumped into a wellbore having a water-based filter cake on the walls thereof, without the water-based filter cake being removed and the well otherwise being cleaned.
  • the oil-containing fluid may diffuse into the oil-swellable elements 120 and 130, which may swell until the internal stresses inside the polymer reach equilibrium. That is, the swell pressure increases until diffusion can no longer occur.
  • the oil-containing fluid of the present disclosure is introduced into an uncased portion of the well, below the packer element.
  • Other embodiments may involve introduction of the oil-containing fluid above the packer element or both above and below the packer element.
  • a "well” includes at least one wellbore drilled into a subterranean formation, which may be a reservoir or adjacent to a reservoir.
  • a wellbore may have vertical and horizontal portions, and it may be straight, curved, or branched.
  • the wellbore may be an open-hole or cased-hole.
  • a tubing string which allows fluids to be placed into or removed from the wellbore, is placed into the wellbore.
  • a casing is placed into the wellbore, and a tubing string can be placed in the casing.
  • An annulus is the space between two concentric objects, such as between the wellbore and casing, or between casing and tubing, where fluid can flow.
  • Annular sealing members suitable for use in other embodiments disclosed herein may include, but are not limited to, those disclosed in U.S. Patent Application Publication Nos. 2007/0151724, 2007/0205002, 2008/0308283, and U.S. Patent Nos. 7,143,832 and 7,849,930, each of which is hereby incorporated by reference in their entirety. Sealing members can also be used in combination with any other tools where isolation of wellbore segments is desired.
  • the illustrated embodiment is one example of many potential applications, it is provided for purposes of explanation. Many other types of applications utilizing a variety of completion equipment, gravel pack techniques and wellbore orientations can benefit from the swellable packer system described.
  • the packer may be incorporated in a screen assembly packer for an open hole completion to utilize the swellable packer to achieve zonal isolation and to block potential undesirable fluid incursion as disclosed in U.S. Patent Application Publication No. 2007/0151724, which is hereby incorporated by reference in its entirety.
  • the oil-containing fluids of the present disclosure may be used to swell an oil-swellable packer composition that is used in a wellbore having been drilled with a water-based drilling fluid, where there is residual water-based fluid in the form of a water-based filtercake remaining in the well.
  • Such fluids may include any water-based drilling fluid known in the art, which may contain an aqueous fluid (such as those described above) forming substantially all of the fluidic portion of the fluid, one or more solid particles including bridging agents or weighting agents known in the art, fluid loss control and/or viscosifiers, such as xanthan or other natural or synthetic polymers, as well as other additives known in the art of drilling fluids.
  • Diesel oil was used as a control in Sample 1.
  • a conventional 60:40 oil-to-water ratio (OWR) invert system was blended for Sample 2 using VERSCOATTM, VERSA WETTM in order to oil-wet the system and maintain an invert emulsion with the brine phase, and SAFE-CARBTM 2, as the weighting agent.
  • a high internal phase ratio (HIPR) emulsion was prepared for Sample 3 containing no solids and a special emulsifier that maintains a water-in-oil system at very low OWR not possible using conventional chemistry.
  • Sample 4 is an all-oil system prepared with the organic alkyl diamide viscosifier to achieve suspension of the organophiliic coated calcium carbonate weighting agent, which may decrease or eliminate the need for an emulsifier or wetting agent within the fluid.
  • Table 2 Calculated change in oil-swellable packer coupon size after exposure to various oil-based fluids.
  • a production screen test (PST) was performed.
  • the production screen test consists of a 1.2 liter pressurized cell where fluid is passed through a sand control screen coupon. A failure of the test would be indications of plugging from a change in the rate at which fluid passes through the coupon is noted or plugging stops the flow of fluid entirely.
  • the PST was performed using a 1 liter volume of fluid at 20 psi through a 6 gauge wire wrap screen. There were no signs of plugging as the fluid freely passed through in 6.53 seconds.
  • the wire wrap screen coupon was removed, gently rinsed in solvent to check for visual signs of solids trapped in the coupon. The coupon appeared clean with no signs of trapped materials.
  • Sample 5 was also subjected to a swell test, in which a sample of oil-swellable elastomer material was placed in a cell containing a volume of Sample 5.
  • the elastomer coupon was static aged in the fluid sample for 18 hours at 180F, and then measured using a digital caliper initially, and after aging, to compare the coupon for swell performance.
  • the measurements recorded include top width, bottom width, height, and thickness, as shown in Table 7 below.
  • a comparison (an increase in swell as a linear measure) of a the Sample 5 soaked-coupon against an elastomeric coupon soaked in diesel for 18 hours at room temperature (due to safety concerns) is presented in Figure 4.
  • Embodiments of the present disclosure relate to a wellbore fluid that may be used in the completion of a well.
  • the present disclosure may advantageously allow for the use of an oil-swellable packer that may have better sealing characteristics than a water-swellable packer.
  • embodiments of the present disclosure may also allow for the use of an oil-containing fluid that can be weighted to needed density (for well control) without risk of particle settlement.
  • the elimination or reduced amount of the emulsifier, surfactants, or wetting agents may be desirable to minimize the interaction between the water-based filtercake and the oil-containing wellbore fluid, thus simplifying displacement logistics between water- and oil-containing fluids.

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Abstract

Procédé de réalisation d'un puits de forage pouvant consister à introduire un fluide de puits de forage contenant de l'huile dans un puits de forage ayant un gâteau de filtration à base d'eau sur les parois de celui-ci, à mettre en contact le fluide de puits de forage contenant de l'huile avec un élément pouvant gonfler dans l'huile dans le puits de forage ; et à permettre le gonflage de l'élément pouvant gonfler dans l'huile, le fluide de puits de forage contenant de l'huile étant sensiblement dépourvu d'agents de surface, d'émulsifiants, d'agents d'humidification ou d'agents de dispersion non associés et pouvant comprendre un fluide oléagineux et un agent de pondération.
PCT/US2013/022971 2012-01-25 2013-01-24 Fluides de puits de forage utilisés avec des éléments pouvant gonfler dans l'huile WO2013112725A1 (fr)

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GB1414176.6A GB2513773A (en) 2012-01-25 2013-01-24 Wellbore fluids used with oil-swellable elements
BR112014018383-0A BR112014018383B1 (pt) 2012-01-25 2013-01-24 Método para completar um poço, método para ativar um sistema obturador expansível em óleo, e fluido de poço
NO20141016A NO346916B1 (no) 2012-01-25 2013-01-24 Borehullsfluider anvendt med oljesvellbare elementer
ECIEPI201415889A ECSP14015889A (es) 2012-01-25 2014-08-26 Fluído de pozo utilizado con elementos hinchables del petroleo

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WO2017019993A1 (fr) * 2015-07-29 2017-02-02 M-I L.L.C. Procédés de formulation de fluides de forage
WO2020023401A1 (fr) * 2018-07-26 2020-01-30 Halliburton Energy Services, Inc. Émulsifiants pour fluides de forage en émulsion directe

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WO2017019963A1 (fr) * 2015-07-29 2017-02-02 M-I L.L.C. Fluides pour puits de forage destinés à être utilisés en fond de trou
WO2017019993A1 (fr) * 2015-07-29 2017-02-02 M-I L.L.C. Procédés de formulation de fluides de forage
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US11034877B2 (en) 2018-07-26 2021-06-15 Halliburton Energy Services, Inc. Emulsifiers for direct emulsion drilling fluids

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ECSP14015889A (es) 2015-09-30
NO346916B1 (no) 2023-02-27
CO7151481A2 (es) 2014-12-29
BR112014018383A2 (fr) 2017-06-20
BR112014018383B1 (pt) 2021-09-08
GB201414176D0 (en) 2014-09-24
BR112014018383A8 (pt) 2017-07-11

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