BR112014018383B1 - METHOD TO COMPLETE A WELL, METHOD TO ACTIVATE AN EXPANDABLE OIL AND WELL FLUID OIL FILTER SYSTEM - Google Patents

Abstract

method for completing a well, method for activating an oil expandable plug system, and well fluid. a method of completing a well may include introducing an oil-containing well fluid into a well having a water-based plaster on its walls, contacting the oil-containing well fluid with an oil-expandable element in the well; and allowing expansion of the expandable element in oil, wherein the oil-containing well fluid is substantially free of surfactants, emulsifiers, surfactants, or disassociated dispersants, and may include an oleaginous fluid and a thickener.

Description

FUNDAMENTALS

[0001] When completing wells in onshore formations, various fluids are generally used in the well for a variety of reasons. Common uses for well fluids include: lubricating and cooling the drill bit by cutting surfaces during general drilling operations, or drilling in an oil oriented formation, suspending loose pieces of formation and transporting them to the surface, controlling the fluid pressure of the well. formation to prevent explosions, maintain stability of the well and minimize fluid loss into the formation, in which the well is being drilled, fracture the formation in the vicinity of the well, displace the fluid within the well with another fluid, clean the well, test the well, transmit hydraulic power to the drill bit, install a shutter, abandon the well or prepare the well for abandonment, and otherwise treat the well or formation.

[0002] Well fluids or slurries may include a base fluid, which is commonly water, diesel or mineral oil, or a synthetic compound. Thickeners (most often barium sulphate or barite is used) can be added to increase density, and clays such as bentonite can be added to help remove cuts from the well and to form a plaster on the walls of the hole.

[0003] Well fluids also contribute to the stability of the wellbore, and control the flow of gas, oil or water through the pores of the formation, in order to prevent, for example, the flow, or, in undesirable cases, the eruption formation fluids or the collapse of pressurized land 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 can require a fluid with a density as high as about 10 pounds per gallon (ppg) and in some cases can be as high as 21 or 22 ppg.

[0004] Oil-based slurries (OBMs) have been used, because of their flexibility in meeting the desired reduction of density, inhibition, friction and rheological properties in well fluids. The drilling industry has been using water-based muds (WBMs) because they are cheap. Used mud and cuts from wells drilled with WBMs can easily be cleared off site in most land-based regions. WBMs and cuts can also be discharged from platforms in many US seawaters, as long as they meet current guidelines for effluent limitations, discharge regulations, and other concession limits.

[0005] A specific category of well or completion fluids includes annular space fluids or plug fluids that are pumped into annular openings in a well, such as, for example, (1) between a well wall and one or more pipe casing columns extending into a well, or (2) between adjacent, concentric columns of pipe extending into a well, or (3) in one or both of an annular space A or B in a well, comprising at least one annular space A and B with one or more columns of internal piping extending into said well, which can be extended in parallel, or nominally in parallel, with each other, and they may or may not be concentric, or nominally concentric, with the outer casing string, or (4) in one or more of an annular space A, B or C in a well, comprising at least one annular space A, B and C with one or more columns of inner piping extending into a m said well, which may be extended in parallel, or nominally in parallel, with each other, and may or may not be concentric, or nominally concentric, with the outer casing string. Alternatively still, said one or more pipe columns may simply pass through a conduit or other external pipe(s) to connect one or more well holes to another wellbore, or lead from one or more well holes. well to a collection or centralized processing center; and said annular space fluid may have been conducted into said conduit or tube(s), but external to said one or more tube columns therein.

[0006] Such plug fluids primarily serve to protect the coating, but also serve to provide hydrostatic pressure in order to equalize pressure with respect to the formation, to reduce pressures on plugs or sealing elements; or to limit the differential pressure acting on the wellbore, casing and production piping to prevent the well from collapsing, and/or to help control a well in the event of a leak in the production piping, or when the plug is no longer provide a seal or has not settled. While plug fluids can be formulated with sufficient density to perform such functions, conventionally, solid thickeners, which are often used in other well fluids, are avoided in plug fluids, due to solid deposition concerns, particularly as fluids from obturator often remain in the annular space for long periods of time without circulation. Furthermore, in addition to serving the aforementioned conventional functions for obturator elements, which are activated by the obturator or annular fluid, the fluid can also be formulated with such additional consideration in mind.

[0007] Another category of well or completion fluids includes open well fluids for uncoated parts of the well. Fluids are pumped into a vertical section or at an elevated angle of a well, where the injection or oriented production formation often remains exposed during production or injection, and/or may include any of the following: expandable plugs , outer casing shutters, perforated linings, sand control screens or sand screens, base tube and/or selected inflow control devices which may or may not include indicators, control lines and even submersible pumps. Often, open well fluid is pre-filled into the open well and works to facilitate installation of any of the above. In the example of an expandable plug/polymer(s), the open well fluid can provide functionality for the plug/polymer to expand, thus providing a barrier to control pressure, fluid circulation and increase installation integrity bottom.

[0008] Accordingly, there is a continuing need for improvements in well fluids to have sufficient density and to meet other considerations that may be particularly desirable for use with plug elements and/or expandable polymers used in wellbore and wells open.

SUMMARY

[0009] In one aspect, embodiments disclosed herein refer to a method for completing a well that includes introducing oil-containing well fluid into a well having a water-based plaster on its walls; contacting oil-containing well fluid with an oil-swellable element in the well; and allowing expansion of the expandable element into oil, where the oil-containing well fluid is substantially free of disassociated surfactants, emulsifiers, wetting agents or dispersants and may include an oleaginous fluid and a thickener.

[00010] In another aspect, embodiments disclosed herein refer to a method for activating an oil expandable plug system that includes introducing into a well, having a water-based plaster on its walls, a well fluid containing oil; contacting the oil-containing well fluid with an oil-swellable element in the well; and allowing expansion of the expandable element into oil, wherein the oil-containing well fluid includes an oil-containing continuous phase, wherein the oil-containing continuous phase forms substantially the entire fluid phase of the oil-containing well fluid; an alkyl diamide and a coated organophilic thickener, having a d90 particle size of less than about 20 microns.

[00011] In yet another aspect, embodiments disclosed herein refer to a well fluid that includes a continuous oil phase, where the continuous oil phase forms substantially the entire fluid phase of the well fluid, an alkyl diamide and a coated organophilic thickener, having a d90 particle size of less than about 20 microns, in which the well fluid is substantially free of any disassociated surfactants, dispersants or emulsifiers.

[00012] This Summary is provided to present a selection of concepts that are described further below in the detailed description. This Summary is not intended to identify the solution or essential features of the claimed object, nor is it intended to be used as an aid in limiting the scope of the claimed object. Other aspects and advantages of the invention will be apparent from the following description and appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[00013] Figure 1 shows an isometric view of an example system, in which embodiments of a sealing element can be implemented.

[00014] Figure 2 is a bar graph demonstrating the increase in total volume of an expandable plug in oil when soaked in various expandable fluid formulations.

[00015] Figure 3 is a photo demonstrating the compatibility of two swellable fluid formulations with a water-based plaster.

[00016] Figure 4 is a bar graph demonstrating the expansion of an expandable plug in oil when soaked in a fluid sample compared to diesel.

DETAILED DESCRIPTION

[00017] Embodiments disclosed in this document refer to well fluids (and methods for using such well fluids) for various completion operations. Particularly, embodiments of the present disclosure relate to well fluids used to activate oil-swellable polymer compositions from an expandable element to a well drilled with a water-based drilling fluid. The oil expandable elements (and therefore well fluids of the present disclosure) can be used in oil expandable plug system applications such as, but not limited to, filling wells, plugging or abandoning wells, isolating well areas , compartmentalize reservoir or segment well.

[00018] The well fluids of the present disclosure may therefore have various components including an oil-containing base fluid such that there is a sufficient amount of the fluid that is free to spread into and expand the polymer, and a thickener to increase the weight of the oleaginous fluid so that greater density can be achieved. The well fluids of the present disclosure can also be used to activate an expandable polymer composition having been placed in the borehole as a plug element, fill with gravel or other applications disclosed therein. The expandable composition may be oil expandable material, which expands by diffusing hydrocarbons into the oil expandable material.

[00019] In some embodiments, a well may be drilled using a water-based drilling fluid, where the water-based drilling fluid filters into the formation to form a water-based grout. As used in that document, a water-based plaster is a plaster, which is moistened by water and can be formed by any fluid containing water, such as having water or an aqueous fluid, such as most fluidic part of the fluid and/or any emulsion that produces a plaster moistened with water after filtration within the formation. In a particular embodiment, the water-based drilling fluid may be displaced with an oil-containing well fluid of the present disclosure, which is allowed to diffuse into oil-swellable materials placed at the bottom of the well, such as an expandable plug in oil, for example, causing oil-swellable materials to "activate" or expand.

[00020] In another embodiment, the expandable oil shutter can be incorporated into a screen unit shutter for an open well completion before hydrocarbon production, from a well, in order to use the expandable shutter for achieve zonal isolation and block the potential for incursion of unwanted fluids. Such techniques are disclosed in greater detail in U.S. Patent Publication No. 2007/0151724, which is incorporated herein by reference in its entirety.

[00021] As mentioned above, the well fluid used to activate or expand the expandable element in oil may be an oil-containing fluid. In some embodiments, the fluid phase of the oil-containing well fluid is formed solely or substantially all of an oleaginous liquid substantially free of an aqueous component and substantially free of emulsifiers or the like. In another embodiment, the fluid phase of the well fluid is formed of an oleaginous liquid, substantially free of an aqueous component and substantially free of emulsifiers, but may contain a certain volume of a non-aqueous, non-oily fluid. In yet another embodiment, the oil-containing well fluid can be a direct emulsion, where an oleaginous fluid is a discontinuous phase within a continuous aqueous or non-oily phase, formulated to be substantially free of emulsifiers or the like.

EXPANDABLE ELEMENTS

[00022] As mentioned above, well fluid is used to activate an expandable shutter system or other expandable elements. Expandable plug systems include an expandable composition, which can be used to fill a gap in the well. The expandable shutter system may consist of the expandable composition separately, but in some embodiments the expandable shutter system includes the expandable composition used as a tool component in completion operations, where a shutter element is placed in a range of well production to provide annular isolation between an upper and lower section of the well. Often, the expandable composition is attached to a base tube, liner or even liner. The composition expansion can be started at any time, but in some embodiments, the composition expands, at least after the equipment is installed in the well.

[00023] Furthermore, expandable compositions are those, which expand or swell, when exposed to a specific substance or substances, such as water or hydrocarbons, to a size that is greater than the size of the previously expanded element. The base fluid of the well fluid, used in conjunction with the expandable compositions, is absorbed into the expandable plug through diffusion. Through the random thermal movement of molecules in the liquid, the fluid diffuses into the obturator. When the plug is wrapped around the outer circumference of a tube, the result of expansion is an increase in the fabricated outer diameter of the expandable plug. Fluid may continue to spread into the plug, causing the plug element to expand so that it reaches the inside diameter of the casing or open well bore, and continues to expand until the internal stresses inside of the shutter material, reach equilibrium. That is, the expansion pressure increases, until diffusion can no longer occur. Particularly, the expandable element can expand, at least sufficiently, such that the expandable element creates a seal in the annular space, such as a differentially sealing annular barrier, which is created between the upper and lower sections of the well. Optionally, the expandable plug can be used to create a barrier between designated sections of an open pit to allow selective isolation during completion or after completion. In embodiments, the thickness of the expandable element may swell at least 5%, at least 10%, at least 15%, at least 20%, at least 25% or at least 50%. Often, the expandable element can be forced to expand in only one radial direction, but in other embodiments it can expand in both the radial and axial directions.

[00024] Other embodiments may include an expandable element in a mechanical plug, which is a tool that can be located and placed in a well, to isolate a well bottom from a well top.

[00025] According to a method of use, an expandable shutter or other element, such as a mechanical plug, can be placed in a part of a well having been drilled, in embodiments, with a water-based fluid, of such that a water-based plaster remains on the walls of the well. It is clear that more than one expandable element can be placed in the well. A combination of expandable plugs and/or mechanical plugs can also be placed in parts of a well. An expansion fluid is then introduced, either directly, by itself, into the annular space, or introduced into the annular space through the tube column or casing. Expansion fluid may contact the expandable element of the plug or mechanical plug, causing the expandable element to begin to swell. The expansion fluid can remain in contact with the expandable element long enough for the expandable element to expand and swell to a size sufficient to seal the annular space.

[00026] Expandable compositions used in the methods of the present disclosure can be formed from various materials that expand or swell sufficiently in the presence of hydrocarbons. Illustrative expandable materials can 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, butadiene acrylate rubber, acrylate-vinylacetate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-polyacrylonitrile graft copolymers, styrene, styrene-butadiene rubber, polyethylene, polypropylene, ethylene-propylene comonomer rubber, ethylene propylene diene monomer rubber, ethylene vinyl acetate rubber, acrylonitrile-butadiene hydrogenated rubber, acrylonitrile rubber butadiene, isoprene rubber, neoprene rubbers, sulfonated polyethylenes, ethylene acrylate, epichlorohydrin ethylene oxide copolymers, ethylene-propylene rubbers, ethylene-propylene-diene terpolymer rubbers, ethylene vinyl acetate copolymer, acrylamides, acrylonitrile butadiene rubbers, polyesters, polyvinylchlorides, hydrogenated acrylonitrile butadiene rubbers, fluor rubber, fluorosilicone rubbers, silicone rubbers, poly 2,2,1-bicycloheptenes (polynorbornene), alkylstyrene, or chloroprene rubber. While the specific chemistry is not limited to the present methods, oil-swellable polymer compositions can also include oil-swellable elastomers.

WELL FLUIDS CONTAINING OIL

[00027] As mentioned above, to activate the expandable element in oil, that is, cause the expandable element to swell, the well fluid may contain oil. The oil-containing well fluid may contain a sufficient amount of an oil-swellable fluid to activate the expandable composition by diffusing the oily fluid into the oil-swellable material. The amount of oil, which will cause sufficient expansion of the expandable element, to abut and seal against the corresponding component of the well, may vary, for example, based on the size of the plug, the extent of expansion/swelling of the required element etc. .

[00028] In some embodiments, the oil-containing fluids of the present disclosure may include an oleaginous fluid as the continuous phase of the fluid, while other embodiments may use a direct emulsion, where the oleaginous fluid is a discontinuous phase within a continuous aqueous or non-oil phase.

[00029] Oil fluids may be a liquid, such as a natural or synthetic oil and in some embodiments, the oil fluid may be selected from the group, including diesel oil, mineral oil; synthetic oil, such as hydrogenated and non-hydrogenated olefins including polyalpha olefins, linear and branched olefins and the like, polydiorganosiloxanes, siloxanes or organosiloxanes, fatty acid esters, alkyl branched and cyclic fatty acid ethers, specifically straight chain, mixtures and compounds thereof the like known to a person skilled in the art; and its mixtures. In a particular embodiment, fluids can be formulated using diesel oil or a synthetic oil as the external continuous phase.

[00030] In one embodiment, oleaginous fluid may be present without any aqueous or non-oily phase, or may be substantially free of an aqueous and/or non-oleaginous fluid (such as those discussed below). As used herein, substantially free of an aqueous or non-oleaginous fluid can be interpreted to mean that the fluid contains less than 20% by vol. of an aqueous or non-oleaginous fluid, or less than 10% by vol. or 5% by vol. in other embodiments. However, in other embodiments, the fluid may contain a non-aqueous, non-oleaginous fluid having partial miscibility (i.e., some, but not full solubility, such as at least 10-25% or greater miscibility) with the fluid. oil in an amount that is greater than 20% by vol. In addition, mutual solvents, i.e. a fluid, having solubility in aqueous and oleaginous fluids, may be present in the oleaginous fluid, including in oleaginous fluids that are at least substantially free of an aqueous or non-oleaginous fluid. Illustrative examples of 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, butyl carbitol, dipropylene glycol methyl ether, various esters, such as lactate of ethyl, propylene carbonate, butylene carbonate etc. and pyrolidones.

[00031] When formulated without, or substantially free of, an aqueous or non-oily phase (or even if it contains an aqueous, non-oily fluid, with partial miscibility with an oleaginous fluid), the fluid may also be free, or substantially free, of any disassociated surfactants, emulsifiers, wetting or dispersing agents, that is, any amphiphilic compounds that have hydrophilic and hydrophobic groups within the molecule. As used herein, "disassociated" refers to molecules, which are not chemically linked, or otherwise chemically or physically associated with other species (such as a solid thickener). Under such a definition, a dispersant or wetting agent that is provided as a coating on the thickener would be considered to be associated, disassociated. As used herein, substantially free of a disassociated surfactant, emulsifier, wetting agent or dispersant means less than an amount that would generate an inverse emulsion for any amount of an aqueous or non-oily fluid present in the fluid. Such amounts can be, for example, less than 5 pounds per gallon (ppb) or less than 4 ppb, 3 ppb, 2 ppb or 1 ppb, in other embodiments. Thus, a wetting or dispersing agent can be provided to coat a solid thickener, but the amount added would not be enough, so that an inverse emulsion could be formed with any excess wetting or dispersing agent. Such excess may be less than 5 ppb, 4 ppb, 3 ppb, 2 ppb or 1 ppb, in various embodiments.

[00032] In some embodiments, the well fluid may be a direct emulsion having an aqueous or non-oily fluid as a continuous phase, where the oleaginous fluid is provided as a discontinuous phase, provided therein. Direct emulsions can be formulated to be substantially free of an emulsifier, surfactant, dispersant or wetting agent as defined above. Non-oleaginous fluids, which can be used in the embodiments disclosed herein, can be a liquid, such as an aqueous fluid. In embodiments, the non-oleaginous liquid may be selected from the group including fresh water, sea water, a brine containing dissolved organic or inorganic salts, liquids containing water-miscible organic compounds, and combinations thereof. For example, the aqueous fluid can be formulated with mixtures of desired salts in fresh water. Such salts can include, but are not limited to, alkali metal chlorides, hydroxides or carboxylates, for example. In various embodiments of the well fluid disclosed therein, the brine can include sea water, aqueous solutions, where the salt concentration is less than the sea water concentration, or aqueous solutions, where the salt concentration is higher than that of sea water. Salts, which can 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, formats, nitrates , oxides, phosphates, sulfates, silicates and fluorides. Salts, which can be incorporated into a particular brine, include any one or more of those present in natural sea water or any other dissolved organic or inorganic salts. Furthermore, brines, which can be used in the well fluids disclosed in that document, can be natural or synthetic, with synthetic brines tending to be much simpler in their constitution. In one embodiment, the density of the well fluid can also be controlled by increasing the salt concentration in the brine (to saturation). In a particular embodiment, a brine may include halide or carboxylate salts of mono- or divalent metal cations, such as cesium, potassium, calcium, zinc and/or sodium. Specific examples of such salts include, but are not limited to, NaCl, CaCl2, NaBr, CaBr2, ZnBr2, NaHCO2, KHCO2, KCl, NH4Cl,CsHCO2, MgCl2, MgBr2, KH3C2O2, KBr, NaH3C2O2 and combinations thereof.

[00033] In embodiments using direct emulsions, the well fluid may contain an oleaginous fluid (to expand the expandable element into oil) in an amount, which has a lower limit of any one of 10% by vol., 20% by vol., 30% by vol., 40% by vol. or 50% by vol., and an upper limit of any one of 40% by vol., 50% by vol., 60% by vol., 70% by vol. or 80% by vol., with any lower limit being combinable with any upper limit. In specific embodiments, the oleaginous fluid can form 20-70% by vol. of well fluid, 30-60% by vol. or 40-50% by vol., with the balance of the fluid part being the non-oleaginous fluid.

SOLID FILTERS

[00034] The density of the fluid can be increased, through the incorporation of a solid thickener. Solid fillers used in some of the embodiments disclosed therein can include a variety of inorganic compounds well known to those skilled in the art. In some embodiments, the thickener may be selected from one or more of the materials including, for example, barium sulfate (barite), calcium carbonate (calcite or aragonite), dolomite, ilmenite, hematite or other iron ores, olivine , siderite, manganese oxide and strontium sulfate. In a particular embodiment, calcium carbonate or other acid-soluble solid thickener may be used.

[00035] A person having common knowledge of the art will recognize that the selection of a particular material may depend to a large extent on the density of the material, because generally the lowest viscosity of well fluid, at any particular density, is obtained. using the highest density particles. In some embodiments, the thickener can be formed from particles, which 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 still other embodiments. Higher density thickeners can also be used with a specific gravity of about 4.2, 4.4 or even as high as 5.2. For example, a thickener formed from particles having a specific gravity of at least 2.68 can allow well fluids to be formulated to meet most density requirements while still having a low enough particle volume fraction for the fluid is pumped. However, other considerations can influence product choice, such as cost, local availability, the energy required for grinding, and whether solid waste or plaster can be easily removed from the well. In specific embodiments, the well fluid can be formulated with calcium carbonate or other acid-soluble material.

[00036] Solid thickeners can have any particle size (and particle size distribution), but some embodiments may include thickeners having a smaller particle size range than API grade thickeners, which may generally be referred to as thickeners, which may generally be referred to as thickeners. micronized thickeners. Such thickeners can generally be in the order of microns (or smaller), including submicron particles in the order of nano-size.

[00037] In some embodiments, the average particle size (d50) of the thickeners can range from a lower limit of more than 5 nm, 10 nm, 30 nm, 50 nm, 100 nm, 200 nm, 500 nm, 700 nm, 0.5 microns, 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 particles can range from any lower limit to any upper limit. In other embodiments, the d90 (size, where 90% of the particles are smaller) of the thickeners can range from a lower limit of more than 20 nm, 50 nm, 100 nm, 200 nm, 500 nm, 700 nm, 1 micron, 1.2 micron, 1.5 micron, 2 micron, 3 micron, 5 micron, 10 micron or 15 micron to an upper limit of less than 30 micron, 25 micron, 20 micron, 15 micron, 10 micron, 8 micron , 5 microns, 2.5 microns, 1.5 microns, 1 micron, 700 nm, 500 nm, where particles can range from any lower limit to any upper limit. The particle ranges described above can be achieved by grinding the materials to the desired particle size or by precipitating the material through a 'bottom up' type clustering approach. Precipitation of such materials is described in U.S. Patent Application Publication No. 2010/009874, which is assigned to the present assignee and incorporated herein by reference. A person of ordinary skill in the art will recognize that, depending on the sizing technique, the thickener may have a particle size distribution other than a monomodal distribution. That is, the thickener may have a particle size distribution which, in various embodiments, may be monomodal, which may or may not be Gaussian, bimodal, or polymodal.

[00038] In one embodiment, a thickener is sized so that: particles having a diameter less than 1 micron are from 0 to 15 percent by volume; particles having a diameter between 1 micron and 4 microns are from 15 to 40 percent by volume, particles having a diameter between 4 microns and 8 microns are from 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 from 3 to 7 percent by volume; particles having a diameter between 16 microns and 20 microns are from 0 to 10 percent by volume; particles having a diameter greater than 20 microns are from 0 to 5 percent by volume. In another embodiment, the thickener is sized so that the cumulative volume distribution is: less than 10 percent or the particles are less than 1 micron; less than 25 percent is in the 1 micron to 3 micron range; less than 50 percent is in the 2 micron to 6 micron range; less than 75 percent is in the 6-micron to 10-micron range; and less than 90 percent is in the range of 10 microns to 24 microns.

[00039] The use of fillers, having such size distributions, has been described in U.S. Patent Application Publication Numbers 2005/0277553 and 2010/0009874, which are assigned to the assignee of the current Application, and incorporated herein by reference. Particles having such size distributions can be obtained by any means known in the art.

[00040] In some embodiments, thickeners include dispersed solid colloidal particles, with an average particle diameter by weight (d50) of less than 10 microns, which are coated with an organophilic polymeric dispersing agent or deflocculating agent. In other embodiments, the thickeners include solid dispersed colloidal particles with a weight average particle diameter (d50) of less than 8 microns, which are coated with a polymeric dispersing agent or deflocculating agent; less than 6 microns in other embodiments; less than 4 microns in other embodiments; and less than 2 microns in still other embodiments. The fine particle size will generate suspensions or slimes, which will show a reduced tendency to sediment or decay, and the polymeric dispersing agent on the particle surface can control interactions between particles and thus produce lower rheological profiles. It is this combination of fine particle size and control of colloidal interactions that reconciles the two goals of lower viscosity and minimal decay.

[00041] In some embodiments, the thickeners may not be coated. In other embodiments, the thickeners can 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 sulfonic acids, alkane sulfonic acids, linear alpha-olefin sulfonic acid and their alkaline earth metal salts. Other examples of 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 illustrated polymeric dispersant can have an average molecular weight of 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 will recognize that other acrylates or other unsaturated carboxylic acid monomers (or esters thereof) can be used to achieve substantially the same results as disclosed herein.

[00042] In embodiments, coated thickeners can be formed by a dry coating process or by a wet coating process. Suitable fillers for use in other embodiments disclosed herein may include those disclosed in US Patent Application Publication Numbers 2004/0127366, 2005/0101493, 2006/0188651, 2008/0064613 and US Patent Numbers 6,586,372 and 7,176 .165, each of which is incorporated herein by reference.

[00043] Particle materials as described in this document (i.e., coated and/or uncoated thickeners) can be added to a well fluid as a thickener in dry or concentrated form, as sludge in an aqueous medium or as an organic liquid. As is known, an organic liquid can have the environmental characteristics required for additives to oil-containing well fluids. With this in mind, oleaginous fluid can 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-olefinic oils, ester oils, mixtures of these fluids, as well as other similar fluids known to a person skilled in the art of drilling, or other well fluid formulation. In one embodiment, the desired particle size distribution is achieved by wet grinding the coarser materials into the desired conductive fluid.

[00044] Such solid thickeners can be particularly useful in well fluids formulated with an entirely oleaginous fluid phase. In a particular embodiment, a coated organophilic thickener, having a particle size within any of the ranges described, can be used in a fluid free of, or substantially free of, an aqueous phase contained therein. Solid thickeners can also be used in the direct emulsions of the present disclosure to provide additional density, beyond that provided by the aqueous phase, as needed.

[00045] In one embodiment, the well fluid may have a density greater than about 8.0 pounds per gallon (ppg), or at least 10, 12, or 14 ppg in another embodiment. In yet another embodiment, the well fluid density, in some embodiments, ranges from about 6 to about 18 ppg, where the thickener is added in an amount to increase the base fluid density by at least 1 ppg or at least 2, 4, or 6 ppg in other forms of realization.

WELL FLUID ADDITIVES

[00046] Other additives, which may be included in the well fluids disclosed in this document, include, for example, thickeners, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, buffer solutions of pH, mutual solvents, thinners, diluting agents and cleaning agents. The addition of such agents should be known to a person having common knowledge of the well slurry and fluid formulation technique.

[00047] In some embodiments, additives can be included in the composition to modify rheological properties such as viscosity and flow. For example, organic thixotropes suitable for adding to the well fluids of the present disclosure include alkyl diamides, such as those having a general formula: R1-HN-CO-(CH2)n-CO-NH-R2, where n is a integer from 1 to 20, from 1 to 4, or from 1 to 2, and R1 is an alkyl group having 1 to 20 carbons, 4 to 12 carbons, or 5 to 8 carbons, and R2 is hydrogen or a alkyl group having from 1 to 20 carbons, is either hydrogen or an alkyl group having from 1 to 4 carbons, where R1 and R2 may or may not be identical. Such alkyl diamides can be obtained, for example, from M-I L.L.C. (Houston, TX) under the trade name VERSAPAC™. Such alkyl diamide viscosifiers may be particularly suitable for use in a well fluid containing oil substantially free of an aqueous or non-oily fluid, but may also be included in direct emulsions.

[00048] In other embodiments, organophilic clays, such as amine treated clays, may be useful as viscosifiers in the fluid composition of the present disclosure. VG-69TM and VG-PLUSTTM are organoclay materials, marketed by M-I L.L.C., Houston, Texas, which can be used in the embodiments disclosed herein. Such organophilic clays, as well as water-based clays, can be particularly useful to aid in the formation and stabilization of a direct emulsion. Other viscosifiers that can be used include partially hydrolyzed polyacrylamide (PHPA), biopolymers (such as guar gum, starch, xanthan gum and the like), bentonite, attapulgite, sepiolite, polyamide resins, polyanionic carboxymethylcellulose (PAC or CMC), polyacrylates , lignosulfonates, as well as other water-soluble polymers. When formulating a direct emulsion without an emulsifier, surfactant, etc., the viscosifier can be incorporated to increase the viscosity and thus the miscibility of the two phases, such that a direct emulsion (oil-in-water) is formed from of mixing in a high shear mixer, as this 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.

[00049] In other embodiments, fumed silicas and/or precipitated silica can be used as a viscosifying agent. In still other embodiments, precipitated silicas can advantageously be used to provide thickener and viscosifier to the oleaginous base fluid. When used to provide binder and viscosifier, the precipitated silicas can be used in addition to, or in place of, the thickeners described above. Alternatively, the relative amounts of thickener and precipitated silica in the well fluid formulation can be adjusted so that the well fluid has desired density and flow properties.

[00050] Precipitated silicas have a porous structure and can be prepared from the reaction of an alkali silicate solution with a mineral acid. Alkali silicates can be selected, for example, from one or more of sodium silicate, potassium silicate, lithium silicate and quaternary ammonium silicates. Precipitated silicas can be produced by destabilizing and precipitating silica from soluble silicates by adding a mineral acid and/or acid gases. Reagents, therefore, include an alkali metal silicate and a mineral acid, such as sulfuric acid, or an acidifying agent, such as carbon dioxide. Precipitation can be carried out under alkaline conditions, for example, by adding a mineral acid and a water silicate solution with constant stirring. Choice of agitation, duration of precipitation, rate of addition of reagents, temperature, concentration and pH can vary the properties of the resulting silica particles.

[00051] Precipitated silicas, useful in embodiments herein, may include solid materials of finely divided particles, such as powders, silts or sands, as well as reinforced flakes or agglomerates of smaller particles of siliceous material. In some embodiments, the precipitated silica (or its agglomerates) can have an average particle size (D50) of less than 50 microns; less than 20 microns in other embodiments; and in the range of about 1 micron to about 10 microns, such as about 4 to about 6 microns, in still other embodiments. In some embodiments, precipitated silicas, having a larger initial average particle size, may be used, where shear or other conditions may result in crushing of the particles, such as disintegration of the agglomerates, resulting in a silica particle having an average size useful particle.

[00052] Precipitated silicas may contain varying amounts of residual alkali metal salts, which result from the association of the corresponding silicate counterion with available anions supplied by the acid source. Residual salts can 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 Ca, Mg and Ba, or organic cations such as ammonium, ammonium tetraalkyl, imidazolium, alkyl imidazolium and the like; and X is an anion selected from halides, such as F, Cl, Br, I, and/or sulfates, sulfonates, phosphonates, perchlorates, borates and nitrates. In one embodiment, the residual salts can be selected from one or more of Na2SO4 and NaCl, and the precipitated silica can have a residual salt content (Na2SO4 equivalent) of less than about 2% by weight. Although the pH of the resulting precipitated silicas can vary, embodiments of the silicas useful in the embodiments disclosed therein can have a pH in the range of about 6.5 to about 9, such as in the range of about 6.8 to about 8.

[00053] In other embodiments, surface-modified precipitated silicas can be used. Surface-modified precipitated silica may include a lipophilic coating, for example. Surface modification can be added to silica after precipitation. Alternatively, silica can be precipitated in the presence of one or more of the surface modifying agents described above.

[00054] It was found that surface-modified precipitated silicas, according to embodiments in this document, can provide, advantageously, densification and viscosification of the oleaginous base fluid. Precipitated silicas, in accordance with embodiments herein, are useful for providing well fluids with high thermal stability at extreme temperatures, in addition to exhibiting a substantially constant rheological profile over time.

[00055] In some embodiments, the surface of silica particles can be chemically modified by a number of synthetic techniques. The surface functionality of the particles can be adapted to improve solubility, dispersibility, or introduce reactive functional groups. This can be achieved by reacting the precipitated silica particles with organosilanes or siloxanes, in which reactive silane groups, present in the molecule, can become covalently bonded to the silica structure that makes up the particles. Non-limiting examples of compounds, which can be used to surface functionalize the precipitated silica particles, include aminoalkylsilanes, such as aminopropyltriethoxysilane, aminomethyltriethoxysilane, trimethoxy[3-(phenylamino)propyl]silane and trimethyl[3-(triethoxysilyl)tetrasulfide, bis( 3-(triethoxysilylpropyl)disulfide, vinyltrimethoxy silane, vinyltriethoxy silane 3-mercaptopropyltrimethoxy silane, 3-mercaptopropyltriethoxysilane, 3-mercaptopropyltrimethoxy silane, 3-aminopropyltriethoxysilane and 3-aminopropyltrimethoxysilane; and alkoxysilanes.

[00056] In another embodiment, organosilicon materials, which contain final reactive groups, can be covalently bonded to the surface of the silica particles. Reactive polysiloxanes can include, for example, diethyl dichlorosilane, diethoxy ethyl phenyl silane, dichlorosilane phenyl methyl, 3,3,3-trifluoropropylmethyldichlorosilane, trimethylbutoxy silane, sim-diphenyltetramethyl disiloxane, octamethyl trisiloxane, octamethylcyclotetrasiloxane, phenyl methyldichlorosilane, hexamethyldichlorosilane trimethyl methoxysilane, trimethyl ethoxysilane, methyl trichlorosilane, methyltriethoxysilane, methyl trimethoxysilane, hexamethylcyclotrisiloxane, hexamethyldisiloxane, hexaethyldisiloxane, dimethyl dichlorosilane, dimethoxy dimethyl silane, dimethyl dietoxysilane, polydimethylsiloxanes comprising 3 to 200 dimethylsiloxysilane or polydimethyloxysilane polymer units end-blocked hydroxydimethylsiloxy (silicone oils) having an apparent viscosity within the range of 1 to 1000 mPascals at 25°C, vinyl silane, gam-methacryloxypropyl trimethoxy silane, polysiloxanes, e.g., polysiloxane beads, and mixtures of such organosilicon materials.

[00057] Surface-modified silicas can have a BET-5 nitrogen surface area of less than about 200 m2/g. In some embodiments, the surface area of the surface-modified precipitated silica can be less than about 150 m 2 /g. In other embodiments, the surface area can be in the range of about 20 m2/g to about 70 m2/g.

[00058] In one or more embodiments, the precipitated silica has a BET-5 nitrogen surface area of 20 m2/g to 70 m2/g, as calculated by the surface adsorption of N2 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.

[00059] In some embodiments, precipitated silicas useful in embodiments of this document may include those as disclosed in US Patent Applications No. 2010/0292386, 2008/0067468, 0131107/2005, 2005/0176852, 2006/0225615, 0228632/2006 and 2006/0281009, each of which is incorporated herein by reference.

[00060] Another additive for oil well fluids, which optionally may be included in the oil well fluids disclosed in this document, is a fluid loss control agent. Fluid loss control agents can act to prevent fluid loss to the surrounding formation, reducing the permeability of the solidified fluid barrier in a wellbore. Suitable fluid loss control agents may include those such as modified lignites, bituminous compounds, gilsonite, organophilic humates prepared by the reaction of humic acid with polyalkylene amides or polyamines, and other fluid loss additives such as an acrylate copolymer / methylstyrene. Such fluid loss control agents can be employed in an amount, which is at least about 0.5 to about 15 pounds per barrel. The fluid loss reducing agent must be tolerant to high temperatures and inert or biodegradable. RD ECOTROLTM, an oil-soluble polymeric fluid control agent that can be used in well fluid, is commercially available from M-I L.C., Houston, Texas.

[00061] To illustrate an embodiment of a well completion with an expandable plug system, an annular seal member (plug) is installed in a well. Figure 1 depicts an embodiment of an annular sealing member 100 including portions made of the expandable composition. Sealing member 100 may include a support member 110 having an outer expandable member 120 disposed about its outer diameter. Support member 110 may also have an internal expandable element 130 disposed around its internal diameter. Support member 110 may have openings 115 formed therein allowing outer expandable element 120 to mate with inner expandable element 130.

[00062] The external expandable element 120 can be arranged on the support member 110 and can be configured to abut a wall of a wellbore or other structure disposed on the external expandable element 120. The internal expandable element 130 can be configured to expand within support member 110 around a tube or other object disposed at least partially within support member 110. Expandable elements 120 and 130 are unified, allowing sealing member 100 to withstand differential pressure. Expandable elements 120 and 130 can be made from the expandable composition.

[00063] After the seal member 100 is placed in the well around a pipe or drill string (along with any other completion equipment), an oil-containing well fluid (such as any of those described above) is formed, by mixing a basic fluid with a thickener (such as a micronized thickener) together with additives that provide the proper rheological properties needed for the well. The well fluid is then pumped down the well (either directly into the annular space or through a tubular column) and allowed to come into contact with the expandable elements placed in the well (either previously or later installed therein). In a certain embodiment, the oil-containing well fluid can displace a water-based well fluid used to drill at least a portion of the well. Such displacement can occur with or without the use of spacer fluids, as known in the art, but without any washing fluids or deaggregators. Alternatively, in other embodiments, the water-based drilling fluid may first be displaced with a conditioned mud, a solids-free mud, or a brine, prior to introducing the oil-containing fluid of the present disclosure. Thus, the oil-containing fluid can be pumped into a well having a water-based plaster on its walls, without the water-based plaster being removed and the well being otherwise cleaned. The oil-containing fluid can spread within the oil-swellable elements 120 and 130, which can expand until it reaches the balance of internal stresses within the polymer. That is, the expansion pressure increases, until diffusion can no longer occur. At this point, an annular differential seal barrier is created between the upper and lower sections of the well. In some embodiments, the oil-containing fluid of the present disclosure is introduced into an unlined portion of the well below the plug element. Other embodiments may involve introducing the fluid containing oil above the closure element, or above and below the closure element.

[00064] As used herein, a "well" includes at least one well hole drilled in an underground formation, which may be a reservoir or adjacent to a reservoir. A wellbore can have both vertical and horizontal parts, and it can be straight, curved, or branched. The wellbore can be an open hole or a lined hole. In an open wellbore, a pipe string, which allows fluids to be inserted into, or removed from, the wellbore, is installed in the wellbore. In a casing hole, a casing is installed inside the wellbore, and a column of pipe can be installed in the casing. An annular space is the space between two concentric objects, such as between the wellbore and casing, or between casing and pipe, where fluid can flow.

[00065] Annular seal members suitable for use in other embodiments disclosed herein may include, but are not limited to, those disclosed in U.S. Patent Application Publications No. 2007/0151724, 2007/0205002, 2008/0308283 and US Patent No. 7,143,832 and 7,849,930, each of which is incorporated herein by reference in their entirety. Seal members can also be used in combination with other tools where isolation of wellbore segments is desired.

[00066] Although the illustrated embodiment is an example of many potential applications, it is provided for the purpose of explanation. Many other types of applications utilizing a variety of completion equipment, gravel filling techniques and wellbore guidelines can benefit from the expandable plug system described. In another embodiment of a well completion, the plug may be incorporated into a screen assembly plug for open hole completion, to use the expandable plug, to achieve zonal isolation and block potential incursion of unwanted fluids, as disclosed in U.S. Patent Application Publication No. 2007/0151724, incorporated herein by reference in its entirety.

EXAMPLES

[00067] As mentioned above, the oil-containing fluids of the present disclosure can be used to expand an oil-swellable plug composition used in a well having been drilled with a water-based drilling fluid, where there is residual fluid based on oil. water in the form of a water-based plaster 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 the entire fluid portion of the fluid, one or more solid particles including filling or thickening agents known in the art, fluid loss control and/or viscosifiers such as xanthan gum or other natural or synthetic polymers, as well as other additives known in the drilling fluid art.

EXAMPLE 1

[00068] To measure the effectiveness of oil-containing well fluids to activate an oil-swellable plug, four well fluid formulations were prepared. Mixed in various proportions, the samples included the following components: diesel, water, dry calcium chloride, lime; SAFE-CARBTM 2, a calcium carbonate thickener; RD ECOTROLTM, an oil-soluble acrylate/methylstyrene copolymer; lime; VG-PLUSTM, an organophilic clay viscosifier; VERSCOATTM, a modified amidoamine derived from fatty acid emulsifier and wetting agent; VERSAWETTM, an oxidized fatty acid surfactant; VERSAMULTM, a blend of fatty acids and wood resin emulsifier for oil-based slurries; ECF-2184, an alkoxylated fatty alcohol, terminated with a carboxylic acid emulsifier; VERSAPACM, an alkyl diamide; and EMI-2180, a micronized calcium carbonate thickener having a d90 of about 10 microns, a d50 of about 4 microns and a d10 of about 1.5 coated with an organophilic coating made of stearyl methacrylate, butylacrylate monomers and acrylic acid, all of which are supplied by MI LLC (Houston, Texas). The fluid formulations are as follows: Table 1 - Formulations for expandable plug fluids in oil

[00069] Diesel oil was used as a control in Sample 1. A conventional inverse system with a 60:40 oil/water ratio (OWR) was mixed for Sample 2, using VERSCOATTM, VERSAWETTM, in order to wet the system with oil and maintain an inverse emulsion with the brine phase, and SAFE-CARBTM 2 as the thickener. In addition, a high internal phase ratio (HIPR) emulsion was prepared for Sample 3 containing no solids and a special emulsifier, which maintains a water-in-oil system with very low OWR, impossible using conventional chemistry. Finally, Sample 4 is an integral oil system prepared with the organic alkyl diamide viscosifier to achieve suspension of the coated organophilic calcium carbonate thickener, which can lessen or eliminate the need for an emulsifier or wetting agent within the fluid.

[00070] Expansion tests were conducted, where parts of Samples 1-4, known as "saturation fluid" in Table 2, were loaded into pressurized cells with a specimen of an oil-swellable plug material and placed in a oven for static aging at 225°F (107°C) for 24 hours. After the static incubation time, cells were removed, air cooled and measured. Sample 1, the diesel oil control, was poured into a vial containing a specimen sample and aged for 24 hours at room temperature because it was not possible to test the fluid at elevated temperature due to safety considerations. The results are shown in Table 2 and Figure 1. Table 2. Calculated change in oil expandable plug specimen size after exposure to various oil-based fluids.

EXAMPLE 2

Tabela 4. Reologia para sistemas de variação da Amostra 4, 9,6lb/gal

[00071] To determine the increase in fluid properties of the integral oil fluid for plug expansion under high temperature conditions at the bottom of the well, two different variations of 9.6 lb/gal Sample 4 volumes were mixed, as shown in Table 3. Fluid was cut in the Silverson mixer controlling heat associated with a cooling bath, to keep the temperature below 150°F (66°C). Viscosity data for both formulations are shown in Table 4. In both samples from Sample 4, an increase in rheology was observed after static aging at 225°F (107°C) for 24 hours. Sample 4

Table 4. Rheology for Sample 4 Variation Systems, 9.6lb/gal

EXAMPLE 3

[00072] To demonstrate the compatibility of Sample 4 of the oil-containing plug expansion fluid with respect to a conventional inverse emulsion fluid, a plaster was generated using a water-based reservoir drilling fluid on a 220° aoxite disc °F (104oC). Drilling fluid was depleted from the cell and replaced by Sample 4-1 (Table 3), in contact with the water-based plaster. This procedure was repeated for a second cell, using a conventional inverse emulsion, ie, Sample 2. The cells were pressurized to 100 psi and heated to 150°F for 24 hours. Then the cells were removed and allowed to cool to room temperature.

[00073] The cells were disassembled and the plasters were removed and photographed. An emulsion was observed on the water-based plaster exposed to the inverse emulsion fluid (Panel B, Figure 3), which can be attributed to degradation of the plaster by emulsifiers used to stabilize the inverse emulsion. The plaster exposed to the integral oil system (and free of any emulsifiers and wetting agents) of Sample 4 (Panel A, Figure 3) showed no signs of emulsion formation.

EXAMPLE 4

[00074] An oil-containing well fluid formulated with a silica additive was tested for the ability to viscosify and activate an expandable element in oil. ECF-2723, an amorphous precipitated silica, having a d50 of about 5 microns, is available from MI SWACO (Houston, Texas). The fluid formulations are as follows: Table 5 - Formulations for oil expandable plug fluids

[00075] The rheology (measured at 120°F) of Sample 5 was tested for initial properties after mixing as well as after 18 hours of static aging at 180°F as shown in Table 6. Although a small drop in rheology was observed, as shown in Table 6, there was no sign of material deposition by weight after static aging. An approximate 2mm top oil separation was measured. Table 6. Rheology for Sample System 5, 9.6 lb/gal

[00076] To assess the potential of screen fouling of Sample 5 loaded with solids, 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 specimen. A failure of the test would be indications of plugging, through a change in velocity at which fluid passes through the specimen, being noticed, or plugging to stop fluid flow entirely. PST was performed using a 1 liter volume of fluid at 20 psi through a 6 gauge coated wire mesh. There were no signs of clogging as the fluid passed freely in 6.53 seconds. The coated wire mesh specimen was removed, gently rinsed in solvent to check for visible signs of solids trapped in the specimen. The specimen was clean, with no signs of trapped materials.

[00077] Sample 5 was also subjected to an expansion test, in which a sample of oil-swellable elastomeric material was placed in a cell containing a volume of Sample 5. The elastomeric specimen was statically aged in the fluid for 18 hours at 180°F and then measured using a digital caliper initially and after aging to compare the specimen for expansion performance. Recorded measurements include top width, bottom width, height and thickness as shown in Table 7 below. A comparison (an increase in expansion, as a linear measure) between a specimen soaked with Sample 5 and an elastomeric specimen soaked in diesel for 18 hours at room temperature (due to safety concerns) is shown in Figure 4 Table 7. Expansion Test Results

[00078] Embodiments of the present disclosure relate to a well fluid, which can be used in completing a well. For wells having been drilled with a water-based fluid, the present disclosure may advantageously allow the use of an oil expandable plug, which may have better sealing characteristics, than a water expandable plug. Furthermore, embodiments of the present disclosure may also allow the use of an oil-containing fluid, which can be thickened to the required density (for well control) without risk of particulate deposition. Furthermore, in an embodiment using an integral oil system or a direct emulsion as described herein, the elimination or reduced amount of emulsifier, surfactants or wetting agents may be desirable to minimize the interaction between the water-based plaster. and well fluid containing oil, thus simplifying the logistics of moving between fluids containing water and oil.

[00079] Although the invention has been described in relation to a limited number of embodiments, persons skilled in the art, taking advantage of this disclosure, will understand that other embodiments can be conceived which do not depart from the scope of the invention as disclosed herein. In this sense, the scope of the invention is to be limited only by the appended claims.

[00080] Although only a few example embodiments have been described in detail above, persons skilled in the art will readily appreciate that many modifications are possible in example embodiments, without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, clauses of the type 'means-plus-function' are intended to cover the structures described in this document as performing the disclosed function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents, where a nail employs a cylindrical surface to fasten pieces of wood together, whereas a screw employs a helical surface, in the environment of fastening pieces of wood, a nail and a screw can be equivalent structures. It is the plaintiff's express intention not to invoke 35 USC § 112, para. 6 for any limitations on any of the claims in this document, except those where the claim expressly uses the words 'means to' in conjunction with an associated function.

Claims (18)

1. Method for completing a well, characterized in that it comprises: introducing a well fluid containing oil into a well having a water-based plaster on its walls, the well fluid containing oil being free of surfactants, emulsifiers, wetting agents or disassociated dispersants, the well fluid comprising: an oleaginous fluid; and a thickener; and contacting the oil-containing well fluid with an oil-swellable element in the well; and allow expansion of the expandable element in oil. 2. Method according to claim 1, characterized in that it further comprises displacing the water-based well fluid with the oil-containing well fluid. 3. Method according to claim 1, characterized in that the oil expandable element is arranged on an outer circumference of a tubular component. 4. Method according to claim 1, characterized in that the well fluid containing oil is free from an aqueous fluid. 5. Method according to claim 1, characterized in that the oil-containing well fluid further comprises an alkyl diamide having the general formula: R1-HN - CO-(CH2)n-CO-NH-R2, where n is a integer from 1 to 20, R1 is an alkyl group having from 1 to 20 carbons and R2 is hydrogen or an alkyl group having from 1 to 20 carbons, where R1 and R2 may or may not be identical. 6. Method according to claim 1, characterized in that the thickener is selected from at least barite, calcium carbonate, dolomite, ilmenite, hematite, olivine, siderite, manganese oxide, hausmanite and strontium sulfate. 7. Method according to claim 1, characterized in that the thickener has a d90 particle size of less than 20 microns. 8. Method according to any one of claims 1 to 7, characterized in that the thickener has an organophilic coating on it. 9. Method according to claim 8, characterized in that the organophilic coating comprises at least one compound selected from oleic acid, stearic acid, polybasic fatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear alpha-olefin sulfonic acids, their alkaline earth metal salts, polyacrylate esters and phospholipids. 10. Method according to any one of claims 1 to 9, characterized in that the well fluid further comprises a silica, a fumed silica, a precipitated silica or a surface-modified precipitated silica. 11. Method for activating an oil expandable plug system, characterized in that it comprises: introducing into a well having a water-based plaster, on its respective walls, a well fluid containing oil, the well fluid containing oil comprising: phase oil continuous, where the oil continuous phase forms the entire fluid phase of well fluid containing oil, alkyl diamide, and coated organophilic thickener having a d90 particle size of less than 20 microns; contacting the oil-containing well fluid with an oil-swellable element in the well; and allow expansion of the expandable element in oil. 12. Method according to claim 11, characterized in that the alkyl diamide has the general formula: R1-HN - CO-(CH2)n-CO-NH-R2, where n is an integer from 1 to 20, R1 is an alkyl group having from 1 to 20 carbons and R2 is hydrogen or an alkyl group having from 1 to 20 carbons, where R1 and R2 may or may not be identical. 13. Method according to claim 11, characterized in that the organophilic coating comprises at least one dispersant selected from oleic acid, polybasic fatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear alpha-olefinic sulfonic acids, alkaline earth metal salts , polyacrylate esters and phospholipids. 14. Method according to claim 11, characterized in that the well fluid further comprises a silica, a fumed silica, a precipitated silica or a surface-modified precipitated silica. 15. Well fluid for expanding an expandable element, characterized in that it comprises: continuous oil phase, where the continuous oil phase forms the entire fluid phase of the well fluid, alkyl diamide, and coated organophilic thickener having a particle size of minus d90 20 microns, where the well fluid is free of emulsifiers, dispersants or disassociated surfactants. 16. Well fluid according to claim 15, characterized in that the alkyl diamide has the general formula: R1-HN - CO-(CH2)n-CO-NH-R2, where n is an integer from 1 to 20 , R1 is an alkyl group having from 1 to 20 carbons and R2 is hydrogen or an alkyl group having from 1 to 20 carbons, where R1 and R2 may or may not be identical. 17. Well fluid according to claim 15, characterized in that the organophilic coating comprises at least one dispersant selected from oleic acid, polybasic fatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear alpha-olefin sulfonic acids, metal salts alkaline earths, polyacrylate esters and phospholipids. 18. Well fluid according to claim 15, characterized in that it further comprises a silica, a fumed silica, a precipitated silica or a surface-modified precipitated silica.

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