NO346916B1 - Borehole fluids used with oil swellable elements - Google Patents

Description

BOREHOLE FLUIDS USED WITH OIL-SOLVABLE ELEMENTS

BACKGROUND

During the completion of wells in soil formations, different fluids are generally used in the well for a number of reasons. Common applications for downhole fluids include: lubrication and cooling of bit cutting surfaces during general drilling operations or drilling in an oil-bearing target formation, suspending loosened formation pieces and transporting them to the surface, controlling formation fluid pressure to avoid blow-out, maintaining well stability and minimizing of fluid loss into the formation through which the well is being drilled, fracturing of the formation in the vicinity of the well, displacing the fluid in the well with another fluid, cleaning the well, testing the well, imparting hydraulic horsepower to the bit, placing a packer, plugging or preparing the well of the well for the purpose of plugging, and otherwise treating the well or formation.

Borehole fluids or mud may include a base fluid, which is generally water, diesel or mineral oil, or a synthetic compound. Weight materials (barium sulphate or barite are most often used) can be added to increase density, and clays, such as bentonite, can be added to support the removal of cuttings from the well and to form a filter cake on the walls of the hole.

Borehole fluids also contribute to the stability of the borehole, and control the flow of gas, oil or water from the pores in the formation to prevent, for example, the flow, or in undesirable cases blow-out of formation fluids or collapse in earth formations put under pressure. The fluid column in the hole exerts a hydrostatic pressure that is 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 approximately 10 pounds per gallon (ppg), and in some cases may be as high as 21 or 22 ppg.

Oil-based muds (OBMs) have been used because of their flexibility in meeting properties related to density, inhibition, friction reduction and rheology desired in downhole fluids. The drilling industry has adopted water-based muds (WBMs) because they are inexpensive. The spent mud and cuttings from wells drilled with WBMs can be easily disposed of on site at most onshore locations. WBMs and drilling cuttings may also be discharged from platforms in many U.S. waters offshore as long as applicable discharge limitation guidelines, discharge standards and other permissible limits are met.

A specific category of wellbore or completion fluids includes annulus fluids or packer fluids, which are pumped into annular aperture spaces in a wellbore, such as, for example (1) between a wellbore wall and one or more casing strings extending into a wellbore, or (2) ) between adjacent concentric tubing strings extending into a borehole, or (3) in one or both of an A or B annulus in a borehole comprising at least an A and B annulus with one or more internal tubing strings extending into the borehole, which may run parallel or nominally parallel to 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 -an annulus in a borehole comprising at least an A, B and C annulus with one or more inner pipe strings extending into the borehole, which may run parallel or nominally parallel to each other and may or may not be concentric or nominally concentric with the outer casing string. Further alternatively, the one or more pipe strings may simply be run through a conduit or one or more outer pipes to connect one or more boreholes to another borehole or to lead from one or more boreholes to a centralized collection or processing center; and the annulus fluid may have been placed inside the channel or the pipe(s), but externally in relation to the one or more pipe strings therein.

Such packer fluids serve primarily to protect the casing, but also serve to provide hydrostatic pressure to equalize pressure relative to the formation, to depressurize sealing elements or packers; or to limit differential pressure acting on the wellbore, casing and production tubing to prevent wellbore collapse, and/or assist control of a well in the event of a leak in the production tubing or when the packer no longer provides a seal or has been opened. Although packer fluids can be formulated with sufficient density to fulfill such functions, solid weight materials that are often used in other downhole fluids are conventionally avoided in packer fluids due to the concerns about settling, especially because packer fluids often remain in the annulus for long periods of time without circulation. Furthermore, in addition to serving the above conventional functions, the fluid, for packer elements activated by the packer fluid or annulus fluid, may also be formulated with respect to such additional considerations.

Another category of wellbore or completion fluids includes open-hole fluids for unlined sections of the well. The fluids are pumped into a vertical section or high-angle section of a wellbore, where the target producing formation 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 , mains and/or selected inflow control devices which may or may not include gauges, control lines and even submersible pumps. Often, the open hole fluid is detected in the open hole prior to, and functions to enable, the installation of any of the above. In the example of a swellable packer/polymer(s), the open hole fluid can provide functionality such that the packer/polymer expands, thus providing a barrier to control pressure, movement of fluids and to increase the integrity of the lower installation.

Consequently, there is a continuing need for improvements in borehole fluids, so that they achieve sufficient density and take into account other factors which may be particularly desirable when used with packer elements and/or swellable polymers used in boreholes and open boreholes.

SHORT DESCRIPTION

In one aspect, the embodiments described herein relate to a method for completing a borehole, which includes introducing an oily borehole fluid into a borehole having a water-based filter cake 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, wherein the oily wellbore fluid is substantially free of unassociated surfactants, emulsifiers, wetting agents or dispersants, and may include an oily fluid and a weighting material.

In another aspect, embodiments described herein relate to a method for activating an oil-swellable packer system, which includes introducing into a borehole having a water-based filter cake on the walls thereof, an oily borehole fluid; contacting the oil-containing wellbore fluid with an oil-swellable element in the wellbore; and allowing swelling of the oil-swellable element, wherein the oily wellbore fluid includes an oily continuous phase, wherein the oily continuous phase forms substantially all of the fluid phase of the oily wellbore fluid; an alkyl diamide, and an organophilic coated weight material having a particle size d90 of less than about 20 microns.

In yet another aspect, embodiments described herein relate to a borehole fluid that includes an oily continuous phase, wherein the oily continuous phase forms substantially all of the borehole fluid's fluid phase, an alkyl diamide, and an organophilic coated weight material having a particle size d90 of less than about 20 microns, the wellbore fluid being substantially free of any unassociated surfactants, dispersants or emulsifiers.

This brief description is intended to introduce a selection of concepts which are described further in the detailed description. It is not the purpose of this brief description to identify key features or essential features of the item specified in the requirements, nor is it intended to be used as an aid to limit the scope of the item specified in the requirements. Other aspects and advantages according to the invention will appear clearly from the following description and the accompanying claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 is an isometric representation of an example of a system in which the embodiments of a sealing element can be implemented.

Figure 2 is a bar graph showing an oil swellable packer's total volume increase when soaked in various swelling fluid formulations.

Figure 3 is a photograph showing the compatibility of two swelling fluid formulations with a water-based filter cake.

Figure 4 is a bar graph showing the swelling of an oil swellable packer when soaked in a fluid sample compared to diesel.

DETAILED DESCRIPTION

The embodiments described herein relate to borehole fluids (and methods for using such borehole fluids) for various completion operations.

Embodiments according to the present disclosure particularly relate to borehole fluids used to activate oil-swellable polymer compositions of a swellable element for a well that is drilled with a water-based borehole fluid. The oil-swellable elements (and thus borehole fluids according to the present disclosure) can be used in oil-swellable packer system applications such as, but not limited to, completion of wells, plugging or abandonment of wells, isolation of zones of the well, reservoir division or borehole segmentation.

The wellbore fluids according to the present disclosure may thus have several components, including an oily base fluid, so that there is a sufficient amount of the fluid that is free to diffuse into and swell the polymer, and a weight material to give the oily fluid more weight, so that a higher density can be achieved. The borehole fluids of the present disclosure can also be used to activate a swellable polymer composition that has been placed in the borehole as a packer element, for gravel packing or other applications discussed herein. The swellable composition can be oil-swellable material which swells by diffusion of hydrocarbons into the oil-swellable material.

In some embodiments, a borehole may be drilled using a water-based borehole fluid, where the water-based borehole fluid filters into the formation to form a water-based filter cake. As used herein, a water-based filter cake is a filter cake that is water-wet, and may be formed from any aqueous fluid, for example with water or an aqueous fluid as the major fluid portion of the fluid and/or any emulsion that forms a water-wet filter cake when filtering into the formation. In a particular embodiment, the water-based wellbore fluid may be displaced by an oil-containing wellbore fluid according to the present disclosure, which is allowed to diffuse into oil-swellable materials placed downhole, such as, for example, an oil-swellable packer, causing the oil-swellable materials to be "activated" or sleepers.

In another embodiment, the oil-swellable packer can be incorporated into a screening assembly packer for an open well completion prior to the production of hydrocarbons from a wellbore, to use the swellable packer to achieve zone isolation and to block potential unwanted fluid intrusion. Such techniques are described in more detail in US patent application no. 2007/0151724, to which reference is hereby made, and which in its entirety shall be considered as being part of the present application.

As mentioned above, the borehole fluid used to activate or swell the oil-swellable element can be an oily fluid. In some embodiments, the oily borehole fluid is formed exclusively or essentially entirely from an oily fluid that is essentially free of an aqueous component and essentially free of emulsifiers or the like. In another embodiment, the fluid phase of the borehole fluid is made up of an oily fluid which is essentially free of an aqueous component and essentially free of emulsifiers, but may contain a certain amount of a non-aqueous, non-oily fluid. In yet another embodiment, the oily borehole fluid may be a direct emulsion, where an oily fluid is a discontinuous phase within an aqueous or non-oily continuous phase which is formulated to be substantially free of emulsifiers or the like.

Swellable elements

As mentioned above, the borehole fluid is used to activate a swellable packer system or other swellable elements. Swellable packer systems include a swellable composition that can be used to fill a space in the borehole. 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 tooling 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 a lower section of the well. Often the swellable composition is attached to a main pipe, liner or even the feed pipe. 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.

Furthermore, swellable compositions are those which, when exposed to one or more particular substances, such as water or hydrocarbons, swell or expand to a size greater than the size of the element before swelling. The borehole fluid's base fluid, which is used in connection with the swellable compositions, is absorbed into the swellable packer by means of diffusion. Through the random thermal movement of the molecules in the liquid, the fluid diffuses into the packer. When the packer is wrapped around a pipe member's outer circumference, the result of the swelling is an increase in the swellable packer's manufactured outside diameter. The fluid can continue to diffuse into the packer, causing the packer element to swell, so that it reaches the inside diameter of the casing or the well's open bore, and will continue to swell until the internal stresses within the packer material reach equilibrium. That is, the swelling pressure increases until diffusion can no longer take place. In particular, the swellable element can swell at least sufficiently for the swellable element to create a seal in the annulus, such as a differentially sealing annular barrier that is created between the upper and lower sections of the well. Optionally, the swellable packer can be used to create a barrier between designated sections of an open borehole to allow selective isolation during completion or after completion. In embodiments, the swellable element thickness may swell at least 5%, at least 10%, at least 15%, at least 20%, at least 25%, or at least 50%. Often the swellable element can be limited to expand only in a radial direction, but in other embodiments it can expand both radially and axially.

Other embodiments may include an inflatable element in a bridge plug, which is a tool that can be positioned and inserted into a borehole to isolate a lower part of the borehole from an upper part of the borehole.

According to one method of application, a swellable packer or other element, such as a bridge plug, can be placed in a section of a borehole that has been drilled, in embodiments, with a water-based fluid, so that a water-based filter cake remains on borehole walls. More than one swellable element can of course be placed in the borehole. A combination of swellable packers and/or bridge plugs can also be placed in sections of a borehole. A swelling fluid is then introduced directly into the annulus itself, or introduced into the annulus via the pipe string or the feed pipe. The swelling fluid may be allowed to contact the packer's or bridge plug's swellable element, causing the swellable element to begin to swell. The swelling fluid may be allowed to remain in contact with the swellable element for a time sufficient for the swellable element to swell and expand to a size sufficient to seal the annulus.

Swellable compositions used in the methods of the present disclosure may be formed from various materials which 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-polyacrylic acid graft copolymer, polyvinyl alcohol- cyclic acid anhydride graft copolymer, isobutylene maleic anhydride, polyacrylates, acrylate butadiene rubber, vinyl acetate acrylate 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, hydrogenated acrylonitrile butadiene rubber, acrylonitrile butadiene rubber, isoprene rubbers, neoprene rubbers, sulphonated polyethylenes, ethylene acrylate, epichlorohydrin ethylene oxide copolymers, ethylene-propylene rubbers, ethylene-propylene diene interpolymer rubbers, ethylene vinyl acetate copolymer, acrylamides, acrylonitrileb utadiene rubbers, polyesters, polyvinyl chlorides, hydrogenated acrylonitrile butadiene rubbers, fluororubbers, fluorosilicone rubbers, silicone rubbers, poly-2,2,1-bicycloheptenes (polynorbornene), alkylstyrenes or chloroprene rubbers. Although the specific chemistry is not limiting to the present methods, oil-swellable polymer compositions may also include oil-swellable elastomers.

Oily borehole fluids

As mentioned above, in order to activate the oil swellable element, i.e. to cause the swellable element to swell, the wellbore fluid may be oily. The oily borehole fluid may contain an amount of an oily fluid sufficient to activate the swellable composition by diffusion of the oily 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 borehole component can vary, for example based on the size of the packer, required extent of swelling/expansion of the element, etc.

In some embodiments, the oily fluids of the present disclosure may include an oily fluid as the continuous phase of the fluid, whereas other embodiments may employ a direct emulsion where the oily fluid is a discontinuous phase within an aqueous or non-oily continuous phase.

Oily fluids can be a liquid, such as a natural or synthetic oil, and in some embodiments, the oily fluid can be selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and non-hydrogenated olefins, including polyalphaolefins, linear and branched olefins and the like, polydiorganosiloxanes, siloxanes or organosiloxanes, esters of fatty acids, especially straight-chain, branched and cyclic alkylethers of fatty acids, mixtures thereof and similar compounds which are known to the person skilled in the art; and mixtures thereof. In a particular embodiment, the fluids may be formulated using diesel oil or a synthetic oil as the external continuous phase.

In one embodiment, the oily fluid may be present without any aqueous or non-oily phase, or may be substantially free of an aqueous and/or non-oily fluid (such as those described below). As used herein, substantially free of an aqueous or non-oily fluid can be understood to mean that the fluid contains less than 20 vol% of an aqueous or non-oily fluid, or less than 10 vol% or 5 vol% of other embodiments. In other embodiments, however, the fluid may contain a non-aqueous, non-oily fluid that has partial miscibility (ie, some but not full solubility, such as at least 10-25% or greater miscibility) with the oily fluid in an amount which is more than 20 vol%. In addition, co-solvents, i.e. a fluid which is soluble in both aqueous and oily fluids, may be present in the oily fluid, including in the oily fluids which are at least substantially free of an aqueous or non-oily fluid . Illustrative examples of such common 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 ethyl lactate, propylene carbonate, butylene carbonate, etc., and pyrrolidones.

When formulated without or substantially free of an aqueous or non-oily phase (or even if it contains a non-aqueous, non-oily fluid that is partially miscible with an oily fluid), the fluid may also be free of or substantially free of any non-associated surfactants, wetting agents, dispersants or emulsifiers, i.e. any amphiphilic compounds containing both hydrophilic and hydrophobic groups in the molecule. As used herein, "non-associated" refers to molecules that are not chemically bound to or otherwise chemically or physically associated with another species (such as a solid weight material). Under such a definition, a dispersant or wetting agent provided as a coating on weight material would be considered to be associated, not non-associated. As used herein, substantially free of an unassociated surfactant, wetting agent, dispersing agent or emulsifier 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 may be, for example, less than 5 pounds per barrel (ppb) or less than 4 ppb, 3 ppb, 2 ppb, or 1 ppb, in other embodiments. Thus, a wetting agent or dispersing agent may be provided to coat a solid weight material, but the amount added would not be so great that an inverted emulsion could be formed with any excess of wetting agent or dispersing agent. Such an excess may be less than 5 ppb, 4 ppb, 3 ppb, 2 ppb or 1 ppb in various embodiments.

In some embodiments, the wellbore fluid may be a direct emulsion having an aqueous or non-oily fluid as a continuous phase, where the oily 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-oily fluids that can be used in the embodiments described herein can be a liquid, such as an aqueous liquid. In embodiments, the non-oily liquid may be selected from the group including fresh water, seawater, a saline solution containing organic and/or inorganic dissolved 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 may include, but are not limited to, for example, alkali metal chlorides, hydroxides or carboxylates. In various embodiments of the borehole fluid described herein, the salt solution may include seawater, aqueous solutions in which the salt concentration is less than that in seawater, or aqueous solutions in which the salt concentration is greater than that in seawater. 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, sulphates, silicates and fluorides. Salts which may be incorporated into a given salt solution include any one or more of those found in natural seawater or any other organic or inorganic dissolved salts. In addition, salt solutions that can be used in the borehole fluids discussed herein can be natural or synthetic, where synthetic salt solutions tend to have a much simpler constitution. In one embodiment, the density of the borehole fluid can also be controlled by increasing the salt concentration in the salt solution (up to saturation). In a particular embodiment, a salt solution 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.

In the embodiments using direct emulsions, the wellbore fluid may contain an oily fluid (to swell the oil-swellable element) in an amount having 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%, where any lower limit may be combined with any upper limit. In specific embodiments, the oily fluid may constitute 20-70 vol% of the borehole fluid, 30-60 vol% or 40-50 vol%, where the rest of the fluid part is the non-oily fluid.

Fixed weight materials

The density of the fluid can be increased by incorporating a solid weight material. Solid weight materials used in any of the embodiments described herein may include a variety of inorganic compounds well known to those skilled in the art. In some embodiments, the weight material may be selected from one or more of the materials including, for example, barium sulfate (baryte), 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 another acid-soluble weight material can be used.

Those skilled in the art will recognize that the choice of a particular material may depend to a large extent on the density of the material, as the lowest borehole fluid viscosity is generally achieved at any particular density by using the particles with the highest density. In some embodiments, the weight material can be made up of particles that are composed of a material with a 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 weight materials can also be used, having a specific gravity of approximately 4.2, 4.4 or even as high as 5.2.

For example, a weight material formed from particles having a specific gravity of at least 2.68 may allow wellbore fluids to be formulated to meet most density needs, yet have a particle volume fraction low enough for the fluid to be pumpable. However, other considerations can have an impact on the choice of product, such as cost, local availability, the power required for grinding, and whether the solid residue or filter cake can be easily removed from the well. In certain embodiments, the borehole fluid may be formulated with calcium carbonate or another acid-soluble material.

The solid weights may be of any particle size (and particle size distribution), but some embodiments may include weights having a smaller particle size range than API grade weights, which may generally be referred to as micronized weights. Such weight materials can generally be in the micron range (or less), including submicron particles i

the nanosize range.

In some embodiments, the mean particle size (d50) of the weight materials 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 micron, 1.5 micron, 3 micron, 5 micron or 7.5 micron, to an upper limit of less than 500 nm, 700 micron, 1 micron, 3 micron, 5 micron, 10 micron, 15 micron , 20 microns, where the particles may range from any lower limit to any upper limit. In other embodiments, the d90 of the weight materials (the size at which 90% of the particles are smaller) 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 particle ranges described above can be achieved by finely grinding the materials to the desired particle size or by precipitation of the material from a scratch assembly approach. Precipitation of such materials is described in US patent application publication no. 2010/009874, which is assigned to the right holder of the present application, and to which reference is hereby made, and which is to be considered in its entirety as being part of the present application. A person skilled in the art will understand that depending on which sizing technique is used, the weight material may have a particle size distribution other than a monomodal distribution. That is, the weight material may have a particle size distribution which in various embodiments may be monomodal, which may or may not be Gaussian, bimodal or polymodal.

In one embodiment, a weight material is sized such that: particles having a diameter of less than 1 micron comprise 0 to 15 percent by volume; particles having a diameter between 1 micron and 4 microns constitute 15 to 40 percent by volume; particles having a diameter between 4 microns and 8 microns constitute 15 to 30 percent by volume; particles having a diameter between 8 microns and 12 microns constitute 5 to 15 percent by volume; particles having a diameter between 12 microns and 16 microns constitute 3 to 7 percent by volume; particles having a diameter between 16 microns and 20 microns constitute 0 to 10 percent by volume; particles having a diameter greater than 20 microns constitute 0 to 5 percent by volume. In another embodiment, the weight material is of such a size that the cumulative volume distribution is: less than 10 percent of the particles are less than 1 micron; less than 25 percent are in the 1 micron to 3 micron range; 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 10 micron to 24 micron range.

The use of weight materials that have such size distributions is described in US patent application publications no. 2005/0277553 and 2010/0009874, which are assigned to the right holder of the present application, and to which reference is hereby made, and which in its entirety shall be considered as being a part of the present application. Particles having these size distributions can be obtained by any means known in the art.

In some embodiments, the weight materials include dispersed solid colloidal particles having a weight average particle diameter (d50) of less than 10 microns, which are coated with an organophilic polymeric antiflocculating agent or dispersant. In other embodiments, the weight materials include dispersed solid colloidal particles having a weight average particle diameter (d50) of less than 8 microns, which are coated with a polymeric antiflocculating agent or dispersant; 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 slurries that will exhibit a reduced tendency to sediment or seepage, and the polymeric dispersant on the particle's surface can control the interparticle interactions and will thus form lower rheological profiles. It is the combination of fine particle size and control of colloidal interactions that unites the two purposes of lower viscosity and minimal seepage.

In some embodiments, the weight materials may be uncoated. In other embodiments, the weight materials can be coated with an organophilic coating, such as a dispersing agent, including carboxylic acids with a molecular weight of at least 150 Daltons, such as oleic acid, stearic acid and polybasic fatty acids, alkylbenzenesulfonic acids, alkanesulfonic acids, linear alpha olefinsulfonic acid and alkaline earth metal salts thereof. Further examples of suitable dispersants may include a polymer compound, such as a polyacrylate ester consisting of at least one monomer selected from stearyl methacrylate, butyl acrylate and acrylic acid monomers. The illustrative polymer dispersant can 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. The person skilled in the art will realize that other acrylate or other unsaturated carboxylic acid monomers (or esters thereof) can be used to achieve essentially the same results as those described herein.

In embodiments, the coated weight materials can be formed using either a dry coating process or a wet coating process. Weight materials suitable for use in other embodiments described herein may include those described in US Patent Application Publication Nos. 2004/0127366, 2005/0101493, 2006/0188651, 2008/0064613, and US Patent Nos. 6,586,372 and 7,176,165, as reference is hereby made to these, and they shall all be considered as being part of the present application.

The particulate materials described herein (ie the coated and/or uncoated weight materials) can be added to a borehole fluid as a weight material in a dry form or concentrated as a slurry in either an aqueous medium or as an organic liquid. As is known, an organic fluid can have the environmental characteristics required for additives to oily wellbore fluids. With this in mind, the oily 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 over 60°C. Suitable oily fluids 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 those skilled in the art of drilling, or other borehole fluid formulation. In one embodiment, the desired particle size distribution is achieved by means of wet milling of the coarser materials in the desired carrier fluid.

Such solid weight materials can be particularly useful in borehole fluids that are formulated with a fully oily fluid phase. In a particular embodiment, an organophilic coated weight material having a particle size within any of the described ranges can be used in a fluid which is free of or substantially free of an aqueous phase contained therein. Solid weight materials 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.

In one embodiment, the wellbore 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 density of the wellbore fluid in some embodiments is in the range of from about 6 to about 18 ppg, wherein the weighting material 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.

Downhole fluid additives

Other additives which may be included in the borehole fluids described herein include, for example, wetting agents, organophilic clays, viscosity increasing agents, fluid loss control agents, surfactants, dispersants, interfacial tension reducing agents, pH buffers, common solvents, thinners, diluents and cleaning agents. The addition of such agents should be well known to those skilled in the art of formulating borehole fluids and muds.

In some embodiments, additives may be included in the composition to modify rheological properties, such as viscosity and flow. For example, organic thixotropics suitable for addition to wellbore fluids according to the present disclosure include alkyl diamides, such as those having the general formula: R1-HN-CO-(CH2)n-CO-NH-R2, where n is an integer from 1 to 20, from 1 to 4 or from 1 to 2, and R1 is an alkyl group 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, where R 1 and R 2 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 viscosity increasing agents can be particularly suitable for use in an oily borehole fluid which is essentially free of an aqueous or non-oily fluid, but can also be included in direct emulsions.

In other embodiments, organophilic clays, such as amine treated clays, may be useful as viscosity increasing agents in the fluid composition of the present disclosure. VG-69<TM> and VG-PLUS<TM> are organoclay materials, available from M-I L.L.C., Houston, Texas, which can be used in the embodiments described herein. Such organophilic clays, as well as water-based clays, can be particularly useful in assisting in the formation and stabilization of a direct emulsion. Other viscosity increasing agents that may be used include partially hydrolyzed polyacrylamide (PHPA), biopolymers (such as guar gum, starch, xanthan gum, and the like), bentonite, attapulgite, sepiolite, polyamide resins, polyanionic carboxymethyl cellulose (PAC or CMC), polyacrylates, lignosulfonates, as well as like other water-soluble polymers. When a direct emulsion is formulated without an emulsifier, a surfactant, etc., the viscosity increasing agent can be incorporated to increase the viscosity of the two phases and thus miscibility, so that a direct (oil-in-water) emulsion is formed by mixing in a high shear mixer, as that term is understood by those skilled in the art, operating at at least 3500 rpm, or at least 5000 or 7000 rpm in other embodiments.

In other embodiments, fumed silica and/or precipitated silica can be used as a viscosity-increasing agent. In yet other embodiments, precipitated silica can advantageously be used to provide both weight gain and viscosification of the oily base fluid. When used to provide weight and viscosification, the precipitated silicas can be used in addition to or in place of the weight materials described above. Alternatively, the relative amounts of the weight material and the precipitated silica in the borehole fluid formulation can be adjusted so that the borehole fluid has both the desired density and the desired flow properties.

Precipitated silica has a porous structure and can be produced from the reaction of an alkali silicate solution with a mineral acid. Alkali silicates can, for example, be selected from one or more of sodium silicate, potassium silicate, lithium silicate and quaternary ammonium silicates. Precipitated silicas can be produced by means of the destabilization and precipitation of silica from soluble silicates by the addition of a mineral acid and/or acid gases. The reactants thus 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 an alkali silicate solution to water with constant agitation. The choice of agitation, precipitation duration, rate of addition of reactants, temperature, concentration and pH can change the properties of the resulting silica particles.

Precipitated silicas useful in the embodiments herein may include finely divided solid particulate materials, such as powders, silts, or sands, as well as reinforced flocs or agglomerates of smaller particles of siliceous material. In some embodiments, 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 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 cause comminution of such particles, such as breaking up the agglomerates, resulting in a silica particle having a useful average particle size.

Precipitated silica can contain varying amounts of residual alkali metal salts which are the result of the association of the corresponding silicate motion with available anions contributed 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 Mg, Ca and Ba, or organic cations such as ammonium, tetraalkylammonium, imidazolium, alkylimidazolium 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 (equivalent to Na2SO4) of less than approximately 2% by weight. While the pH of the resulting precipitated silicas may vary, embodiments of the silicas useful in the embodiments described herein may have a pH in the range of from about 6.5 to about 9, such as in the range of from about 6.8 to approximately 8.

In other embodiments, surface-modified precipitated silicas can be used. The surface-modified precipitated silica may include, for example, a lipophilic coating.

The surface modification can be added to the silica after precipitation. Alternatively, the silica can be precipitated in the presence of one or more of the surface modifiers described above.

It has been shown that, according to the embodiments herein, surface-modified precipitated silicas can advantageously provide both weight gain and viscosification of the oily base fluid. Precipitated silicas according to the embodiments herein are useful for providing wellbore fluids that have improved thermal stability at temperature extremes, while exhibiting a substantially constant rheological profile over time.

In some embodiments, the surface of the silica particles can be chemically modified using a number of synthetic techniques. The surface functionality of the particles can be tailored to improve solubility, dispersibility or introduce reactive functional groups. This can be achieved by causing the precipitated silica particles to react with organosilanes or siloxanes, in which reactive silane groups present on the molecule can be covalently bound to the silica lattice that makes up the particles. Non-limiting examples of compounds that can be used to functionalize the surface of the precipitated silica particles include aminoalkylsilanes, such as aminopropyltriethoxysilane, aminomethyltriethoxysilane, trimethoxy[3-(phenylamino)propyl]silane and trimethyl[3-(triethoxysilyl)propyl]ammonium chloride; alkoxyorganomercaptosilanes, such as bis(3-(triethoxysilylpropyl) tetrasulfide, bis(3-(triethoxysilylpropyl)disulfide, vinyltrimethoxysilane, vinyltriethoxysilane, 3-mercaptopropyltrimethoxysilane; 3-mercaptopropyltriethoxysilane; 3aminopropyltriethoxysilane and 3-aminopropyltrimethoxysilane; and alkoxysilanes.

In another embodiment, organosilicone materials containing reactive end groups can be covalently linked to the surface of the silica particles. Reaktive polysiloksaner kan innbefatte for eksempel dietyldiklorsilan, fenyletyldietoksysilan, metylfenyldiklorsilan, 3,3,3-trifluorpropylmetyldiklorsilan, trimetylbutoksysilan, sym –difenyltetrametyldisiloksan, oktametyltrisiloksan, oktametylsyklotetrasiloksan, heksametyldisiloksan, pentametyldiklorsilan, trimetylklorsilan, trimetylmetoksysilan, trimetyletoksysilan, metyltriklorsilan, metyltrietoksysilan, metyltrimetoksysilan, heksametylsyklotrisiloksan, heksametyldisiloksan, hexaethyldisiloxane, dimethyldichlorosilane, dimethyldimethoxysilane, dimethyldiethoxysilane, polydimethylsiloxanes comprising 3 to 200 dimethylsiloxy units, trimethylsiloxy or hydroxydimethylsiloxy end-blocked poly(dimethylsiloxane) polymers (silicone oils) having an apparent viscosity within the range of from 1 to 1000 mPascal at 25°C, vinyl silane, gamm-methacryloxypropyltrimethoxysilane , polysiloxanes, e.g. polysiloxane spheres, and mixtures of such organosilicone materials.

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 can be in the range from about 20 m<2>/g to about 70 m<2>/g.

In one or more embodiments, the precipitated silica has a BET-5 nitrogen surface area of 20 m<2>/g to 70 m<2>/g, as calculated from the surface adsorption of N2 using the BET-1 point method, a pH of the range of pH 7.5 to pH 9, and an average particle diameter in the range of 20 nm to 100 nm.

In some embodiments, precipitated silicas useful in embodiments herein may include those described in US Patent Application Publication Nos. 2010/0292386, 2008/0067468, 2005/0131107, 2005/0176852, 2006/0225615, 2006/022863062, and 2006/02286309. , all of which are hereby referred to, and each of which is to be considered as part of the present application.

Another additive to oily wellbore fluids that can optionally be included in the oily wellbore fluids described herein is a fluid loss control agent.

Fluid loss control agents can act to prevent loss of fluid to the surrounding formation by reducing the permeability of the barrier of congealed wellbore fluid. Suitable fluid loss control agents may include such as modified lignites, asphalt compounds, gilsonite, organophilic humic acid salts 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 used in an amount that is at least from about 0.5 to about 15 pounds per barrel. The fluid loss reducing agent should be resistant to elevated temperatures, and inert or biodegradable. ECOTROL RD<TM>, an oil-soluble polymeric fluid loss control agent that can be used in the wellbore fluid, is commercially available from M-I L.L.C., Houston, Texas.

To illustrate an embodiment of a well completion with a swellable packer system, an annular sealing element (packer) is deployed in a borehole. Figure 1 shows an embodiment of an annular sealing element 100 including sections made of the swellable composition. The sealing element 100 may include a support element 110 which has an outer swellable element 120 arranged around an outer diameter thereof. The support element 110 can also have an inner swellable element 130 arranged around an inner diameter thereof. The support element 110 may have openings 115 formed therethrough, the outer swellable element 120 being allowed to form a unit with the inner swellable element 130.

The outer swellable member 120 may be disposed around the support member 110, and may be configured to engage a wall of a borehole or other structure disposed around the outer swellable member 120. The inner swellable member 130 may be configured to swell within the support element 110 around a pipe element or other object which is at least partially arranged inside the support element 110. The swellable elements 120 and 130 are made to form a unit, the sealing element 100 being allowed to withstand differential pressure. The swellable elements 120 and 130 can be made from the swellable composition.

After the sealing element 100 is placed in the borehole around a pipe string or drill string (along with any other completion equipment), an oily borehole fluid (such as any of those described above) is formed by mixing a base fluid with a weight material (such as a micronized weight material) together with additives that provide the correct rheological properties required for the well. The borehole fluid is then pumped downhole (either directly into the annulus or through a pipe string), and is allowed to contact the swellable elements placed in the borehole (previously or subsequently placed therein). In a particular embodiment, the oily borehole fluid may displace a water-based borehole fluid used to drill at least part of the borehole. Such displacement can take place with or without the use of spacer fluids, as known in the art, but without any washing or breaker fluids. Alternatively, in other embodiments, the water-based drilling fluid may first be displaced with a treated mud, a solids-free mud, or a saline solution prior to introduction into the oily fluid of the present disclosure. Thus, the oily fluid can be pumped into a borehole which has a water-based filter cake on the walls thereof, without the water-based filter cake being removed and the well being otherwise cleaned. The oily fluid can diffuse into the oil-swellable elements 120 and 130, which can swell until the internal stresses within the polymer reach equilibrium. That is, the swelling pressure increases until diffusion can no longer take place. At this point, a differentially sealing ring-shaped barrier is created between the upper and lower sections of the well. In some embodiments, the oily fluid of the present disclosure is introduced into an unlined section of the well, below the packer element. Other embodiments may involve introducing the oily fluid above the packer element or both above and below the packer element.

As used herein, a "well" includes at least one borehole drilled into a subsurface formation, which may be a reservoir or adjacent to a reservoir. A borehole can have vertical and horizontal sections, and it can be straight, curved or branched. The borehole can be an open borehole or a lined borehole. In an open-hole wellbore, a tubing string, which allows fluids to be placed into or removed from the wellbore, is placed into the wellbore. In a cased borehole, a casing pipe is placed in the borehole, and a pipe string can be placed in the casing pipe. An annulus is the area between two concentric objects, such as between the borehole and casing or between casing and pipe string, where fluid can flow.

Annular sealing elements suitable for use in other embodiments described herein may include, but are not limited to, those described in US Patent Application Publication Nos. 2007/0151724, 2007/0205002, 2008/0308283, and US Patent Nos. 7,143,832 and 7,849,930, as reference is hereby made to these, and they shall all be considered as being part of the present application. Sealing elements can also be used in combination with any other tools where isolation of borehole segments is desired.

Although 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 packing techniques and borehole orientations can benefit from the swellable packer system described. In another embodiment of a well completion, the packer can be incorporated into a screening assembly packer for an open well completion to utilize the swellable packer to achieve zone isolation and to block potential unwanted fluid intrusion, as described in US Patent Application Publication No. 2007/0151724, which is hereby referred to, and which in its entirety shall be considered as being part of the present patent application.

Examples

As mentioned above, the oily fluids according to the present publication can be used to swell an oil-swellable packer composition that is used in a borehole that has been drilled with a water-based drilling fluid, where there is residual water-based fluid in the form of a water-based filter cake remaining in the well. Such fluids may include any water-based borehole fluid known in the art, which may contain an aqueous fluid (such as those described above) constituting substantially all of the fluid portion of the fluid, one or more solid particles, including bridging agents or weight materials known in the art, fluid loss control and/or viscosity increasing agents, such as xanthan or other natural or synthetic polymers, as well as other additives known in the drilling fluid art.

Example 1

To measure the effectiveness of the oil-containing wellbore fluids in activating an oil-swellable packer, four wellbore fluid formulations were prepared. Mixed in the various proportions, the samples included the following components: diesel, water, dry calcium chloride, lime; SAFE-CARB<TM >2, a calcium carbonate weighting material; ECOTROL RD<TM>, an oil-soluble methylstyrene/acrylate copolymer; lime; VG-PLUS<TM>, an organophilic clay viscosity increasing agent; VERSCOAT<TM>, a modified amidoamine derived fatty acid emulsifier and wetting agent; VERSAWET<TM>, an oxidized fatty acid surfactant;

VERSAMUL<TM>, a mixture of fatty acids and tall oil emulsifier for oil-based muds; ECF-2184, an carboxylated fatty alcohol terminated with a carboxylic acid emulsifier;

VERSAPAC<TM>, an alkyl diamide; and EMI-2180, a micronized calcium carbonate weight material 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 from stearyl methacrylate, butyl acrylate, and acrylic acid monomers, all of which are available from M-I LLC (Houston, Texas). The fluid formulations are as follows:

Table 1 Formulations for oil-swellable packer fluids

Diesel oil was used as a control in sample 1. A conventional reverse system with an oil-to-water ratio (OWR) of 60:40 was mixed into sample 2 using VERSCOAT<TM>, VERSAWET<TM> to oil-wet the system and maintaining an inverted emulsion with saline phase, and SAFE-CARB<TM >2 as the weight material. In addition, a high internal phase ratio (HIPR) emulsion was prepared for sample 3, which contained no solids, and a special emulsifier that maintains a water-in-oil system at very low OWR that is not possible using conventional chemistry. Finally, sample 4 is an all-oil system prepared with the organic alkyl diamide viscosity increasing agent to achieve suspension of the organophilic coated calcium carbonate weight material, which can reduce or eliminate the need for an emulsifier or a wetting agent in the fluid.

Swelling analyzes were performed in which portions of samples 1-4, referred to as "soak fluid" in Table 2, were loaded into pressurized cells with a coupon of an oil-swellable packer material, and placed in an oven for static aging at 225°F (107< o>C) for 24 hours. Following the static incubation time, cells were removed, air cooled and measured. Sample 1, the diesel oil control, was poured into a glass containing a coupon sample and aged for 24 hours at room temperature, as for safety reasons it was not possible to test the fluid at an elevated temperature.

The results are shown in table 2 and figure 1.

Table 2 Calculated change in oil-swellable packer coupon size after exposure to various oil-based fluids.

Example 2

To determine the increase in fluid properties of the packer swell fluid in whole oil under high temperature downhole conditions, two different varieties of 9.6 lb/gal volumes of sample 4 were mixed as shown in Table 3. The fluid was sheared on a Silverson mixer, the associated heat being controlled with a cooling bath to keep the temperature below 150°F (66<o>C ). Viscosity data for both formulations are shown in Table 4. In both samples of Sample 4, an increase in rheology was observed after static aging at 225°F (107<o>C ) for 24 hours.

Table 3 Formulations for Sample 4 Variation systems

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

Example 3

To demonstrate the compatibility of the oily packer swelling fluid Sample 4 with respect to a conventional reverse emulsion fluid, a filter cake was generated using an aqueous reservoir drill-in fluid on an aloxite disc at 220°F (104<o>C ). The cell was emptied of drilling fluid and replaced with sample 4-1 (table 3), in contact with the water-based filter cake. This procedure was repeated for a second cell, using a conventional inverted emulsion, i.e. sample 2. The cells were pressurized to 100 psi and heated to 150°F for 24 hours. The cells were then removed and allowed to cool to room temperature.

Cells were disassembled and the filter cakes removed and photographed. An emulsion was observed on the water-based filter cake exposed to the reverse emulsion fluid (lane B, Figure 3), which can be attributed to the degradation of the filter cake by emulsifiers used to stabilize the reverse emulsion. The filter cake exposed to an all-oil system (and free of all emulsifiers and wetting agents) in sample 4 (route A, Figure 3) showed no signs of emulsion formation.

Example 4

An oily borehole fluid formulated with a silica additive was tested for the ability to viscosity and activate an oil-swellable element. ECF-2723, an amorphous precipitated silica with a d50 of approximately 5 microns, is available from M-I SWACO (Houston, Texas). The fluid formulations are as follows:

Table 5 Formulations for oil-swellable packer fluids

The rheology (measured at 120F) of sample 5 was tested for initial properties after mixing, as well as after 18 hours of static aging at 180F, as shown in Table 6. Although a small drop in rheology was observed, as shown in Table 6, there was no evidence of weight material precipitation after static aging. A top oil separation of approx. 2mm was measured.

Table 6 Rheology for 9.6 lb/gal Sample 5 System

To evaluate the screen plugging potential of the solids loaded sample 5, a production screen test (PST) was performed. The production sieve test consists of a 1.2 liter pressurized cell where fluid is passed through a sand control sieve coupon. Failure of the test may be indicative of plugging from a change in the rate at which fluid passing through the coupon is noted, or plugging stops fluid flow completely. The PST was performed using 1 liter fluid volume at 20 psi through a wound mesh screen, size 6. There was no evidence of plugging as the fluid passed freely through in 6.53 seconds. The wrapped mesh strainer coupon was removed, carefully cleaned in solvent to check for visible signs of solids trapped in the coupon. The coupon appeared clean, with no sign of trapped materials.

Sample 5 was also subjected to a swelling test, where a sample of oil-swellable elastomeric material was placed in a cell containing a volume of sample 5.

The elastomer coupon was statically 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 swelling performance. The recorded measurements include top width, bottom width, height and thickness, as shown in figure 7 below. A comparison (an increase in swelling as a measure of length) of the sample 5 soaked coupon with an elastomeric coupon soaked in diesel fuel for 18 hours at room temperature (for safety reasons) is presented in Figure 4.

Table 7 Results of swelling test

Embodiments according to the present disclosure relate to a borehole fluid that can be used in the completion of a well. For wells that have been drilled with a water-based fluid, the present disclosure may advantageously allow the use of an oil-swellable packer which may have better sealing characteristics than a water-swellable packer. Furthermore, embodiments according to the present publication can also allow the use of an oily fluid which can be weighted to the desired density (for the purpose of well control) without the risk of particle precipitation. Furthermore, in an embodiment using an all-oil system or a direct emulsion, as described herein, the elimination or reduced amount of the emulsifier, surfactants or wetting agents may be desirable to minimize the interaction between the water-based filter cake and the oily wellbore fluid, as displacement logistics between water- and oily fluids are thus simplified.

Although the invention has been described with respect to a limited number of embodiments, those skilled in the art having the benefit of this disclosure will recognize that other embodiments may be devised which do not depart from the scope of the invention as set forth herein. Accordingly, the scope of the invention shall only be limited by the accompanying claims.

Although a few examples of embodiments have been described in detail in the above, the person skilled in the art will easily understand that many modifications are possible in the examples of embodiments without significantly deviating from the scope of the present invention. Accordingly, it is intended that all such modifications be included within the scope of this disclosure as defined by the accompanying claims. In the claims, means plus function sentences are intended to cover the structures described herein as performing the stated function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw are not structurally equivalent in that a screw uses a cylindrical surface to fasten together pieces of wood, while a screw uses a helical surface, a nail and a screw can be equivalent structures in the context of fastening together parts of wood.

Claims (26)

PATENT CLAIMS 1. Procedure for completing a borehole, which procedure includes: introducing an oily borehole fluid into a borehole having a water-based filter cake on walls thereof, the oily borehole fluid being substantially free of unassociated surfactants, emulsifiers, wetting agents or dispersants, and comprising: an oily fluid; and a weight material; and contacting the oil-containing wellbore fluid with an oil-swellable element in the wellbore; and to allow swelling of the oil-swellable element. 2. Method according to claim 1, which further comprises: drilling the borehole with a water-based borehole fluid to form the water-based filter cake on walls thereof; 3. Method according to claim 2, which further comprises displacing the water-based borehole fluid with the oil-containing borehole fluid. 4. A method according to any one of the preceding claims, wherein the oil-swellable element is arranged on the outer circumference of a tubular component. 5. A method according to any one of the preceding claims, further comprising positioning the oil swellable element in an unlined interval of the borehole. 6. Method according to any one of the preceding claims, wherein the oil-containing borehole fluid is essentially free of an aqueous fluid. 7. Method according to any one of the preceding claims, wherein the oily fluid forms essentially all of the fluid phase of the oily borehole fluid. 8. Method according to any one of the preceding claims, wherein the oily borehole fluid further comprises an alkyl diamide having the general formula: R<1>-HN-CO-(CH2)n-CO-NH-R<2>, where n is an integer from 1 to 20, R<1>is an alkyl group having from 1 to 20 carbons, and R<2>is hydrogen or an alkyl group having from 1 to 20 carbons, where R<1>and R <2 >may or may not be identical. 9. A method according to any one of the preceding claims, wherein the oily borehole fluid has a density greater than 8.0 ppg (approx. 958.6 kg/m<3>). 10. Method according to any one of the preceding claims, where the weight material is selected from at least one of barite, calcium carbonate, dolomite, ilmenite, hematite, olivine, siderite, manganese oxide, hausmannite and strontium sulfate. 11. A method according to any one of the preceding claims, wherein the weight material has a particle size d90 of less than approximately 20 micrometres. 12. Method according to any one of the preceding claims, wherein the weight material has a particle size d90 of less than approximately 10 micrometers. 13. A method according to any one of the preceding claims, wherein the weight material has a particle size d90 of less than approximately 5 micrometers. 14. A method according to any one of the preceding claims, wherein the weight material has an organophilic coating thereon. 15. Method according to claim 14, where the organophilic coating comprises at least one selected from oleic acid, stearic acid, polybasic fatty acids, alkylbenzenesulfonic acids, alkanesulfonic acids, linear alphaolefinsulfonic acids, alkaline earth metal salts thereof, polyacrylate esters and phospholipids. 16. Method according to any one of the preceding claims, wherein the borehole fluid further comprises a silica. 17. Method according to claim 16, wherein the borehole fluid further comprises at least one of a pyrogenic silica and a precipitated silica. 18. Method according to claim 17, wherein the borehole fluid further comprises a surface-modified precipitated silica. 19. Method according to any one of the preceding claims, wherein the oily fluid further comprises an aqueous continuous phase, wherein the oily fluid forms a discontinuous phase in the aqueous continuous phase. 20. Method for activating an oil-swellable packer system, which method comprises: introducing into a borehole which has a water-based filter cake on the walls thereof, an oily borehole fluid, the oily borehole fluid comprising: an oily continuous phase, where the oily continuous phase forms substantially all of the fluid phase of the oily borehole fluid, an alkyl diamide, and an organophilic coated weight material having a particle size d90 of less than about 20 micrometers; contacting the oil-containing wellbore fluid with an oil-swellable element in the wellbore; and to allow swelling of the oil-swellable element. 21. Method according to claim 20, where the alkyl diamide has the general formula: R<1>-HN-CO-(CH2)n-CO-NH-R<2>, where n is an integer from 1 to 20, R<1 >is an alkyl group having from 1 to 20 carbons, and R<2>is hydrogen or an alkyl group having from 1 to 20 carbons, where R<1>and R<2>may or may not be identical. 22. Method according to any one of claims 20 to 21, wherein the organophilic coating comprises at least one dispersant selected from oleic acid, polybasic fatty acids, alkylbenzenesulfonic acids, alkanesulfonic acids, linear alpha olefinsulfonic acids, alkaline earth metal salts thereof, polyacrylate esters and phospholipids. 23. A method according to any one of claims 20 to 22, wherein the oily borehole fluid is free of any unassociated surfactants, dispersants or emulsifiers. 24. Method according to any one of claims 20 to 23, wherein the borehole fluid further comprises a silica. 25. Method according to claim 24, wherein the borehole fluid further comprises at least one of a pyrogenic silica and a precipitated silica. 26. Method according to claim 25, wherein the borehole fluid further comprises a surface-modified precipitated silica.