WO2015040241A1

WO2015040241A1 - Improvements in treating fluid loss from a borehole

Info

Publication number: WO2015040241A1
Application number: PCT/EP2014/070262
Authority: WO
Inventors: Zalpato Ibragimova; Steinar Wasa Tverlid
Original assignee: Statoil Petroleum As
Priority date: 2013-09-23
Filing date: 2014-09-23
Publication date: 2015-03-26

Abstract

There is described an epoxy polymer in the form of a plurality of sets of particulates and its use in methods of treating a borehole, e.g. to treat fluid loss or to reinforce, strengthen or maintain fluid pressure in the borehole. Compositions, including a lost circulation material, LCM, pill comprising the epoxy polymer are also described.

Description

Improvements in treating fluid loss from a borehole

Technical field The present invention relates to the field of well construction, and in particular to methods of treating a borehole of a well. The methods of treatment include methods to reinforce, strengthen or contain fluid pressure in the borehole, for example for hydrocarbon production from a geological formation, and associated apparatus. The invention also relates to a method of treating fluid loss from a borehole, a lost circulation material (LCM) pill for treating such fluid loss, and a liner for preventing or restricting fluid loss. The invention also relates to an epoxy polymer for use in the methods, to a fluid comprising the epoxy polymer and to a liner comprising the epoxy polymer. Background

Boreholes are drilled into the geological subsurface of the Earth in order to construct a well to recover fluids from the subsurface. In the oil and gas exploration and production industry, for example, it is sought to recover hydrocarbon fluids, for example natural oil and/or gas, through wells.

In order to drill a borehole, drilling equipment is used which includes in particular a drill string tubing with a drill bit mounted at the engaging end of the tubing for cutting into rock formations in the subsurface. As drilling progresses, the drill string tubing moves into the borehole. Drilling fluid is pumped through the interior of the drill string tubing and into the borehole near the drill bit. The drilling fluid then circulates into the annulus in the borehole between the drill string and the borehole surface, through the annulus and along the drill string tubing, and out of the top of the borehole. The drilling fluid from the borehole is then typically circulated back to the rig before being pumped back into the borehole.

The drilling fluid acts to cool and lubricate the drill bit, and helps to carry drill cuttings out of the borehole. The drilling fluid can also exert pressure against the borehole surface, and may have a composition selected according to the desired pressure in the borehole. The fluid pressure in the borehole is an important parameter in order to control the well construction process. It is typically desired for the fluid pressure to be higher than the formation pressure so as to avoid fluid influxes from the formation into the borehole and avoid kicks or blow outs. Situations of drilling fluid loss from the borehole and into the formation can be a particular problem for pressure control during drilling. This may occur where the rock formation encountered in the borehole is weak, highly fractured, or unconsolidated, such that the drilling fluid in the borehole flows out of the borehole through fractures in the borehole surface, into the rock formation, rather than passing back up to the top of the well via the annulus. Situations of seepage loss (0.5 - 5% of circulating volume), partial loss (5 - 40 % of circulating volume) or total loss (40 -100 % of circulating volume) can be encountered. Fluid loss results in a loss of the pressure in the borehole, such that sufficient fluid pressure may not be possible to maintain. There is a need to prevent drilling fluid loss from a borehole across the borehole surface into the formation. It is known to use lost circulation material (LCM) to treat drilling fluid loss. The LCM is pumped into the borehole for example by being inserted into the drilling fluid. The LCM is used to stem fractures in the rock and prevent flow of drilling fluid from the borehole into the rock formation. The LCM may comprise fibrous or plate-like material intended to bridge across pore throats or fractures in the exposed rock and seal sections of the borehole surface where losses occur. Typically, the material comprises calcium carbonate material. The LCM can have a particular size distribution according to the expected size and shape of the fractures through which the fluid is lost. The objective is to use the LCM to plug the fractures and regain pressure integrity in the borehole. It is known to provide LCM in a pill. The pill comprises a volume of pill fluid containing the LCM. The pill fluid can be inserted through the drill string and into the annulus during a pause in drilling to treat the fluid loss region of the borehole. The construction of an oil or natural gas well requires a borehole of the well to be drilled and casing installed. Installing a casing in a borehole of an oil or natural gas well is an important part of the drilling and completion process. The casing serves to strengthen the surface of the borehole and ensures that no oil or natural gas seeps out of the well as it is brought to the surface, and further ensures that other fluids or gases do not seep into the formation through the borehole. In particular, the casing prevents losses of drilling fluid circulating down the borehole through a drill pipe string and a drill bit carried on the downhole end of the drill pipe string and further circulating upward to the top of the borehole through an annulus between the drill pipe string and the wall of the borehole. The drilling fluid cools the drill bit, removes cuttings from the borehole and maintains hydrostatic pressure on pressurized subterranean formations. Usually, the surface or wall of the borehole is stabilized by running and cementing a tubular casing into the borehole, which means that drilling the borehole normally is a sequential process in which drilling the borehole and installing the casing alternate. The process is time-consuming, since the drill pipe string has to be removed from the borehole for installing of the casing.

It is known to use the tubular casing instead of the drill pipe string to direct and rotate the drill bit. In such a casing while drilling system, the casing is part of the drilling assembly and may be cemented in place where the appropriate depth is reached, and thereafter a length of the tubular casing is run through the cemented casing portion for further drilling the borehole. The casing while drilling process is unpredictable to some extent, since the casing quite easily may stick to the borehole, which makes the position of the casing shoe unpredictable, and some length of the casing may be lost with the result that the well may not reach desired depth (Nediljka Gaurina-Medimurec, "Casing Drilling Technology", Rudarsko-geolosko-naftni zbornik, Zagreb 2005, Vol. 17, pages 19 to 26).

From US 7,334,637 B2 it is known to form a temporary liner in a wellbore by extruding a fusible polymer liner material, such as polyethylene or polypropylene from an assembly supported on the drill pipe string. An extruder extrudes the liner material onto the wall of the borehole while the liner material is fed from a reservoir at the surface level of the borehole through an additional piping running through the drill string. A heat source, for example a laser device, melts the fusible liner material extruded onto the wall of the borehole to produce the liner.

The liner produced according to US 7,334,637 B2 is a temporary liner intended to be replaced later on by a conventional tubular casing to be cemented in the borehole. The system requires an additional piping through the drill pipe. The fusible liner material must be capable of being extruded onto and adhered on the wall of the borehole. Another method for stabilizing a wellbore during drilling in a sequential process is known from US patent 5,944,105. A downhole portion of the drill pipe string is provided with a plurality of nozzles through which fluid jets can be ejected. After having drilled the borehole into an unstable subterranean formation, fluid is pumped through the nozzles to enlarge the borehole by fluid jet erosion while moving the drill pipe string upwardly. After having enlarged the diameter of the borehole, a hardenable, permeable material, for example a hardenable organic resin, is ejected through the nozzles to fill the enlarged portion of the borehole. The material is caused to harden by heat or a hardening agent, and thereafter the borehole is redrilled through the hardened material. The known method does not allow a continuous lining of the formation while drilling.

From WO 2005/121 198 A1 another sequential process for in- situ stabilizing the wall of a wellbore is known. After having drilled the borehole through a weak formation, the drill string is pulled up above the weak interval to be stabilized. A resin mixture is pumped through the drill string into the borehole to displace the drilling fluid from the drill string and the annulus between the drill string and the wall of the borehole and to squeeze the resin into the weak formation. After squeezing resin into the formation, the well is shut for several hours prior to cleaning set resin out of the wellbore and resuming drilling operation to deepen the well. From US patent 6,31 1 ,773 B1 it is known to consolidate particulate solids in subterranean zones around a wellbore by causing a hardenable resin composition to flow between the particulate solids of the subterranean zone. By hardening the resin composition, the particulate solids will be consolidated into a hard, permeable pack. Similar methods for consolidating the wall of a borehole are known, for example, from EP 0 879 935 A2, US 7,216,71 1 B2, US 7,264,052 B2, WO 03/102 086 A2, EP 0 542 397 A2 or US 4,428,426. These documents disclose resin-coated particles, for example sand grains or other proppants, for treating subterranean formations, in particular subterranean fractures. SUMMARY OF INVENTION

Viewed from a first aspect the present invention provides an epoxy polymer, wherein the polymer is in the form of a plurality of sets of particulates, comprising: a first set of particulates having an average diameter of 40 to 100 microns; and a second set of particulates having an average diameter of 700 to 1000 microns. Viewed from a further aspect the present invention provides a method of making an epoxy polymer as hereinbefore defined, comprising:

mixing a first set of particulates having an average diameter of 40 to 100 microns, a second set of particulates having an average diameter of 700 to 1000 microns, and optionally a third set of particulates having an average diameter of 120 to 300 microns.

Viewed from a further aspect the present invention provides a composition comprising an epoxy polymer as hereinbefore defined and a carrier.

Viewed from a further aspect the present invention provides a lost circulation material, LCM, pill for treating fluid loss from a borehole, the borehole extending into at least one geological formation, the LCM pill comprising a carrier and an epoxy polymer.

Viewed from a further aspect the present invention provides a lining for treating a borehole extending into at least one geological formation comprising an epoxy polymer as hereinbefore defined.

Viewed from a further aspect the present invention provides a lining for lining a surface in a lost circulation region of a borehole extending into at least one geological formation, for restricting or preventing fluid flow between the borehole and the geological formation, the lining produced from the epoxy polymer as hereinbefore defined, a fluid as hereinbefore defined, or a LCM pill as hereinbefore defined.

Viewed from a further aspect the present invention provides a method of treating a borehole, the borehole extending into at least one geological formation, the method comprising:

(a) providing an epoxy polymer as hereinbefore defined, a fluid as hereinbefore defined, or a LCM pill as hereinbefore defined; and

(b) circulating the epoxy polymer, fluid or LCM pill in the borehole to deposit a polymer, the polymer melting, fusing and/or curing to produce a lining on a surface in the region to treat the borehole.

Viewed from a further aspect the present invention provides a method of treating fluid loss from a borehole, the borehole extending into at least one geological formation, the method comprising:

(a) stopping drilling;

(b) providing a lost circulation material, LCM, pill which comprises an epoxy polymer and a carrier;

(c) circulating the LCM pill in the borehole to deposit the epoxy polymer at a lost circulation region, the polymer melting, fusing and/or curing to produce a lining on a surface in said region to restrict or prevent fluid flow between the borehole and the geological formation; and

(d) re-starting drilling.

Viewed from a further aspect the present invention provides a method of treating a borehole extending into at least one geological formation, the method comprising circulating an epoxy polymer as hereinbefore defined and a carrier in the borehole adjacent to a borehole wall portion to be treated, the epoxy polymer melting, fusing and/or curing by heat from the formation, to produce a lining or liner at said wall portion to treat the borehole.

Viewed from a further aspect the present invention provides a method of reinforcing a borehole of a well comprising the steps of:

circulating a drilling fluid containing a meltable, fusible and/or curable epoxy polymer as hereinbefore defined dissolved and/or emulsified and/or dispersed therein along the surface of the borehole; and

melting, fusing and/or curing the epoxy polymer in the vicinity of the surface of the borehole.

Viewed from a further aspect the present invention provides an epoxy polymer as hereinbefore defined and carrier for use in a method as hereinbefore defined.

Viewed from a further aspect the present invention provides apparatus for performing a method as hereinbefore defined.

Viewed from a further aspect the present invention provides equipment for drilling and reinforcing a borehole of a well comprising:

a drill pipe string comprising a drill tool at its lowermost end;

a drilling fluid circulation means for circulating drilling fluid through the drill pipe string and an annulus between the drill pipe string and the borehole;

a downhole treatment device held on the drill pipe string for applying a liner of epoxy polymer material at the surface of the borehole, characterized in that the drilling fluid circulated through the annulus is a fluid system containing meltable, fusible and/or curable epoxy polymer dissolved and/or emulsified and/or dispersed therein and the treatment device is adapted to melt, fuse and/or cure the epoxy polymer contained in the drilling fluid in the vicinity of the surface of the borehole.

DEFINITIONS As used herein the term "epoxy polymer" refers to a polymer that is formed from monomers comprising at least one epoxide group and which comprises at least one epoxide group.

As used herein the term "polymer" refers to a compound which has a polydispersity index of greater than 1 . As used herein the term polymer also encompasses mixtures of different types of polymers, e.g. polymers comprising different repeat units and/or polymers having different physical properties.

As used herein the term "particulates" refers to discrete particles of any size or shape.

As used herein the term "borehole" refers to the wellbore, including the open or uncased portion of the well. It also refers to the inside diameter of the wellbore wall, and the rock face that bounds the drilled hole.

As used herein, the term "melting" refers to the process by which the epoxy polymer changes into or becomes liquid.

As used herein, the term "fusing" refers to the process by which the chains of one polymer intermix and entangle i.e. cross-link with the chains of another particulate polymer.

As used herein, the term "curing" refers to the process by which polymer chains cross-link. The process of curing creates a 3-dimensional network of polymer chains which generally increases the hardness of the polymer.

As used herein the term "carrier" refers to a transport material, such as a fluid. As used herein the term "lost circulation material" or "LCM" refers to a material intentionally introduced into a system to reduce and/or prevent the flow of a fluid, such as a drilling fluid, into a weak, fractured or otherwise compromised formation or section of a formation.

As used herein the term "LCM pill" refers to an LCM in a known volume of fluid. As used herein the term "drilling fluid" refers to a fluid, such as a mixture, suspension or emulsion which is used in drilling boreholes. An example of a drilling fluid is a water-based drilling mud.

As used herein the term "curing agent" refers to an additive which aids, facilitates or enables curing of a material as hereinbefore defined, e.g. a polymer.

As used herein the term "lining" refers to a substantially continuous material which is present on a section or region of the borehole.

As used herein the term "flocculate" refers to a process wherein smaller particles aggregate into larger particles. DESCRIPTION OF THE INVENTION

The present invention relates to methods of treating boreholes. For example, the inventors have recognised that existing LCMs tend not to seal the cracks fully, such that existing LCM techniques can have low reliability. Often, several attempts may be needed to get a satisfactory result and other times it may not be possible to regain satisfactory pressure integrity at all. In the present invention, an epoxy polymer is used. The epoxy polymer is preferably provided in particulate form, i.e. in particles. The terms particulates and particles are used herein interchangeably. The particulates may be regularly or irregularly shaped but are preferably regularly shaped. Particularly preferably the particulates are substantially spherical, e.g. spherical. The particulates may be a wide range of sizes depending, for example, on the nature of the borehole to be treated. Typically, however, the average diameter of particulates is in the range 20 to 2000 micron, more preferably 30 to 1500 micron and still more preferably 50 to 1000 micron. Particle diameters may be measured by conventional methods, for example by sieve analysis, laser diffraction, light scattering, passage through an electrically charged orifice, or settling rate.

The epoxy polymer preferably comprises a plurality of sets of particulates, e.g. 2 or 3 or 4 or more sets of particulates. By a set of particulates is meant a collection of particulates wherein at least 90 %wt and more preferably at least 95 %wt of the particulates within the collection have an average diameter of ±20%, more preferably ±10% and still more preferably ±5% of the stated average. Particularly preferably the epoxy polymer comprises a first set of particulates having a first average diameter and a second set of particulates having a second average diameter that is 7 to 15 times greater and more preferably 8 to 12 times greater than the first average diameter. Still more preferably the epoxy polymer further comprises a third set of particulates having a third average diameter that is 1.5 to 5 times greater and more preferably 2 to 4 times greater than the first average diameter. Especially preferably the epoxy polymer comprises a first set of particulates having an average diameter of 40 to 100 microns (e.g. 50 to 85 microns) and a second set of particulates having an average diameter of 700 to 1000 microns (e.g. 750 to 900 microns). Such an epoxy polymer per se forms an aspect of the present invention.

Still more preferably the epoxy polymer further comprises a third set of particulates having an average diameter of 120 to 300 microns (e.g. 150 to 250 microns). The epoxy polymer may, for example, comprise: a first set of particulates having an average diameter of 50 to 85 microns, a second set of particulates having an average diameter of 750 to 900 microns and a third set of particulates having an average diameter of 150 to 250 microns. Alternatively the epoxy polymer may, for example, comprises 0 to 40 wt% of a first set of particulates having an average diameter of around 80 microns; and 45 to 65 wt% of a second set of particulates having an average diameter of around 800 microns; and 0 to 60 wt% of a third set of particulates having an average diameter of around 180 microns. In some embodiments the particulates further comprise a metal. In such embodiments the particulates preferably comprise a metal core and an epoxy polymer coating surrounding or encompassing the core. Suitable metals for use in the metal core include, for example, iron, steel and aluminium. Preferably the average diameter of the metal core is in the range 10 to 1800 microns, more preferably 30 to 1500 microns and still more preferably 50 to 1000 microns. The metal may help to transfer heat to the epoxy polymer when in the borehole, to facilitate the melting, fusing and curing process. In other embodiments the particulates consist essentially of, e.g. consist of, epoxy polymer, i.e. individual particulates are formed entirely of epoxy polymer. In particularly preferred methods of the invention, a mixture of particulates is used, e.g. a mixture comprising particulates having a metal core and an epoxy polymer coating and particulates consisting of epoxy polymer. The weight ratio of particulates comprising a metal core to particulates consisting of epoxy polymer is preferably 50:50 to 95:5 and more preferably 65:35 to 80:20. The epoxy polymer particulates may consist of epoxy polymer only. Preferably, the epoxy polymer comprises solid particulates coated with meltable, fusible and/or curable epoxy polymer to mechanically strengthen the liner formed on the wall of the borehole. In a preferred embodiment, the solid particulates are comprised of metal, in particular steel, to provide for ductility and toughness of the liner while the epoxy polymer will bind the composite together. Any of the sets of particulates may comprise particulates comprising a metal core and an epoxy polymer coating or particulates consisting of epoxy polymer or mixtures thereof. Preferably at least one set of particulates comprises particulates having a metal core and an epoxy polymer coating surrounding the core. Preferably at least one set of particulates comprises particulates consisting of epoxy polymer. Preferably, however, the first set of particulates is particulates comprising a metal core and an epoxy polymer coating. More preferably the third set of particulates is particulates comprising a metal core and an epoxy polymer coating. Still more preferably the second set of particulates is particulates consisting of epoxy polymer.

Preferably, the particulates of the epoxy polymer have a diameter of less than 1 mm, preferably of less than 0.3 mm, for example 0.1 mm, to improve anchoring in the formation and to reduce the porosity of the liner. A diameter of less than 0.3 mm is advantageous if the epoxy polymer is coated onto particulate metal cores.

The epoxy polymer may preferably be provided in sufficient quantity and with an appropriate size distribution in order to fill the cracks, passageways, and/or openings causing fluid loss. For example, the epoxy polymer may comprise particulates differing in size, e.g. diameter, in order to penetrate into spaces such as pores cracks, passageways, and/or openings differing in size in the wall of the borehole. This can help to fill or bridge the spaces with the epoxy polymer more efficiently.

The epoxy polymer may have a non-uniform melting, fusing and/or curing temperature. Particulates having a size above a certain threshold size may have a higher or lower melting, fusing and/or curing temperature than particulates having a size below said threshold temperature.

The epoxy polymer may be selected or designed with at least one predetermined melting, fusing and/or curing temperature, e.g. a temperature based on the prevailing temperature conditions in the borehole, so that the epoxy polymer may melt, fuse and/or cure above the predetermined temperature.

As used herein, the term melting refers to the process by which the epoxy polymer changes into or becomes liquid. As used herein, the term fusing refers to the process by which the chains of one particulate epoxy polymer intermix and entangle with the chains of another particulate polymer. Typically fusing occurs after melting. As used herein, the term curing refers to the process by which epoxy polymer chains cross-link. The process of curing creates a 3-dimensional network of polymer chains which generally increases the hardness of the polymer. Typically curing occurs after melting and fusing.

The epoxy polymer may have a non-uniform fusing or curing time, at a given temperature. Particulates having a size above a certain threshold size may have a longer or shorter fusing or curing time than particulates having a size below said threshold size. The sets of particulates may comprise epoxy polymer having a fusing or curing time that is different between sets.

The epoxy polymer may melt, fuse and/or cure naturally in the prevailing temperature conditions in the borehole. Alternatively, one aspect of the invention may further comprise using a borehole tool to focus energy in the borehole in e.g., a fluid loss region to provide sufficient heat to cause the epoxy polymer to melt, fuse and cure to produce the lining on said surface of the borehole. An advantage of using a tool to provide energy is that it facilitates placement of a LCM in a specific area of the borehole.

The epoxy polymer used in the invention may be a homopolymer or a copolymer but is preferably a copolymer. The epoxy polymer may be crystalline, semi-crystalline or amorphous. Still more preferably the epoxy polymer comprises a mixture of 2 or more (e.g. 2, 3 or 4) polymers. Preferably at least one epoxy polymer (e.g. 1 polymer) is crystalline. Preferably at least one epoxy polymer (e.g. 1 polymer) is amorphous.

Preferably at least one of the epoxy polymers used in the invention has a melting point of 40 to 200 °C, more preferably 50 to 150 °C and still more preferably 70 to 100 °C, e.g. when measured by melting point apparatus. Preferably at least one of the epoxy polymers used in the method of the invention has a glass transition temperature of 40 to 200 °C, more preferably 50 to 150 °C and still more preferably 70 to 100 °C, e.g. when measured by a scanning caliometer. Preferably all of the epoxy polymers used in the method of the invention has a density of 100 to 2000 kg/m³, more preferably 300 to 1500 kg/m³ and still more preferably 1200 to 1300 kg/m³, e.g. when measured by a density meter.

The epoxy polymer used in the method of the present invention is preferably curable. The epoxy polymer may be cured, for example, by addition of a curing agent or hardener, heat and/or radiation. Particularly preferably the epoxy polymer is heat curable. Preferably the epoxy polymer further comprises a curing agent.

Representative examples of suitable epoxy polymers include epoxy polymers of the bisphenol-A type, epoxy polymers of the bisphenol-S type, epoxy polymers of the bisphenol-F type, epoxy polymers of the phenol-novolak type, epoxy polymers of the cresol-novolak type, epoxidized products of numerous dicyclopentadiene-modified phenol resins, obtained by treating dicyclopentadiene with numerous phenols, epoxidized products of 2,2',6,6'-tetra-methylbiphenol, aromatic epoxy polymers such as epoxy polymers with naphthalene basic structure and epoxy polymers with fluorene basic structure, aliphatic epoxy polymers such as neopentyl glycol diglycidyl ether and 1 ,6-hexane diol diglycidyl ether, alicyclic epoxy polymers such as 3,4- epoxycyclohexylmethyl-3,4-epoxycyclohexane carboxylate and bis(3,4- epoxycyclohexyl)adipate, and epoxy polymers with a heterocycle such as triglycidyl isocyan urate.

Specific examples of suitable epoxy polymers include diglycidylether compounds of mononuclear divalent phenols such as resorcinol and hydroquinone; diglycidylether compounds of multinuclear divalent phenols such as 4,4'-isopropylidene diphenol (bisphenol A) and 4,4'-methylene diphenol (bisphenol F); glycidylether compounds with alcohol such as butyl alcohol or higher alcohols; diglycidylether compounds of diols such as ethyleneglycol, propyleneglycol, butanediol and hexanediol; glycidylether compounds with mononuclear monovalent phenol compounds such as phenol, metacresol, paracresol and orthocresol; glycidylester compounds with monovalent carboxylic acids such as neodecanoic acid; diglycidylester compounds of aliphatic, aromatic or alicyclic dibasic acids such as maleic acid, fumaric acid, itaconic acid, succinic acid, glutaric acid, suberic acid, adipic acid, azelaic acid, sebacic acid, phthalic acid, isophthalic acid, terephthalic acid and cyclohexane dicarboxylic acid; glycidyl amine compounds such as 1 ,3-bis(N,N-diglycidyl aminomethyl) benzene and 1 ,3- bis(N,N-diglycidyl aminomethyl)cyclohexane. More preferably the epoxy polymer is selected from 4,4'-isopropylidene diphenol diglycidylether (a bisphenol A-type epoxy polymer), 4,4'-methylene diphenol diglycidylether (a bisphenol F-type epoxy polymer) or a mixture thereof. An epoxy polymer based on 4,4'-isopropylidene diphenol diglycidylether (a bisphenol A-type epoxy polymer) is particularly preferred. Adhesion happens due to molecular attraction of contacts between substances for melting and hardening in liquid form. The active component is typically Bisphenol A and the curing agents for epoxy resins may be polyamines, aminoamides and/or phenolic compounds.

As mentioned above, the epoxy polymer preferably comprises a mixture of different types of epoxy polymers. The blending of different types of epoxy polymer is often beneficial to achieve the desired melting, fusing and/or curing profile. Suitable epoxy polymers for use in the methods of the present invention are commercially available, e.g. from Akzo Nobel. For example, an epoxy polymer with the active component 4,4'- isopropylidene diphenol (bisphenol A) available from Akzo Nobel under the trade name Resicoat® may be used, for example having a real density 1 -1 .9 g/cm³, bulk density 300-1000 kg/m³, and softening point of >50°C. For example, the Resicoat® product code HNH07R available from Akzo Nobel may be used.

A further aspect of the present invention is a method of making an epoxy polymer as hereinbefore described, comprising: mixing a first set of particulates having an average diameter of 40 to 100 microns, a second set of particulates having an average diameter of 700 to 1000 microns, and optionally a third set of particulates having an average diameter of 120 to 300 microns. The mixing of the sets of particulates can be carried out by any conventional method known in the art. Optionally the method further comprises mixing a curing agent with the epoxy polymer.

A further aspect of the present invention is a composition, e.g. a fluid comprising an epoxy polymer as hereinbefore described and a carrier. Preferably the composition comprises a carrier. The epoxy polymer may be dissolved or dispersed in the carrier, but is preferably dispersed in the carrier.

According to a further aspect of the invention, there is provided a lost circulation material, LCM, pill for treating fluid loss from a borehole, the borehole extending into at least one geological formation, the LCM pill comprising an epoxy polymer and a carrier. Preferably the epoxy polymer is an epoxy polymer as hereinbefore described.

The carrier is preferably a liquid carrier. The epoxy polymer is preferably insoluble in the carrier. Thus preferably the epoxy polymer is applied to the borehole as a dispersion in the carrier. The carrier may be aqueous or non-aqueous. Preferred nonaqueous carriers include hydrocarbon or hydrocarbon mixtures, alcohols and polyols, for example mineral oil. More preferably, however, the carrier is aqueous, e.g. water. In some methods, the carrier preferably comprises drilling fluid. The carrier may be water based mud, e.g. a water based drilling mud. The fluid comprising the epoxy polymer and the carrier may further comprise a curing agent.

The carrier optionally comprises other additives known in the art for use in well treatment. Such additives may include surfactants, thickeners, diversion agents, pH buffers and catalysts.

Preferably the LCM pill is arranged to be circulated in the borehole and to deposit the polymer at a lost circulation region in use, the polymer being meltable, fusible and/or curable to produce a lining on a surface in said region for restricting or preventing fluid flow between the borehole and the geological formation.

Preferably the LCM pill comprises an epoxy polymer having a threshold melting, fusing and/or curing temperature lower than the temperature in the borehole at the lost circulation region, such that the threshold temperature of the material is exceeded when deposited at said region to activate melting, fusing, and/or curing of the epoxy polymer.

The amount of epoxy polymer to be used will vary widely depending on factors such as the nature of the borehole, the nature of the epoxy polymer and the size of the region over which e.g. fluid loss occurs. In general, the amount of epoxy polymer used will be sufficient to maintain pressure during drilling following treatment and appropriate amounts may readily be determined by those skilled in the art. Typically the concentration of epoxy polymer in the carrier is 0.5 to 10 %wt, more preferably 1 to 5 %wt and still more preferably 2 to 5 %wt, e.g. about 1 %wt or 2 %wt. Preferably about 0.5 to 10 litres (e.g. about 2 to 5 litres), more preferably 1 to 2 litres of carrier comprising epoxy polymer per m³ of the formation are employed during treatment.

The epoxy polymer material may be contained in the fluid in the pill in a concentration of up to around 5% by weight, or preferably up to 2% by weight, for example 1 % by weight or 2% by weight.

An advantage of the use of epoxy particulates in the methods of the invention is that the particles are all relatively small, i.e. even the largest particles are not particularly large. This is beneficial because when the epoxy particulates are placed into a carrier little, if any segregation, occurs. This ultimately means that an appropriate mix of epoxy particulates is delivered to all areas of the borehole during treatment.

According to a further aspect of the invention there is provided a lining for treating a borehole extending into at least one geological formation comprising an epoxy polymer as hereinbefore described. Preferably the lining is in a lost circulation region.

According to a further aspect of the invention, there is provided a lining, e.g. an epoxy polymer liner, for lining a surface in a lost circulation region of a borehole extending into at least one geological formation. Preferably the lining is for restricting or preventing fluid flow between the borehole and the geological formation, the lining produced using the LCM pill as hereinbefore described.

The lining may typically restrict or prevent passage of fluid through the lining. The lining may block in full or in part, the cracks, passageways and/or openings in the wall of the borehole. Thus, the lining may prevent fluid access into and fluid loss from the borehole through the cracks, passageways and/or openings from the borehole into the geological formation. The epoxy polymer may have a threshold melting, fusing and/or curing temperature lower than the temperature in the borehole at the loss region, such that the threshold temperature is exceeded in order to activate melting, fusing, and/or curing of the polymer to produce the lining. The lining, and particulates from which it is produced, may penetrate into and block in full or in part, the cracks, passageways and/or openings in the wall of the borehole. Thus, the lining in particular where the epoxy polymer particulates have metal cores, may improve strength, reinforcement, support. It may also reduce any fluid loss from the borehole through the cracks, passageways and/or openings from the borehole into the geological formation.

Polymer materials that can be suitable for forming the liner of the borehole are known in the art; reference is made to the patent documents mentioned above. Further suitable polymer material is known from EP 1 664 481 B1 , WO 2005/121 500 A1 or WO 02/14 453 A1.

A further aspect of the invention is a lining for lining a surface in a lost circulation region of a borehole extending into at least one geological formation, for restricting or preventing fluid flow between the borehole and the geological formation, the lining produced from the epoxy polymer as hereinbefore described, a fluid as hereinbefore described, or a LCM pill as hereinbefore described.

According to a further aspect of the present invention, there is provided a method of treating a borehole, the borehole extending into at least one geological formation, the method comprising:

(a) providing an epoxy polymer as hereinbefore described, a fluid as hereinbefore described, or a LCM pill as hereinbefore described; and

In some preferred methods the epoxy polymer, fluid or LCM pill deposit the epoxy polymer at a lost circulation area. Preferably the epoxy polymer melts, fuses and/or cures to produce a lining on a surface of the area. Preferably the lining restricts or prevents fluid flow between the borehole and the geological formation.

In other preferred methods the epoxy polymer, fluid or LCM pill are circulated in the borehole adjacent to a borehole wall portion to be heated. Preferably the epoxy polymer melts, fuses and/or cures by the heat from the formation. Preferably the melting, fusing and/or curing produces a lining or liner at the wall portion to treat the borehole.

Preferred epoxy polymers for use in the methods of the invention are those described as preferred in the section on epoxy polymers above.

A still further aspect of the present invention provides a method of treating fluid loss from a borehole, the borehole extending into at least one geological formation, the method comprising:

(a) stopping drilling;

(d) re-starting drilling.

Preferably the epoxy polymer used in the above-described method is an epoxy polymer as hereinbefore described. Particularly preferred epoxy polymers are those described as preferred in the section on epoxy polymers above.

The epoxy polymer may be circulated in the borehole to deposit the epoxy polymer on a surface of the wall of the borehole, or may be deposited on surfaces of cracks, passageways and/or openings which extend in the wall of the borehole, between the borehole and the geological formation. Preferably the produced lining restricts or prevents passage of fluid through the lining. Preferably the lining blocks pores, cracks, passageways and/or openings in a wall of the borehole to restrict or prevent fluid access into the geological formation.

The epoxy polymer may preferably be provided in sufficient quantity and with an appropriate size distribution in order for the lining to fill the cracks, passageways, and/or openings causing fluid loss. For example, the epoxy polymer may comprise particulates differing in size, e.g. diameter, in order to penetrate into spaces such as pores cracks, passageways, and/or openings differing in size in the wall of the borehole. This can help to fill or bridge the spaces with the epoxy polymer more efficiently. The use of an epoxy polymer in a LCM pill, rather than in the drilling fluid, is particularly effective in achieving sealing because the epoxy polymer penetrates into the cracks and openings to a much greater extent. When used in a drilling fluid, the epoxy polymer primarily serves to stregthen the lining formed on the borehole wall.

The method may further comprise identifying the lost circulation region by observing a loss of circulating fluid in a drilling process. Moreover, the method may further comprise circulating drilling fluid in the borehole and drilling a further section of the borehole after the lining is produced.

In the method, the epoxy polymer may melt, fuse and/or cure naturally in the prevailing temperature conditions in the borehole by exceeding the predetermined temperature naturally in the prevailing temperature conditions in the borehole. Alternatively, one aspect of the invention may further comprise using a borehole tool to focus energy in the borehole in the fluid loss region to provide sufficient heat to cause the epoxy polymer to melt, fuse and cure to produce the lining on said surface of the borehole. An advantage of using a tool to provide energy is that it facilitates placement of a LCM in a specific area of the borehole. The method may further comprise delivering a curing agent or hardener into the borehole at the surface of the borehole to cause the deposited epoxy polymer to cure. Preferably the curing agent is delivered in a carrier and still more preferably in a carrier as described above in relation to the epoxy polymer. Conventional curing agents, which are well known, in the art may be used. More preferably, however, curing is achieved by heating.

The method may further comprise delivering a salt solution into the borehole at the surface of borehole to cause the deposited epoxy polymer to flocculate. As used herein, the term flocculate refers to the formation of aggregates of epoxy polymer particulates by particulates clumping or grouping together. The average diameter of a flocculated particulate epoxy polymer is significantly greater than the average diameter of the particulates forming the flocculate, which facilitates the bridging of larger cracks and pores without compromising the ability of particulates to still enter smaller spaces. Preferably the salt present in the salt solution comprises an alkali metal or an alkaline earth metal and more preferably an alkali metal. Particularly preferably the salt comprises a cation selected from Na⁺, K⁺, Ca⁺⁺ or Cs⁺ and especially preferably Na⁺. The anion may be any counter ion that renders the salt water soluble. Representative examples of suitable anions include halides, formates, nitrates, carbonates and sulfates. Particularly preferably the anion is a halide and especially chloride. Preferably the concentration of the salt solution is in the range 1 to 25 %wt and more preferably 10 to 15 %wt.

Treatment with the epoxy polymer, and optionally curing agent and/or salt solution, in the method of the present invention is conducted by injecting the epoxy polymer, curing agent or salt solution respectively through a borehole into the formation, generally employing pressures sufficient to penetrate the formation. Preferably the epoxy polymer, salt solution and curing agent are injected separately. Preferably the epoxy polymer is injected first. If used, preferably the salt solution is injected second. If used, preferably the curing agent is injected third.

Treatment times or period of shut-in will depend on a number of factors including the nature of the borehole, the extent and degree of epoxy polymer liner required, the nature and concentration of the epoxy polymer employed, the depth of perforations, etc. Typical shut-in times may be determined by those skilled in the art and will generally range from 0.5 to 10 hours and preferably from 0.1 to 5 hours. In some methods no shut in time is required.

The method may further comprise one or more steps of:

- circulating drilling fluid through the borehole;

- drilling the borehole;

- identifying the lost circulation region by observing a loss of the circulating drilling fluid when drilling;

- stopping drilling; and

removing remaining drilling fluid from the borehole after drilling has stopped. The method may further comprise steps of recommencing circulation of drilling fluid and drilling of the borehole after the lining is produced. The method of the invention may also be repeated a plurality of times during the drilling of a borehole.

According to a further aspect of the invention, there is provided a method of treating a borehole extending into at least one geological formation, the method comprising circulating an epoxy polymer as hereinbefore described and a carrier in the borehole adjacent to a borehole wall portion to be treated, the polymer melting, fusing and/or curing by heat from the formation, to produce a lining or liner at said wall portion to treat the borehole. Particularly preferred epoxy polymers are those described as preferred in the section on epoxy polymers above.

Preferably the epoxy polymer is designed with at least one melting, fusing and/or curing temperature and the deposited epoxy polymer melts, fuses and/or cures by exceeding the predetermined temperature naturally by the heat from the formation. Thus alternatively viewed, there is provided a method of treating a borehole extending into at least one geological formation, the method comprising circulating a polymer and a carrier in the borehole adjacent to a borehole wall portion to be treated, the polymer melting, fusing and/or curing passively to produce a lining or liner at said wall portion to treat the borehole.

The heat from the formation may thus be sufficient to produce the melting, fusing and/or curing of the epoxy polymer. The heat may be received in the borehole, by the particulates, through the borehole wall. The epoxy polymer may thus be designed with melting, fusing and/or curing temperatures which are exceeded in the borehole at the borehole wall portion by heat from the formation. The melting, fusing and/or curing temperatures may be determined with reference to the temperatures expected to occur naturally in the borehole from formation heat.

The formation temperature at depth may generally be naturally higher than at the surface, as may be determined by the geothermal gradient of the Earth. The carrier and epoxy polymer delivered from the surface may typically have a temperature below the melting, fusing and/or curing temperature of the epoxy polymer, for example typical surface temperature, at least initially, before it is circulated in the borehole adjacent to the region to be treated. When the carrier and epoxy polymer is circulated in the wellbore at sufficient depth, the natural temperature conditions may cause the carrier and epoxy polymer to heat up and the epoxy polymer temperature to increase to above the melting, fusing and/or curing temperature necessary for the melting, fusing, and/or curing of the epoxy polymer to take place to produce the lining. The epoxy polymer may thus be heated passively, simply by its presence in the borehole at the region to be treated, or mere exposure to heat from the formation. Preferably, no heater or other energy concentration device is required to be used to produce melting, fusing and/or curing of the epoxy polymer or the lining at the region to be treated. Typically, no heater or other energy concentration device is required in the borehole, whether at said region or otherwise, to perform the method. Heat from the formation alone may thus be sufficient.

Preferably the circulating step is performed to deposit the epoxy polymer on a surface of the wall of the borehole, or, on surfaces of cracks, passageways and/or openings which extend into the wall of the borehole between the borehole and the geological formation. Preferably the lining and/or epoxy polymer penetrates into pores, cracks, passageways and/or openings in a wall of the borehole to strengthen the geological formation.

The method may be performed during drilling, wherein the carrier comprises drilling fluid. The treating may comprise strengthening, supporting and/or reinforcing the borehole and/or providing pressure integrity and/or containing fluid in the borehole.

Since the epoxy polymer material for producing the liner of the borehole is preferably contained in the drilling fluid (mud e.g. water based mud) anyway needed for drilling the borehole, no additional piping along the borehole or no downhole reservoir for epoxy polymer material is needed.

Due to the downhole pressure of the drilling fluid, some of the drilling fluid including polymer material may be pressed into the pores of the formation and anchors the liner to the wall of the borehole. The polymer material may be dissolved or emulsified within the drilling fluid, but in particular is in a particulate form, for example in the form of powder-like particles or granules, which adhere to each other when being melted, fused and/or cured. The amount of polymer to be used will vary widely depending on factors such as the nature of the borehole, the nature of the polymer and the size of the region to be treated. In general, the amount of polymer used will be sufficient to maintain pressure during drilling following treatment and appropriate amounts may readily be determined by those skilled in the art. Typically the concentration of polymer in the carrier is 0.5 to 10 %wt, more preferably 1 to 5 %wt and still more preferably 2 to 5 %wt, e.g. about 1 %wt or 2 %wt. Preferably about 0.5 to 10 litres (e.g. about 2 to 5 litres), more preferably 1 to 2 litres of carrier comprising polymer per m³ of the formation are employed during treatment to produce the lining. A curing agent or hardener may be provided into the borehole to cause the deposited epoxy polymer to cure. Preferably the curing agent is delivered in a carrier, for example the drilling fluid. Conventional curing agents, which are well known in the art may be used. Curing may be achieved by heating. The drilling fluid may be an aqueous carrier such as a water based drilling mud. Other additives such as surfactants, thickeners, diversion agents, pH buffers and catalysts may be included in the drilling fluid.

The method may further comprise delivering a salt solution into the borehole at the surface of borehole to cause the deposited epoxy polymer to flocculate. As used herein, the term flocculate refers to the formation of aggregates of epoxy polymer particulates by particulates clumping or grouping together. The average diameter of a flocculated particulate epoxy polymer is significantly greater than the average diameter of the particulates forming the flocculate, which facilitates the bridging of larger cracks and pores without comprising the ability of particulates to still enter smaller spaces. Preferably the salt present in the salt solution comprises an alkali metal or an alkaline earth metal and more preferably an alkali metal. Particularly preferably the salt comprises a cation selected from Na⁺, K⁺, Ca⁺⁺ or Cs⁺ and especially preferably Na⁺. The anion may be any counter ion that renders the salt water soluble. Representative examples of suitable anions include halides, formates, nitrates, carbonates and sulfates. Particularly preferably the anion is a halide and especially chloride. Preferably the concentration of the salt solution is in the range 1 to 25 %wt and more preferably 10 to 15 %wt.

Treatment with the epoxy polymer, and optionally curing agent and/or salt solution, in the method of the present invention is conducted by injecting the epoxy polymer, curing agent or salt solution respectively through a borehole into the formation, generally employing pressures sufficient to penetrate the formation. Preferably the epoxy polymer, salt solution and curing agent are injected separately. Preferably the epoxy polymer is injected first. If used, preferably the salt solution is injected second. If used, preferably the curing agent is injected third. Treatment times or period of shut-in will depend on a number of factors including the nature of the borehole, the extent and degree of epoxy polymer liner required, the nature and concentration of the epoxy polymer employed, the depth of perforations, etc. Typical shut-in times may be determined by those skilled in the art and will generally range from 0.5 to 10 hours and preferably from 0.1 to 5 hours. In some methods no shut in time is required.

The liner may be continuously produced on the wall of the borehole. The thickness can be controlled by controlling the concentration of the epoxy polymer material within the drilling fluid, the axial of the speed of the drill pipe string and the circulating velocity of the drilling fluid along the wall of the borehole. Depending on the porosity of the formation, the epoxy polymer material may migrate into the formation to seal and/or improve anchoring of the liner at the formation. Basically, it is sufficient to compact the epoxy polymer material contained in the drilling fluid starting from the average concentration of the epoxy polymer material in the drilling fluid,

A treatment device may be adapted and used to specifically raise the concentration of the epoxy polymer material in the vicinity of the wall e.g. in a limited space therein. Additional pressure may be exerted onto epoxy polymer material by magnetic forces produced by at least one magnet of the treatment device. In this case the epoxy polymer material preferably comprises solid particulates of a diamagnetic material, for example copper, which is repelled within the magnetic field produced by the treatment device onto the surface of the borehole. The magnetic repellent force pushes the particulates towards and into the formation where the particulates concentrate for forming the liner.

If the drilling fluid contains epoxy polymer material comprising solid particulates having a particle density higher than the density of the drilling fluid including particulate material other than the particulate epoxy polymer material, the concentration of the epoxy polymer material in the vicinity of the wall of the borehole can be raised by a centrifugal separator coaxially arranged with the drill pipe string. The centrifugal separator centrifugates the higher density epoxy polymer material towards the wall of the borehole while the drilling fluid flows axially along the annulus. The centrifuge induces a whirl in the drilling fluid around the drill string a certain distance before and in the limited space curing position. Preferably, the solid particulates of the epoxy polymer material have a density which is higher than the density of formation particulates contained in the drilling fluid and also higher than the density of the rest of the drilling fluid. Due to the centrifugal action the particulates with the highest density, e.g. the particulate epoxy polymer material will be separated onto the wall of the borehole to produce the layer while lighter components of the drilling fluid will remain in a radially inner portion of the annulus.

In a preferred embodiment, the centrifugal separator is in the form of a helical vane coaxially stationary surrounding the drill pipe string. In another embodiment, the centrifugal separator can be in the form of a motor- driven impeller coaxially rotating with respect to the drill pipe string. The impeller has a fan wheel which produces the whirl in the drilling fluid to centrifugate the particulates onto the wall of the borehole. An object of a further aspect of the invention is to provide a technique which allows reinforcement of a borehole of a well, in particular a well of petroleum and/or natural gas.

A further aspect of the present invention is therefore a method of reinforcing a borehole of a well comprising the steps of: circulating a drilling fluid containing a meltable, fusible and/or curable epoxy polymer as hereinbefore described dissolved and/or emulsified and/or dispersed therein along the surface of the borehole; and melting, fusing and/or curing the epoxy polymer in the vicinity of the surface of the borehole. Particularly preferred epoxy polymers are those described as preferred in the section on epoxy polymers above.

The method is preferably performed while drilling the borehole. The melting, fusing and/or curing step may be performed by concentrating energy melting, fusing and/or curing the epoxy polymer in a limited space in the vicinity of the surface. The concentrating step is preferably performed while drilling of the borehole (1 ) is continued. The concentrating step is performed to produce a lining or liner at the surface of the borehole. The liner advantageously acts to provide support and strength to the borehole wall. The amount of the epoxy polymer to be used will vary widely. The concentration of the epoxy polymer in the drilling fluid may be 0.5 to 10 %wt, for example 1 to 5 %wt, typically 2 to 5 %wt, e.g. about 1 %wt or 2 %wt. A curing agent or hardener may be provided into the borehole to cause the deposited epoxy polymer to cure. Preferably the curing agent is delivered in a carrier, for example the drilling fluid. Conventional curing agents, which are well known in the art may be used. Curing may be achieved by heating. The drilling fluid may be an aqueous carrier such as a water based drilling mud. Other additives such as surfactants, thickeners, diversion agents, pH buffers and catalysts may be included in the drilling fluid.

The method may further comprise delivering a salt solution into the borehole at the surface of borehole to cause the deposited polymer to flocculate. As used herein, the term flocculate refers to the formation of aggregates of epoxy polymer by particulates clumping or grouping together. The average diameter of a flocculated epoxy polymer is significantly greater than the average diameter of the particulates forming the flocculate, which facilitates the bridging of larger cracks and pores without comprising the ability of particulates to still enter smaller spaces. Preferably the salt present in the salt solution comprises an alkali metal or an alkaline earth metal and more preferably an alkali metal. Particularly preferably the salt comprises a cation selected from Na⁺, K⁺, Ca⁺⁺ or Cs⁺ and especially preferably Na⁺. The anion may be any counter ion that renders the salt water soluble. Representative examples of suitable anions include halides, formates, nitrates, carbonates and sulfates. Particularly preferably the anion is a halide and especially chloride. Preferably the concentration of the salt solution is in the range 1 to 25 %wt and more preferably 10 to 15 %wt.

Treatment with the epoxy polymer, and optionally curing agent and/or salt solution, in the method of the present invention is conducted by injecting the epoxy polymer, curing agent or salt solution respectively through a borehole into the formation, generally employing pressures sufficient to penetrate the formation. Preferably the epoxy polymer, salt solution and curing agent are injected separately. Preferably the epoxy polymer is injected first. If used, preferably the salt solution is injected second. If used, preferably the curing agent is injected third. The epoxy polymer comprises particulates. The particulate epoxy polymer may consist of epoxy polymer only. Preferably, the epoxy polymer comprises solid particulates coated with meltable, fusible and/or curable epoxy polymer to mechanically strengthen the liner formed on the wall of the borehole. In a preferred embodiment, the solid particulates are comprised of metal, in particular steel, to provide for ductility and toughness of the liner while the epoxy polymer will bind the composite together.

Preferably, the particulates of the epoxy polymer have a diameter of less than 1 mm, preferably of less than 0.3 mm, for example 0.1 mm, to improve anchoring in the formation and to reduce the porosity of the liner. A diameter of less than 0.3 mm is advantageous if the epoxy polymer is coated onto particulate metal cores. The epoxy polymer may be selected or designed with at least one predetermined melting, fusing and/or curing temperature, so that the epoxy polymer may melt, fuse and/or cure above the predetermined temperature.

The liner may be continuously produced on the wall of the borehole. The thickness can be controlled by controlling the concentration of the epoxy polymer within the drilling fluid, the axial of the speed of the drill pipe string and the circulating velocity of the drilling fluid along the wall of the borehole. Depending on the porosity of the formation, the epoxy polymer may migrate into the formation to seal and/or improve anchoring of the liner at the formation. Basically, it is sufficient to compact the epoxy polymer contained in the drilling fluid starting from the average concentration of the polymer in the drilling fluid, but preferably the treatment device is adapted to specifically raise the concentration of the epoxy polymer in the vicinity of the wall and in particular in the vicinity of the limited space, in which the treatment device concentrates energy for curing, fusing and/or curing the epoxy polymer.

In a preferred embodiment, additional pressure is exerted onto the particulate epoxy polymer by magnetic forces produced by at least one magnet of the treatment device. The epoxy polymer comprises solid particulates of a diamagnetic material, for example copper, which is repelled within the magnetic field produced by the treatment device onto the surface of the borehole. The magnetic repellent force pushes the particulates towards and into the formation where the particulates concentrate for forming the liner. If the drilling fluid contains epoxy polymer material comprising solid particulates having a particle density higher than the density of the drilling fluid including particulate material other than the particulate epoxy polymer material, the concentration of the epoxy polymer material in the vicinity of the wall of the borehole can be raised by a centrifugal separator coaxially arranged with the drill pipe string. The centrifugal separator centrifugates the higher density epoxy polymer material towards the wall of the borehole while the drilling fluid flows axially along the annulus. The centrifuge induces a whirl in the drilling fluid around the drill string a certain distance before and in the limited space curing position. Preferably, the solid particulates of the epoxy polymer material have a density which is higher than the density of formation particulates contained in the drilling fluid and also higher than the density of the rest of the drilling fluid. Due to the centrifugal action the particulates with the highest density, e.g. the particulate epoxy polymer material will be separated onto the wall of the borehole to produce the layer while lighter components of the drilling fluid will remain in a radially inner portion of the annulus.

A further aspect of the present invention provides equipment for drilling and reinforcing a borehole of a well comprising:

a drill pipe string comprising a drill tool at its lowermost end;

a downhole treatment device held on the drill pipe string for applying a liner of epoxy polymer material at the surface of the borehole, characterized in that the drilling fluid circulated through the annulus is a fluid system containing meltable, fusible and/or curable epoxy polymer dissolved and/or emulsified and/or dispersed therein and the treatment device is adapted to melt, fuse and/or cure the epoxy polymer contained in the drilling fluid in the vicinity of the surface of the borehole. Preferably the epoxy polymer is as hereinbefore described. Particularly preferred epoxy polymers are those described as preferred in the section on epoxy polymers above.

Since the epoxy polymer for producing the liner of the borehole is contained in the drilling fluid (mud e.g. water based mud) anyway needed for drilling the borehole, no additional piping along the borehole or no downhole reservoir for polymer material is needed. The treatment device is positioned at the drill pipe string downhole in the vicinity of the drill tool, which may be in the form of a simple drill bit, but also may include a roamer or a downhole assembly including a downhole drill motor. Due to the downhole pressure of the drilling fluid, some of the drilling fluid including epoxy polymer may be pressed into the pores of the formation and anchors the liner to the wall of the borehole. The epoxy polymer may be dissolved or emulsified within the drilling fluid, but in particular is in a particulate form, for example in the form of powder-like particles or granules, which adhere to each other when being melted, fused and/or cured by energy from the treatment device. Preferably the epoxy polymer is as hereinbefore described. Particularly preferred epoxy polymers are those described as preferred in the section on epoxy polymers above.

In a preferred embodiment, the treatment device comprises an energy radiating device which produces at least two distinct energy beams which are directed from different positions to a common spot in the limited space in the vicinity of the surface of the borehole where the energy beams intersect and focus the energy within said limited space. Thus preferably the treatment device is an energy radiating device to concentrate energy for melting, fusing and/or curing the epoxy polymer in a limited space in the vicinity of the surface, the device producing at least two energy beams which intersect in the limited space in the vicinity of the surface of the borehole. Still more preferably the energy radiating device comprises at least two laser light devices or microwave devices or induction heating devices or ultrasound devices providing intersecting energy beams. While the energy of a single energy beam does not suffice to fuse or cure the epoxy polymer in the bulk of the drilling fluid, the focused energy of the plurality of the energy beams is sufficient for producing the liner.

In one embodiment, the step of concentrating energy for melting, fusing and/or curing the epoxy polymer in the vicinity of the surface of the borehole comprises the step of simultaneously directing at least two energy beams to the limited space such that the energy beams intersect within a limited space. In another embodiment, the energy source, e.g. an energy output port of the treatment device is positioned near the surface of the borehole and directs its energy beams directly onto the surface.

Alternatively the treatment device has at least one energy output port positioned in the vicinity of the surface of the borehole and preferably an associated energy shielding and/or an energy reflector which concentrates the energy to the limited space in which the liner is to be produced and protects the bulk of the drilling fluid outside said limited space from radiated energy. The energy source of the treatment device can be of any type that allows directed radiation of energy onto the surface of the borehole. Preferably, the energy source is a laser device or an induction heating device or a microwave radiating device or a supersonic energy radiating device. The type of the energy source may be chosen depending on the epoxy polymer and/or in case of particulate material comprising a core, e.g. a metal core, in dependence of the material of the core, as it known in the art.

If the drilling fluid contains particulate epoxy polymer comprising solid particles having a particle density higher than the density of the drilling fluid including particulate material other than the particulate epoxy polymer, the concentration of the epoxy polymer in the vicinity of the wall of the borehole can be raised by a centrifugal separator coaxially arranged with the drill pipe string. The centrifugal separator centrifugates the higher density particulate polymer towards the wall of the borehole while the drilling fluid flows axially along the annulus. The centrifugal induces a whirl in the drilling fluid around the drill string a certain distance before and in the limited space curing position. Preferably, the solid particles of the particulate polymer have a density which is higher than the density of formation particles contained in the drilling fluid and also higher than the density of the rest of the drilling fluid. Due to the centrifugal action the particles with the highest density, e.g. the particulate polymer will be separated onto the wall of the borehole to produce the layer while lighter components of the drilling fluid will remain in a radially inner portion of the annulus.

In a preferred embodiment, the centrifugal separator is in the form of a helical vane coaxially stationary surrounding the drill pipe string. In another embodiment, the centrifugal separator can be in the form of a motor- driven impeller coaxially rotating with respect to the drill pipe string. The impeller has a fan wheel which produces the whirl in the drilling fluid to centrifugate the particulates onto the wall of the borehole. The idea of concentrating particulate polymer at the wall of the borehole by means of centrifugating the drilling fluid in the annulus can also be carried out with a treatment device not being adapted to concentrate the energy in a limited space near the wall of the borehole. The aspect of the centrifugal separator thus can be used with an equipment the treatment device of which heats the drilling fluid within the total radial depth of the annulus. According to a further aspect there is provided apparatus for performing a method as hereinbefore described. The apparatus may comprise further features as defined in relation any other aspect. The equipment described herein may be used to perform the method described herein. Each of the aspects described above may have further features as defined in relation to any other aspect. Any of the above aspects may have further features in any combination as described herein whether in the drawings, description and/or claims.

Description and drawings

There will now be described, by way of example only, embodiments of the invention with reference to the accompanying drawings, in which:

Figure 1 is a schematic section through a borehole of a well of a borehole extending into the earth during the delivery of a drilling fluid and e.g. repairing a fluid loss region in a well whilst drilling of the borehole is suspended, according to an embodiment of the invention;

Figure 2 is a close-up representation of a surface of the borehole in the fluid loss region, and the deposition of polymer in the pill of Figure 1 upon that surface;

Figure 3 is a cross-section of a solid particle coated with polymer;

Figure 4 is a further close-up representation of a structure of the surface of the borehole and the penetration of polymer into the structure, according to another embodiment;

Figure 5 is an image of a test device for providing an artificial converging crack for testing the suitability of lost circulation material comprising polymer; Figure 6 is an end on image of the test device of Figure 5 after treatment, including melting and curing of polymer, in a first test;

Figure 7 is an image of facing surfaces of the test device of Figure 5 when separated into halves along the crack after treatment in the first test of Figure 6;

Figure 8 is an end on image of the test device of Figure 5 after treatment, including melting and curing of polymer, in a second test; Figure 9 is an image of facing surfaces of the test device of Figure 5 when separated into halves along the crack after treatment in the second test of Figure 8;

Figure 10 is an end on image of the test device of Figure 5 after treatment, including melting and curing of polymer, in a third test;

Figure 1 1 is an image of facing surfaces of the test device of Figure 5 when separated into halves along the crack after treatment in the third test of Figure 10;

Figure 12 is an end on image of the test device of Figure 5 after treatment, including melting and curing of polymer, in a fourth test;

Figure 13 is an image of facing surfaces of the test device of Figure 5 when separated into halves along the crack after treatment in the fourth test of Figure 12; Figure 14 is a graph showing filtrate versus time results from the tests of Figures 7 to 13;

Figure 15 is a histogram of filtration times for the different tests of Figures 7 to 13; Figure 16 is an image of epoxy polymer in water-based mud with flocculation due to KCI brine; and

Figure 17 is an image of epoxy polymer in water-based mud with flocculation due to NaCI brine. Figure 18 is a schematic section through a borehole of a well with a first embodiment of an equipment for drilling and reinforcing the borehole;

Figure 19 is a section through the borehole of the well with another embodiment of the equipment for drilling and reinforcing the borehole;

Figure 20 is a cross-section of a particle contained in the drilling fluid used with the equipment while drilling; Figure 21 is a sketch of an improvement of the equipment to be used with the equipment of Figs. 18 or 19; and

Figure 22 and Figure 23 are sketches of alternatives to the improvement of Figure 21 . With reference firstly to Figure 1 , a lost circulation material (LCM) pill, which comprises a fluid carrier 2 and an epoxy polymer, is being circulated into a borehole 3 using circulation apparatus 1 . The borehole 3 extends from the seabed or land surface into the geological subsurface 4. The circulation apparatus 1 comprises, in this example, drill string tubing 5 disposed in the borehole 3, fluid conveying means and a container 7, for example provided on a platform 8, for containing the fluid 2. The fluid conveying means has first tubing 6a used to convey the fluid from the container 7 into the borehole 3 through the tubing 5, and second tubing 6b used to convey fluid out from the borehole 3, more specifically out from the annulus 9 between the borehole wall and the outer surface of the drill tubing, back to the container 7, to provide a continuous circulation of fluid into and out of the borehole as shown generally by the flow arrows 10. Pump equipment or the like may be used to pump the fluid into and or out of the borehole.

As shown in Figure 1 , the LCM pill is pumped into the borehole, and reaches a lost circulation region 12 along the borehole. The lost circulation region 12 is associated with fluid loss from the borehole into the surrounding geological formation. Such a region 12 is typically detected during drilling of the borehole (e.g. by sudden loss of annulus pressure indicating fluid loss as drilling progresses). When fluid loss has been detected, the LCM pill may then be pumped into the borehole. Before doing so, drilling, that is the movement downwards and rotation of drill string tubing 5 and drill bit 13 at the lower end of the tubing 5, is stopped, and the drilling fluid is removed from the well. The LCM pill is then pumped into the borehole, as seen in Figure 1 , conveniently via the drill string tubing 5. Thus, the LCM pill is circulated separately from the drilling fluid that is used during drilling, and may be provided as a separate pre-prepared volume of fluid, ready to use in the borehole when needed. As it is pumped in, the LCM pill circulates in the borehole, such that the carrier fluid 2 containing the epoxy polymer is present adjacent to the surface of the borehole in the fluid loss region, and penetrates into the pores, cracks, passageways or other openings in the wall of the borehole in the fluid loss region, which are in fluid communication between the borehole and the formation and thus responsible for the circulation loss from the borehole into the formation. This is seen more clearly in Figure 2. The epoxy polymer 16 is carried in the carrier fluid and is deposited at the lost circulation region, on surfaces of the borehole wall and of the pores, cracks, passageways and openings in the wall. By virtue of the pressure differential between the fluid in the borehole and the formation, the fluid will tend to flow toward the lost circulation region and penetrate into the pores, cracks etc. in the wall. The wall acts as a filter on the fluid 2, such that much of the fluid penetrates into the wall and passes through the pores, cracks etc, whilst the epoxy polymer is left behind on the surfaces.

The borehole wall in this region typically comprises formation rock 15 which may be weak, unconsolidated or porous, or highly fractured. At the lost circulation region, the fluid 2 then flows through cracks and pores in the rock, whilst the epoxy polymer 16 carried in the fluid is deposited and adheres onto the physical material of the rock itself.

The deposited epoxy polymer then melts, fuses together, and cures. The melting, fusing and curing process produces a fluid resistant epoxy polymer lining on the surface of the borehole. The lining does not allow fluid to penetrate through the lining (i.e. is fluid resistant), and prevents or at least restricts fluid access from the wellbore into the pores, cracks, passageways and openings. Ideally, the epoxy polymer lining that is produced completely seals the lost circulation region and passageways etc. all around the circumference of the hole. When circulating the LCM pill, it can be noted that some of the LCM pill may return back up through the annulus, as seen by arrows 17, out of the top of the borehole before being pumped back into the borehole. In other words, the epoxy polymer present in the LCM pill which is not used to prevent fluid loss typically circulates to the surface of the borehole and does deposit elsewhere in the production system. The returned fluid of the LCM pill may be recirculated until the full volume of the LCM pill is substantially used up (by penetrating into the formation and depositing epoxy polymer). When the lining is formed, drilling is re-started with drilling fluid circulating into and out of the borehole in the normal way. This may involve pumping out any remaining fluid of the LCM pill before reinserting the drilling fluid. The drilling fluid is contained in the borehole by the lining, without any significant loss into the formation at the previously determined lost circulation region. Loss of drilling fluid into the formation is prevented at least sufficiently to continue drilling, due to the presence of the epoxy polymer lining. Drilling can therefore continue successfully, with good pressure control, downward past the lost circulation region 12.

When the epoxy polymer is deposited at the lost circulation region, in particular when on formation rock, heat from the rock formation is transferred to the epoxy polymer directly. The heat from the rock formation is sufficient to cause melting, fusing and/or curing of the epoxy polymer. Thus, the epoxy polymer has a predetermined melting, fusing and/or curing temperature that is exceeded such that it melts, fuses and/or cures when in contact with the formation. Hence, no heating devices are required to be used to initiate the melting and curing process.

In other variants, an energy tool, for example a heater, is used to focus energy in the annulus of the borehole at the fluid loss region in order to facilitate heating of the epoxy polymer and to subject the epoxy polymer to a temperature sufficient (i.e. above the predetermined temperature(s)) to produce the melting and curing of the polymer.

It will be appreciated that various epoxy polymers can be used in the technique described above, provided they are able to melt, fuse and/or cure so as to produce the lining on the surface in the loss region of the borehole. Epoxy polymers are preferred because the epoxy polymers have good curing, adhesion, strength, penetration, and temperature properties. Suitable epoxy polymers are known and available commercially, for example from Akzo Nobel, with desired melting, fusing and/or curing temperatures for usage in the borehole. The LCM pill is preferably prepared in advance of it being pumped into the borehole, as a pre-prepared volume of fluid carrier containing the particulate epoxy polymer. The particulate epoxy polymer is preferably suspended and dispersed in the carrier fluid. In particular variants, some or all of the epoxy polymer could be dissolved or emulsified in the carrier fluid.

Figure 1 also illustrates a method of treating a borehole to reinforce, strengthen or contain fluid pressure in the borehole. Referring again to Figure 1 , the drilling fluid 2 is pumped into the borehole, and reaches borehole wall region to be treated 12. The region to be treated 12 requires reinforcement, strengthening, pressure containment, and/or support. Such a region 12 is typically detected during drilling of the borehole.

As it is pumped in, drilling fluid circulates in the borehole, such that the fluid 2 containing the epoxy polymer is present adjacent to the surface of the borehole in the region to be treated, and penetrates into the pores, cracks, passageways or other openings in the wall of the borehole at the region to be treated 12, between the borehole and the formation. This is seen more clearly in Figure 2. The epoxy polymer 16 is carried in the drilling fluid and is deposited at the region 12, on surfaces of the borehole wall and of the pores, cracks, passageways and openings in the wall.

To protect the wall 15 of the borehole 1 and to apply a liner 17 to the wall 15 for reinforcing and sealing the surface of the formation, the epoxy polymer is contained in the drilling fluid 9 in a dissolved and/or emulsified and/or dispersed form and circulates together with the drilling fluid 9 in the annulus 13 along the wall 15 of the borehole 1 . Under the pressure of the drilling fluid 9 the epoxy polymer material enters to a certain degree into the pores of the formation 2. The epoxy polymer melts, fuses and/or cures by way of the heat from the formation naturally occurring at the treatment region and anchors the liner 17 produced on the wall 15 to the formation 2. The deposited epoxy polymer then melts, fuses together, and cures. The melting, fusing and curing process produces an epoxy polymer lining on the surface of the borehole wall which gives the borehole strength, support and provides fluid resistance and containment. In embodiments when epoxy polymer is delivered via the circulating drilling fluid, the liner 17 is continuously produced on the wall 15 by the treatment device 19. The thickness of the liner 17 can be controlled by controlling the density of the epoxy polymer material within the drilling fluid 9, the axial speed of the drill pipe string 5 carrying the treatment device 19 and the circulating velocity of the drilling fluid 9 within the annulus 13.

When circulating the drilling fluid, it can be noted that some of the fluid may return back up through the annulus, as seen by arrows 17, out of the top of the borehole before being pumped back into the borehole. In other words, the epoxy polymer present in the fluid which is not used to treat the borehole typically circulates to the surface of the borehole.

When the epoxy polymer is deposited at the region to be treated 12, in particular when on formation rock, heat from the rock formation is transferred to the epoxy polymer directly. The heat from the rock formation is sufficient to cause melting, fusing and/or curing of the polymer. Thus, the epoxy polymer has a predetermined melting, fusing and/or curing temperature that is exceeded such that it melts, fuses and/or cures when in contact with the formation. Hence, no heating or energy concentrating devices are required to be used to generate the melting and curing process and produce the lining.

It will be appreciated that various epoxy polymers can be used in the technique described above, provided they are able to melt, fuse and/or cure so as to produce the lining on the surface in the region to be treated 12 of the borehole. Epoxy polymers are preferred because the epoxy polymers have good curing, adhesion, strength, penetration, and temperature properties. Suitable epoxy polymers are known and available commercially, for example from Akzo Nobel, with desired melting, fusing and/or curing temperatures for usage in the borehole. Further details of the preferred epoxy polymer used as described in the above methods can be seen with reference now to Figures 2 to 4. As seen in Figure 2, the epoxy polymer is provided in particulate form, i.e. in particles for example as powder. The particulate epoxy polymer comprises a metal core coated with epoxy polymer. In Figure 3, an individual particle of the epoxy polymer 20 is shown, having a metal core 22 surrounded by an epoxy polymer shell or layer 21 . The metal core may help to transfer heat to the epoxy polymer layer when in the borehole, to facilitate the melting, fusing and curing process. The metal can for example comprise iron and/or another metal. In other embodiments, individual particles of the particulate epoxy polymer are formed entirely of epoxy polymer.

The epoxy polymer material preferably is in a particulate form with a particle size of less than 1 mm, preferably less than 0.3 mm, for example 0.1 mm. The particles may consist completely of epoxy polymer material, but preferably have a structure as shown in Figure 3 as a section through particle 20. The particle 20 has a core 22 of solid material like mineral material, e.g. sand or preferably a metal. The core 22 is entirely coated by a layer 21 of the epoxy polymer material. By fusing and/or curing the coating 21 during production of the liner, the particles 20 are combined to an integral layer by fusing or curing the coatings 39 together, while the core 22 provides for ductility and toughness, in particular when the cores 22 consist of steel. The metal provides mechanical support and strength.

The epoxy material should withstand well fluids and drilling fluids. It is essential that the epoxy polymer material is capable of melting, fusing and/or curing above a threshold temperature either by melting above the threshold temperature or by being initiated to cure above the threshold temperature. The epoxy polymer can be a one-component system or a two-component system.

The particulate epoxy polymer is preferably suspended and dispersed in the drilling fluid. In particular variants, some or all of the epoxy polymer could be dissolved or emulsified in the drilling fluid.

The relative sizes of the particles of the particulate epoxy polymer vary, as indicated in Figure 4. The particulate epoxy polymer has a particle size distribution suited to penetrate different sizes of pores, cracks, passageways and/or openings in the borehole wall. In Figure 4, it is seen how particles penetrate such pores, cracks etc. corresponding to their size. A first particle 18 has smaller diameter than that of a second particle 20, and penetrates a first crack 20 which accommodates the first particle 18 but not the second particle 19. The second particle 19 on the other hand is able to penetrate and be accommodated in a second crack 20, being a much larger crack than the first crack. Thus, the particles have a distribution of different sizes. The distribution of sizes can typically be in the range of 20 μιη to 2 mm, for example 70 μιη to 1 mm, preferably selected from any of 80, 180 and 800 μιη. The LCM pill and/or drilling fluid is prepared to have a certain concentration of epoxy polymer in the pill. The concentration of epoxy polymer can typically be in the range of up to 10 % by weight, for example up to 5% by weight, preferably in the range of 1 to 2% by weight. The fluid carrier in which the epoxy polymer is contained could further comprise water or brine and/or a component for example with a composition similar to drilling fluid for example oil or water based drilling fluid or mud.

In specific embodiments, the particulate epoxy polymer in the pill includes some particulates comprising a metal core coated with polymer such as in Figure 3, and also some particles individually formed entirely of epoxy polymer. This could be desirable so that some particles are heated more quickly than others. For example, larger particles, may be provided as epoxy polymer coated metal particles to be able to heat relatively quickly, whilst smaller particles which penetrate farthest into a pore throat, crack, passageway and/or opening may be formed entirely of epoxy polymer and heat more slowly. This allows larger bridges across the pores, cracks, passageway and/or opening to be made first as the larger particles melt, fuse and/or cure earlier. The smaller particles can then fill and plug gaps or spaces around the fused and/or cured larger particles after the larger particles have fused/cured, so that the crack is well-filled with epoxy polymer and an effective lining produced. This may allow good penetration and strength of the lining.

It may be desired to provide epoxy polymer in a way that will ensure that any given opening or crack in the borehole wall at the region 12 is well filled by the material. As mentioned above, the particle size distribution is important, in order to allow particles to access and fill up the spaces or gaps, so that when the material cures, the lining is well anchored, durable, strong, provides an effective fluid barrier and is effective in providing a seal. The pressure in the borehole helps to push the epoxy polymer into the spaces and gaps in the e.g. lost circulation region to press particles together and/or against surfaces at which they are deposited to help produce an effective lining. The production of a strong and effective lining on the borehole surface may also be controlled by way of other properties of the epoxy polymer such as the melting, fusing and/or curing time and/or temperature of the epoxy polymer, or its viscosity prior to curing. For example, the curing temperature of the epoxy polymer in larger particles can be lower than that in smaller particles so that the larger particles cure at a lower temperature and consequently earlier than the smaller particles as they are heated in the borehole. In this way, larger bridges across openings in the borehole wall can be made first. In another example, the time of duration of the melting, fusing, and/or curing phase prior to the epoxy polymer being fully cured can be longer for smaller particles so that they remain viscous for longer than the larger particles, which can help penetration into any residual gaps and spaces in the rock being treated. In other examples, the actual viscosity of the polymer prior to curing may be selected to be very liquid or more gel-like. Different particles, for example different particle-size fractions, may have different viscosity properties.

It is also possible to control the epoxy polymer by causing it to flocculate, and produce flocculated epoxy polymer particles. This is for example carried out by pumping a salt solution, for example a solution of NaCI or KCI, into the borehole and into contact with the deposited epoxy polymer. By way of the presence of the salt solution, the epoxy polymer flocculates. Thus, the salt solution is preferably pumped in after at least some of the epoxy polymer from the pill has been deposited, and before curing of the epoxy polymer. This can be a very useful to achieve efficient bridging of large crack systems. The LCM pill and/or drilling fluid for example contains particulate epoxy polymer which can enter into and deposit on the surfaces of the cracks quite easily. Then, when this epoxy polymer is exposed to the salt solution, the epoxy polymer flocculates and produces flocculated particles that are larger in size than the particulate epoxy polymer originally deposited, to more efficiently fill, block and support the openings, pores, cracks etc. The flocculated particles then melt, fuse and/or cure as they are subjected to sufficient temperatures to produce the epoxy polymer lining on the surface of the borehole.

The technique of treating fluid loss from a borehole or treating a borehole to reinforce it as described herein, using an epoxy polymer that melts, fuses and/or cures to produce a lining on the borehole surface can provide improved strength, reinforcement and fluid and pressure integrity compared with traditional, e.g. LCM, methods. It can, for instance, be possible to fully fill and seal off openings so that leakage through the openings, and cracks in the borehole wall and formation rock cannot take place at all. By controlling the content of epoxy polymer in the pill or drilling fluid, for example particle size distribution, make-up of particles, epoxy polymer type, and threshold temperatures for curing and heating, the plugging of openings and leak paths is more effective and quicker, allows a lining to be produced that provides better fluid resistance and is more durable. Applying salt solutions to cause the epoxy polymer to flocculate provides another way to facilitate and control the plugging or bridging of openings and formation of the lining. This may allow drilling to be continued to construct a well in cases where, using previous techniques, well construction and drilling operations may have needed to be abandoned as a result of drilling fluid loss and lack of pressure control.

In some embodiments (not illustrated), the particles have the structure as shown in Figure 3 and have a core consisting of a diamagnetic metal, for example copper, which, brought in a magnetic field, is repelled by a magnet. In order to produce repellent forces acting on such particles, a treatment device e.g. provided in the drill string comprises at least one magnet, the magnetic field of which is directed so as to force the diamagnetic particles towards the wall of the borehole. The magnet concentrates the particles in the vicinity of the wall and exerts some radial pressure onto the particles before and while forming the liner.

In other embodiments, the particulate epoxy polymer material comprises solid particles as shown in Figure 3 having a solid core in particular of a metal like steel with the core being coated with fusible and/or curable polymer material. The solid particles have an overall density which is higher than the density of any other particles, for example formation particles contained in the drilling fluid and also higher than the density of the rest of the drilling fluid. By engineering the solid particles of the particulate epoxy polymer material in this way, the particulate material can be concentrated at the wall of the borehole by producing a drilling fluid whirl within the annulus around the drill pipe string. A centrifugal separator is for example provided coaxially with the drill pipe and is in the form of a helical vane coaxially fixed to the drill pipe string to impart a whirl movement to the drilling fluid returning and flowing uphole in the annulus. The separator can be a fan wheel which is arranged coaxial to the drill pipe string 5d. A motor may then rotate the fan wheel to produce a centrifugating whirl of drilling fluid within the annulus. Again the particulate epoxy polymer material contained in the drilling fluid is concentrated axially and in the vicinity of the wall of the borehole, whilst the centrifugal action lowers the concentration of particulate epoxy polymer material in the vicinity of the drill pipe string.

Figure 18 shows a section through the downhole end of a borehole 1 ' of a well intended to produce oil and/or natural gas from a formation 2'. The borehole 1 ' is drilled by a drilling equipment 3' comprising a drill pipe string 5' having at its lowermost end a drill bit 7'. The drill pipe string 5' can be constructed in form of a coiled tubing, and the drill bit 7' may include a roamer and a downhole drill motor. Drilling fluid 9' (mud) is circulated from the top of the borehole 1 ' down to the drill bit 7' through the drill pipe string 5' (arrow 11 ') and back to the top of the borehole 1 ' through an annulus 13' radially between the drill pipe string 5' and the surface 15' or wall of the borehole 1 ' (arrow 12'). The drilling fluid lubricates the drill bit 7' and conveys chips the drill bit 7' has produced from the formation to the top of the borehole 1 '. As it is known in the art, the drilling fluid also provides for a counterbalance to formation fluid pressure to prevent uncontrolled flow of fluids from the formation 2' into the borehole 1 ' or vice versa.

To protect the wall 15' of the borehole 1 ' and to continuously and simultaneously apply a liner 17' to the wall 15' for reinforcing and sealing the surface of the formation, a treatment device 19' is attached to the drill pipe string 5' adjacent to the drill bit 7'. The treatment device 19' fuses and/or cures epoxy polymer which is contained in the drilling fluid 9' in a dissolved and/or emulsified and/or dispersed form and which circulates together with the drilling fluid 9' in the annulus 13' along the wall 15' of the borehole 1 '. Under the pressure of the drilling fluid 9' the epoxy polymer enters to a certain degree into the pores, cracks, passageways and/or spaces in the formation 2' and helps to anchor the liner 17' produced on the wall 15' to the formation 2'.

The liner 17' is preferably continuously produced on the wall 15' by the treatment device 19' as explained in more detail below. The thickness of the liner 17' is controlled by controlling the density of the epoxy polymer material within the drilling fluid 9', the axial speed of the drill pipe string 5' carrying the treatment device 19' and the circulating velocity of the drilling fluid 9' within the annulus 13'. The epoxy polymer preferably is in a particulate form with a particle size of less than 1 mm, preferably less than 0.3 mm, for example 0.1 mm. The material should withstand well fluids and drilling fluids. It is essential that the epoxy polymer is capable of fusing and/or curing above a threshold temperature either by melting above the threshold temperature or by being initiated to cure above the threshold temperature. The epoxy polymer can be a one-component system or a two-component system. Of course, instead of a temperature threshold other epoxy polymer systems may be used relying on another initializing process, for example on the basis of UV- light energy supply. The treatment device 19' comprises a plurality of laser devices 21 ', here three laser devices 21 ', which are staggered in axial direction of the drill pipe string 5' and each of which produces a plurality of laser beams 23' distributed around the drill pipe string 5'. Groups of laser beams 23' with at least one laser beam 23' of each of the laser devices 21 ' are directed onto the wall 15' of the borehole such that the laser beams 23' of each group intersect in a limited space 25' in the vicinity of the wall 15' of the borehole 1 '. Thus, the groups of laser beams 23' are focused to said limited space and provide energy spots of a raised energy level within the limited space 25' as compared to the rest of the annulus 13' where the bulk of the epoxy polymer circulates with the drilling fluid 9'. In this way, the epoxy polymer is melted, fused and/or cured to form the liner 17' in the space 25'. The bulk of the epoxy polymer may not be influenced. The treatment device 19' and thus the laser beams 23' rotate together with the drill pipe string 5'. In case of a non-rotating drill pipe string, the treatment device 19' is rotated by a downhole motor relatively to the drill pipe string 5'. Axially on both sides of the treatment device 19' centralizers 27' are provided to guide the treatment device 19' concentrically with the borehole 1 '.

During drilling the borehole 1 ', the drilling fluid 9' continuously circulates through the drill pipe string 5' and the annulus 13' past the treatment device 19'. The continuously rotating laser devices 21 ' are focused to a "hot spot" within the limited space 25' so as to heat the epoxy polymer material contained in the drilling fluid 9' above the threshold temperature of the epoxy polymer and melts, fuses and/or initiates curing of the epoxy polymer material in the vicinity of the wall 15' to continuously build up the liner 17' simultaneously with the feed motion of the drill bit 7'. In the following, other embodiments of the invention will be described. Components having a similar purpose or function as described with respect to Figure 18 will be assigned the same reference numeral with a letter added for distinction. Reference is made to the above description of Figure 18.

Figure 19 shows a drilling equipment 1 a' which differs from that of Figure 18 by the treatment device 19a'. Contrary to the plurality of laser devices 21 ' of Figure 18, the treatment device 19a' comprises a plurality of energy radiating devices 29' each having an energy output port 31 ' positioned in the vicinity of the wall 15a' of the borehole 1 a', and a shielding or reflector 33' which shields the bulk of epoxy polymer material outside the limited space 25a' against the energy radiated into the limited space 25a' in the vicinity of the wall 15a'. Thus, the epoxy polymer present in the space 25a' will be fused and/or cured to form the liner 17a'. The shielding/reflector 33' is shown in the form a plate; of course, other forms may be used, for example tubes which radially extend beyond the energy output port 31 ' towards the wall 15a'.

Both in Figure 18 and Figure 19, a plurality of energy beams or energy devices are provided around the drill pipe string. As being obvious for a man skilled in the art, only one group of energy beams or only one energy output port is sufficient.

Instead of laser devices as shown in Figure 18, microwave devices or induction heating devices or ultrasound devices may be used. The same applies to the embodiment of Figure 19. The meltable, fusible and/or curable epoxy polymer preferably is in a particulate form consisting of particles with a size of less than about 1 mm, preferably of less than 0.3 mm and more preferably of about 0.1 mm. The particles may consist completely of epoxy polymer material, but preferably have a structure as shown in Figure 20 as a section through particulate 35'. The particulate 35' has a core 37' of solid material like mineral material, e.g. sand or preferably a metal. The core 37' is entirely coated by a layer 39' of the epoxy polymer. By melting, fusing and/or curing the coating 39' during production of the liner, the particulates 35' are combined to an integral layer by fusing or curing the coatings 39' together, while the core 37' provides for ductility and toughness, in particular when the cores 37' consist of steel. Figure 21 shows a sketch of an improvement which may be added to the embodiments of Figures 18 or 19. The particulates 35b', which have the structure as shown in Figure 20 have a core consisting of a diamagnetic metal, for example copper, which, brought in a magnetic field, is repelled by a magnet. In order to produce repellent forces acting on such particulates 35b', the treatment device 19' as explained in Figure 18 or the treatment device 19a' of Figure 19 comprises at least one magnet 41 ', the magnetic field of which is directed so as to force the diamagnetic particles 35b' towards the wall 15b' of the borehole. The magnet 41 ' is positioned downhole of the limited space 25b' at which energy indicated at 43' melts, fuses and/or cures the epoxy polymer material of the particulates 35b' to form the liner 17b'. The magnet 41 ' concentrates the particulates 35b' in the vicinity of the wall 15b' and exerts some radial pressure onto the particulates 35b' before and while forming the liner 17b'.

Figure 22 shows an embodiment which allows raising the concentration of particulate epoxy polymer in the vicinity of the wall 15c' of the borehole 1 c'. The epoxy polymer comprises solid particulates as shown in Figure 20 at 35' having a solid core in particular of a metal like steel with the core being coated with meltable, fusible and/or curable epoxy polymer. The solid particulates have an overall density which is higher than the density of any other particles, for example formation particles contained in the drilling fluid and also higher than the density of the rest of the drilling fluid. By engineering the solid particulates of the epoxy polymer material in this way, the particulate material can be concentrated at the wall 15c' of the borehole 1 c' by producing a drilling fluid whirl within the annulus 13c' around the drill pipe string 5c' at a certain distance before and within the curing position defined by the treatment device 19c' within the limited space 25c'.

As shown in Figure 22, a centrifugal separator 45' is provided coaxially with the drill pipe string 5c' upstream in the flow direction 12c' of the drilling fluid 9c'. The centrifugal separator 45' is in the form of a helical vane 47' coaxially fixed to the drill pipe string 5c' to impart a whirl movement (arrow 49') to the drilling fluid 9c' flowing uphole in the annulus 14c. As indicated in Figure 22, the concentration of the particulate epoxy polymer within the whirl fluid flowing uphole in the direction 12c' rises towards the fusing and/or curing position in the limited space 25c'. Figure 23 shows a variant of the centrifugal separator 45d' in the form of a fan wheel 51 ' which is arranged coaxial to the drill pipe string 5d'. A motor 53' rotates the fan wheel 51 ' to produce a centrif ugating whirl of drilling fluid within the annulus 13d'. Again the epoxy polymer particulates contained in the drilling fluid are concentrated some distance before and within the curing position at the limited space 25d'.

The treatment device 19c' or 19d', respectively, makes use of the energy concentrating idea the embodiments of Figures 18 and 19 are based on. Since the centrifugal separators 45', 45d' of the embodiments shown in Figures 22 and 23 provide for a concentration of the epoxy polymer material in the vicinity of the wall of the borehole, it is preferred but not necessary that the energy produced by the treatment devices is radially confined or concentrated at the vicinity of the wall. The limited space may be extended radially up to the drill pipe string since the centrifugal action lowers the concentration of epoxy polymer particulates in the vicinity of the drill pipe string. The same applies to the embodiment shown in Figure 21 .

Results

Laboratory tests with different epoxy polymer-containing fluids have been carried out. Figure 5 shows a test device 100 for testing the suitability of lost circulation material comprising epoxy polymer. The test device has two half-cylinders 101 a, 101 b designed to be clamped together to make up a cylinder with a converging cylindrical space filled with a rough filler material 102 to represent rock as may be encountered at the wall of a borehole. When clamped, the surfaces 103a, 103b face each other. The half-cylinders are clamped so that a small space is defined between the surfaces 103a, 103b to represent a crack in the rock as may be found in the lost circulation region of a borehole wall. Thus, the test device provides in effect an artificial converging crack for testing the epoxy polymer. The half-cylinders may be clamped to provide a crack of different sizes. In Figure 5, a rough surface artificially converging crack has an inlet width of 500μιη (wide end) and an outlet width of 50μιη (narrow / restricted end). In Figure 5, the two half- cylinders are detached from one another, allowing the surfaces 103a, 103b to be inspected.

In the experiments, the half-cylinders are clamped together to define an artificial crack between facing surfaces 103a, 103b. Fluid, i.e. the epoxy polymer and the carrier, is supplied so as to penetrate into the crack at the cylindrical inlet end of the device, at the wide end of the crack. A pressure differential of dP = 500 psi. and a temperature of T = 70 °C was applied. Heat was applied to the test device providing a temperature of T = 70 °C such that the filler material and the epoxy polymer is heated, causing the epoxy polymer to melt, fuse and/or cure. The fluid was thus pushed into and through the crack. The fluid exiting from the narrow, outlet end of the crack, is collected, and the time for the fluid (epoxy polymer and/or carrier), to pass through is measured. The exiting fluid is referred to as filtrate, as the crack acts as a filter with respect to the epoxy polymer particles above a certain size. The content of the filtrate was also observed, for example to check whether any epoxy polymer particles have remained in the carrier indicating that they have not been deposited in the crack. Where the crack is too narrow for the epoxy polymer particle to pass through, the epoxy polymer lodges in the crack whilst the carrier fluid passes onwards. The fluid that follows into the crack must then circumvent earlier lodged particles in order to reach the outlet. Thus, the filtrate quantity and the time and speed (e.g. filtration rate) for the supplied fluid to pass through the crack and filtrate to build up could be determined.

In the experiments the epoxy polymer is present in a concentration of 1% polymer by weight, that is, 10 g/l polymer in water, being the carrier fluid. The polymer in all of the tests was an epoxy polymer with the active component 4,4'- isopropylidene diphenol (bisphenol A) available from Akzo Nobel under the trade name Resicoat®, specifically the Resicoat® product code HNH07R, having a real density 1 - 1.9 g/cm³, bulk density 300-1000 kg/m³, and softening point of >50^qC. The same epoxy polymer product was used in each test except applied in different particle size distributions or configurations with or without iron cores.

Test 1 :

Figures 6 and 7 show the results after treatment of the crack with fluid containing the following polymer blend:

70 wt% epoxy polymer Resicoat® HNH07R coated iron particles of which 30 wt% have an average diameter of 80 μιη and 70% have an average diameter of 800 μιη; and

30 wt% pure epoxy polymer Resicoat® HNH07R particles with an average diameter of 180 μιη. Figure 6 shows the wide end of the crack whilst Figure 7 shows the opened up half- cylinders and the facing surfaces of the crack, after treatment with epoxy polymer- containing fluid. The inlet to the crack can be seen as a central horizontal line 201 across the circular end in the image in Figure 6. The dark areas 202 on the crack surfaces show the cured polymer. The results indicate good ability to penetrate into the crack. The polymer particles were pushed well down in the crack. Polymer particles were not observed in the filtrate fluid indicating they were all retained in the crack. The polymer particles hardened efficiently. Visual observation after performing the test, and after exposure to temperature and pressure, indicates that hardening has occurred. The curing reaction after exposure to temperature and pressure is not reversible.

Test 2:

Figures 8 and 9 show the results after treatment of the crack with fluid containing a different blend of polymer as follows:

70 wt% polymer Resicoat® HNH07R coated iron particles of which 10 wt% have an average diameter of 80 μιη and 90 wt% have an average diameter of 800 μιη; and

30 wt% pure polymer Resicoat® HNH07R particles with an average diameter of 180 Mm.

The difference from Test 1 is that there are fewer smaller particles (10%wt instead of 30%wt of the 80 μιη average diameter) amongst the iron coated particles. These results also show high penetration. Polymer particles are distributed in the whole flow area from 500 μιη to 50 μιη, although mostly in the particle size distribution range 450 μιη to 50μιη. A reduced concentration of fine particles appears to have produced a more uniform distribution of the particles and formed a better bridging of fine and coarse polymer particles. Particles were not observed in the filtrate. Test 3:

Figures 10 and 1 1 show the results after treatment of the crack with fluid containing another blend of polymer as follows:

40 wt% polymer Resicoat® HNH07R coated iron particles with an average diameter of 80 μιη; and 60 wt% polymer Resicoat® HNH07R coated iron particles with an average diameter of 800 μιη.

Compared with Tests 1 and 2, this test omits particles with the intermediate size of 180 μιη average diameter of pure polymer. Some particles are lodged at the bottom, and some at the top of the crack.

Test 4:

Figures 12 and 13 show the results after treatment of the crack with fluid containing another polymer as follows:

100 wt% polymer Resicoat® HNH07R coated iron particles with an average diameter of 800 μιη.

The results show poor plugging of the crack, and it can be seen in Figure 13 that the cured polymer is sparsely distributed on the crack surfaces

Test 5: Reinforcement of fractured shale

Procedure:

• Mancos shale was used as a field analog (φ38 mm x L38 mm specimen)

• Axial fractures generated by uniaxial loading - 48 Mpa peak stress

• Spacers (aluminium) inserted between fracture planes to ensure permeability

• Specimen remounted in triaxial cell

• Peak strength measured in triaxial conditions (with confining pressure): 51 Mpa

• Residual (post-peak) strength measured: 16-21 Mpa (depending on pore pressure)

• Epoxy polymer solution injected into fractures and cured at 70 °C overnight

• Specimen de-mounted, scanned, and remounted Results

The specimen was in tact after curing and the fracture planes had some cohesion Peak strength after treatment measured: 29 Mpa. This is higher than the earlier residual stregnth Summary of tests

Data from the above tests are displayed in the plots shown in Figures 14 and 15. Figure 14 shows the collected filtrate amount versus time for the Tests 1 to 4.

Figure 15 shows the corresponding total filtration times, i.e. collection time for filtrate of the supplied fluid that has passed through from the inlet to the outlet of the crack. The gradients of the curves in Figure 14 indicate the filtration rate. A slow filtration rate means that it takes longer for the filtrate of the fluid to accumulate through the outlet crack (see Figure 15). This indicates that the polymer has become lodged in the crack so as to create a significant obstacle in the pathway for fluid through the crack, such that it is more difficult and takes longer, for fluid to pass through the crack between the inlet and the outlet. Pathways for fluid may be smaller or more tortuous.

The results in Figure 14 show very high filtration rates in relation to Test 4 which used a single size polymer, and two other single size material tests (labelled as Epoxy 4 and Pure polymer 180 μιη, not described specifically above). By including other particles sizes in Tests 1 , 2 and 3, the filtration rate is significantly slowed. This corresponds with better penetration and distribution of particles in the crack surfaces as seen in the Figures 6 to 1 1 described above. The polymer blends in Tests 1 to 3 therefore appear to have relatively good sealing potential and suitability for treating loss, whilst the single size does seem to give an acceptable sealing potential.

Test 1 results provide the slowest filtration rate. Test 1 includes a greater proportion of smaller particles compared with Tests 2 and 3, but also intermediate and larger particle sizes. The presence of the smaller particles helps the sealing because they are pressed and packed together very closely and can fit in small spaces and around larger particles, closing small pathways and spaces effectively, and melting, fusing and/or curing into a more continuous lining. The Test 1 indicates that the use additionally of small particles provides significant slowdown in filtration rate and good sealing potential. Packing with larger particles tends to leave larger gaps or spaces between particles due to their size or shape, which may not be sealed very well without the presence of smaller particles that fit those spaces, such that fluid can pass through more easily and give rise to higher filtration rate, such as in Test 2. Test 3 shows that intermediate size particles can also be important to sealing, as the omission of these in Test 3 show faster filtration than in Test 1. By including other particles sizes in Tests 1 , 2 and 3, rather than relying on single-size material as in Test 4, better penetration and distribution of particles in the crack surfaces is seen. The epoxy polymer blends in Tests 1 to 3 therefore appear to have relatively good potential for filling the cracks and providing strong, durable and fluid resistant liner.

The presence of the smaller particles helps because they are pressed and packed together very closely and can fit in small spaces and around larger particles, closing small pathways and spaces effectively, and melting, fusing and/or curing into a more continuous lining. Packing with larger particles can tend to leave larger gaps or spaces between particles due to their size or shape, which may not be sealed very well without the presence of smaller particles that fit those spaces.

The graphs refer to Epoxy 4 which is single size material similar to the pure 180 micron polymer, but with higher viscosity properties in the melting phase.

Melting of the polymer allows it to adhere to crack surfaces. In the melting phase, the polymer softens and can deform somewhat. The pressure differential pushes and helps the particles to penetrate into the crack and into spaces where it can seal effectively. This is helped by the deformability of the polymer and particles in the melting phase.

Figures 16 and 17 show the results of flocculation tests with different KCI and NaCI salt solutions. The epoxy polymer was deposited as described above and salt solutions applied. The fluid based on NaCI brine solution showed an agglomeration with following flocculation (see Figure 17), while in the KCI brine the epoxy polymer molecules remain evenly dispersed (see Figure 16).

The difference on impact of KCI and NaCI salt solutions on the epoxy polymer depend on the condition of the chemical interactions between the individual epoxy polymer crystals and the salt crystals. Due to the K+ ions having a smaller diameter than Na+ ions in the hydrated form, the K+ ions distribute into the polymer crystal structure, and thus bind crystal surfaces close together and effectively prevent aggregation and flocculation processes. The Na+ ions with larger diameter allow a binding of the individual polymer crystals to each other "edge-to-edge" or "edge-to-face" in aggregation and flocculation follows.

The results from test 5 show that the epoxy polymer may be used to reinforce fractured shale. Various modifications and improvements may be made without departing from the scope of the invention herein described.

Claims

CLAIMS:

1. An epoxy polymer, wherein said polymer is in the form of a plurality of sets of particulates, comprising:

a first set of particulates having an average diameter of 40 to 100 microns; and a second set of particulates having an average diameter of 700 to 1000 microns.

2. A polymer as claimed in claim 1 , wherein said epoxy polymer comprises a third set of particulates having an average diameter of 120 to 300 microns.

3. A polymer as claimed in claim 1 or claim 2, wherein at least one set of particulates comprises particulates having a metal core and an epoxy polymer coating surrounding the core.

4. A polymer as claimed in any one of claims 1 to 3, wherein at least one set of particulates comprises particulates consisting of epoxy polymer.

5. A polymer as claimed in any one of claims 1 to 4, wherein said plurality of sets of particulates comprises:

0 to 40 wt% of a first set of particulates having an average diameter of around 80 microns; and

45 to 65 wt% of a second set of particulates having an average diameter of around 800 microns; and

0 to 60 wt% of a third set of particulates having an average diameter of around

180 microns.

6. A polymer as claimed in any preceding claim, wherein said epoxy polymer comprises particulates differing in size in order to penetrate into spaces such as pores cracks, passageways, and/or openings differing in size in the wall of a borehole, which extends into at least one geological formation.

7. A polymer as claimed in any preceding claim, wherein said epoxy polymer has a non-uniform fusing or curing time.

8. A polymer as claimed in any preceding claim, wherein particulates having a size above a certain threshold size have a longer or shorter fusing or curing time than particulates having a size below said threshold size.

9. A polymer as claimed in any preceding claim, wherein said epoxy polymer has a non-uniform melting, fusing and/or curing temperature.

10. A polymer as claimed in any preceding claim, wherein particulates having a size above a certain threshold size have a higher or lower melting, fusing and/or curing temperature than particulates having a size below said threshold temperature.

1 1. A method of making an epoxy polymer as claimed in any one of claims 1 to 10, comprising:

12. A composition comprising an epoxy polymer as claimed in any one of claims 1 to 10 and a carrier.

13. A composition as claimed in claim 12 which is a fluid composition.

14. A composition as claimed in claim 12 or claim 13, wherein said carrier comprises drilling fluid.

15. A composition as claimed any one of claims 12 to 14, further comprising a curing agent.

16. A lost circulation material, LCM, pill for treating fluid loss from a borehole, the borehole extending into at least one geological formation, the LCM pill comprising a carrier and an epoxy polymer as defined in any one of claims 1 to 10.

17. A LCM pill as claimed in claim 16, wherein the epoxy polymer is contained in said pill in a concentration of up to around 5% by weight.

18. A LCM pill as claimed in claim 16 or 17, wherein the epoxy polymer has a threshold melting, fusing and/or curing temperature lower than the temperature in the borehole at the lost circulation region, such that the threshold temperature of the material is exceeded when deposited at said region to activate melting, fusing, and/or curing of the epoxy polymer.

19. A lining for treating a borehole extending into at least one geological formation comprising an epoxy polymer as defined in any one of claims 1 to 10.

20. A lining as claimed in claim 19, wherein said lining is in a lost circulation region.

21. A lining for lining a surface in a lost circulation region of a borehole extending into at least one geological formation, for restricting or preventing fluid flow between the borehole and the geological formation, the lining produced from the epoxy polymer of any one of claims 1 to 10, a composition as claimed in any one of claims 12 to 15, or a LCM pill as claimed in any one of claims 16 to 18.

22. A method of treating a borehole, the borehole extending into at least one geological formation, the method comprising:

(a) providing an epoxy polymer as claimed in any one of claims 1 to 10, a composition as claimed in any one of claims 12 to 15, or a LCM pill as claimed in any one of claims 16 to 18; and

(b) circulating said epoxy polymer, composition or LCM pill in the borehole to deposit a polymer, the polymer melting, fusing and/or curing to produce a lining on a surface in said region to treat said borehole.

23. A method of treating fluid loss from a borehole, the borehole extending into at least one geological formation, the method comprising:

(a) stopping drilling;

(d) re-starting drilling.

24. A method as claimed in claim 23, wherein said epoxy polymer is as defined in any one of claims 1 to 10.

25. A method as claimed in any one of claims 22 to 24, wherein the epoxy polymer is circulated in the borehole to deposit the epoxy polymer on a surface of the wall of the borehole, or, on surfaces of cracks, passageways and/or openings which extend into the wall of the borehole.

26. A method as claimed in any one of claims 22 to 25, wherein the produced lining restricts or prevents passage of fluid through the lining.

27. A method as claimed in any one of claims 22 to 26, wherein said lining blocks pores, cracks, passageways and/or openings in a wall of the borehole to restrict or prevent fluid access into the geological formation.

28. A method as claimed in any one of claims 22 to 27, which further comprises identifying a lost circulation region by observing a loss of circulating drilling fluid in a drilling process.

29. A method as claimed in any one of claims 22 to 28, which further comprises circulating drilling fluid in the borehole and drilling a further section of the borehole after the lining is produced.

30. A method as claimed in any one of claims 22 to 29, which further comprises using a borehole tool to focus energy in the borehole in a fluid loss region to provide sufficient heat to cause the polymer to melt, fuse and cure to produce the lining on said surface of the borehole.

31 . A method as claimed in any one of claims 22 to 29, wherein no heater or other energy concentration device is required to be used to produce melting, fusing and/or curing of the epoxy polymer or the lining at the region to be treated.

32. A method as claimed in any one of claims 22 to 29 and 31 , wherein the epoxy polymer is designed with at least one predetermined melting, fusing and/or curing temperature and the deposited epoxy polymer melts, fuses and/or cures by exceeding the predetermined temperature naturally in the prevailing temperature conditions in the borehole.

33. A method of treating a borehole extending into at least one geological formation, the method comprising circulating an epoxy polymer as defined in any one of claims 1 to 10 and a carrier in the borehole adjacent to a borehole wall portion to be treated, the epoxy polymer melting, fusing and/or curing by heat from the formation, to produce a lining or liner at said wall portion to treat the borehole.

34. A method as claimed in claim 33, wherein no heater or other energy concentration device is required to be used to produce melting, fusing and/or curing of the epoxy polymer or the lining at the region to be treated.

35. A method as claimed in claim 33 or claim 34, wherein the circulating step is performed to deposit the epoxy polymer on a surface of the wall of the borehole, or, on surfaces of cracks, passageways and/or openings which extend into the wall of the borehole between the borehole and the geological formation.

36. A method according to any one of claims 33 to 35, performed during drilling, wherein the carrier comprises drilling fluid.

37. A method as claimed in any one of claims 33 to 36, wherein the lining and/or epoxy polymer penetrates into pores, cracks, passageways and/or openings in a wall of the borehole to strengthen the geological formation.

38. A method as claimed in any one of claims 33 to 37, wherein said epoxy polymer is designed with at least one melting, fusing and/or curing temperature and the deposited epoxy polymer melts, fuses and/or cures by exceeding the predetermined temperature naturally by the heat from the formation.

39. A method of reinforcing a borehole of a well comprising the steps of: circulating a drilling fluid containing a meltable, fusible and/or curable epoxy polymer as claimed in any one of claims 1 to 10 dissolved and/or emulsified and/or dispersed therein along the surface of the borehole; and

40. A method according to claim 39, performed while drilling the borehole.

41 . A method as claimed in claim 40, wherein the melting, fusing and/or curing step is performed by concentrating energy for melting, fusing and/or curing the epoxy polymer in a limited space in the vicinity of the surface.

42. A method as claimed in claim 41 , wherein the step of concentrating energy for melting, fusing and/or curing the epoxy polymer in the vicinity of the surface of the borehole comprises the step of simultaneously directing at least two energy beams to the limited space such that the energy beams intersect within a limited space.

43. A method as claimed in claim 41 , wherein the step of concentrating energy for melting, fusing and/or curing the epoxy polymer in the vicinity of the surface of the borehole comprises the step of outputting the energy in the vicinity of the limited space while shielding and/or reflecting the energy at the side of the limited space remote of the surface of the borehole.

44. A method as claimed in any one of claims 39 to 43, wherein the drilling fluid contains solid metal particles coated with meltable, fusible and/or curable epoxy polymer as defined in any one of claims 1 to 10.

45. A method as claimed in any one of claims 39 to 44, when dependent on claim 3, wherein the metal cores consist of a diamagnetic metal and the method further comprises the step of magnetically accelerating the particles towards the surface of the borehole.

46. A method as claimed in any one of claims 41 to 45, wherein the step of circulating the drilling fluid comprises producing upstream of the limited space of concentrated energy a whirl of drilling fluid coaxial with the borehole for centrifugating particulate epoxy polymer material towards the surface of the borehole.

47. A method as claimed in any one of claims 22 to 46, which further comprises delivering a salt solution into the borehole to cause the deposited epoxy polymer to flocculate.

48. An epoxy polymer as defined in any one of claims 1 to 10 and carrier for use in the method of any of claims 22 to 47.

49. Apparatus for performing the method of any one of claims 22 to 47.

50. Equipment for drilling and reinforcing a borehole of a well comprising:

a drill pipe string comprising a drill tool at its lowermost end;

51. Equipment as claimed in claim 50, wherein the treatment device is an energy radiating device to concentrate energy for melting, fusing and/or curing the epoxy polymer in a limited space in the vicinity of the surface, the device producing at least two energy beams which intersect in the limited space in the vicinity of the surface of the borehole.

52. Equipment as claimed in claim 51 , wherein the energy radiating device comprises at least two laser light devices or microwave devices or induction heating devices or ultrasound devices providing intersecting energy beams.

53. Equipment as claimed in claim 50, wherein the treatment device has at least one energy output port positioned in the vicinity of the surface of the borehole.

54. Equipment according to claim 53, wherein the energy output port has associated thereto an energy shielding and/or an energy reflector to focus the energy to the surface of the borehole.

55. Equipment as claimed in any of claims 50 to 54, wherein the drilling fluid contains particulate epoxy polymer as claimed in any one of claims 1 to 10.

56. Equipment as claimed in claim 55, wherein the particulate epoxy polymer comprises solid particles coated with meltable, fusible and/or curable epoxy polymer.

57. Equipment as claimed in claim 56, wherein the solid particles are comprised of metal.

58. Equipment as claimed in any one of claims 50 to 55, wherein the drilling fluid contains particulate epoxy polymer comprising solid particles of a diamagnetic metal coated with fusible and/or curable epoxy polymer material, and wherein the treatment device comprises magnetic accelerating means for radially accelerating the particulate epoxy polymer towards the surface of the borehole.

59. Equipment as claimed in any one of claims 50 to 58, wherein the drilling fluid contains particulate epoxy polymer comprising solid particles having a particle density higher than the density of the drilling fluid including particulate material other than the particulate epoxy polymer and wherein the downhole treatment device comprises a centrifugal separator coaxial with the drill pipe string adapted to centrifugate the higher density particulate epoxy polymer of the drilling fluid circulating in the annulus radially outwards towards the surface of the borehole.

60. Equipment as claimed in claim 59, wherein the centrifugal separator comprises coaxial to the drill pipe string a stationary helical vane or a motor-driven fan wheel.