GB2518442A

GB2518442A - Method of treating a borehole

Info

Publication number: GB2518442A
Application number: GB1316901.6A
Authority: GB
Inventors: Zalpato Ibragimova; Steinar Wasa Tverlid
Original assignee: Statoil Petroleum ASA
Current assignee: Equinor Energy AS
Priority date: 2013-09-23
Filing date: 2013-09-23
Publication date: 2015-03-25
Also published as: GB201316901D0

Abstract

A method of treating a borehole 3 which extends into a formation involves circulating a polymer 2 and a carrier in the borehole 3, the polymer 2 melting, fusing and/or curing by heat from the formation to produce a lining or liner at the wall of the borehole. The polymer may be an epoxy polymer and be in particulate form having a metal core (22, fig 3) and a polymer coating (21, fig 3) surrounding the core.

Description

Method of treating a borehole

Technical field

The present invention relates to the field of well construction, and in particular to a method of treating a borehole of a well, for example to reinforce, strengthen or contain fluid pressure in the borehole, for example for hydrocarbon production from a geological formation, and associated apparatus.

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 trom the formation into the borehole and avoid kicks or blow outs.

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 thrcugh 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 ol 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. Alter 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 Al 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 6,311,773 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 01 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 [P 0 879 935 A2, US 7,21 6,711 B2, uS 7,264,052 B2, WO 03/102 086 A2, [P 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 the invention

According to a first aspect of the invention, 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 by heat from the formation, 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 polymer. The heat may be received in borehole, by the particles, through the borehole wall. The 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 polymer delivered from the surface may typically have a temperature below the melting, fusing and/or curing temperature of the 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 polymer is circulated in the wellbore at sufficient depth, the natural temperature conditions may cause the carrier and polymer to heat up and the polymer temperature to increase to above the melting, fusing and/or curing temperature necessary for the melting, fusing, and/or curing of the polymer to take place to produce the lining. The 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 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.

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

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

Due to the downhole pressure of the drilling fluid, some of the drilling Iluid 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.

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 [P 1 664 481 BI, WO 2005/121 500 Al or 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.

The polymer may be deposited 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.

The 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 102000 micron, more preferably 30 to 1500 micron and still more preferably 50 to 1000 micron.

In some embodiments the particulates further comprise a metal. In such embodiments the particulates preferably comprise a metal core and a 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 to 1000 microns. The metal may help to transfer heat to the 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, polymer, i.e. individual particles are formed entirely of 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 a polymer coating and particulates consisting of polymer. The weight ratio of particulates comprising a metal core to particulates consisting of polymer is preferably 50:50 to 95:5 and more preferably 65:35 to 80:20. The lining, and particles 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 polymer particles 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.

The polymer may preferably be provided in sufficient quantity and with an appropriate size distribution in order to fill the cracks, passageways, and/or openings. For example, the polymer may comprise particles 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 polymer more efficiently.

Particularly preferably the particulate polymer 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 %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 particulate 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 B to 12 times greater than the first average diameter. Still more preferably the particulate 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 particulate polymer comprises a first set of particulates having an average diameter of 40 to 100 miorons (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). Still more preferably the particulate polymer further comprises a third set of particulates having an average diameter of 120 to 300 microns (e.g. 150 to 250 microns). The particulate polymer may, for example, comprise: a first set of particulates having an average diameter of 50 to 35 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.

When a plurality of sets of particulates is used, any of the sets may comprise particulates comprising a metal core and a polymer coating, particulates consisting of polymer or mixtures thereof. Preferably, however, the first set of particulates is particulates comprising a metal core and a polymer coating. More preferably the third set of particulates is particulates comprising a metal core and a polymer coating. Still more preferably the second set of particulates is particulates consisting of polymer.

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

As used herein, the term melting refers to the process by which the polymer changes into or becomes liquid. As used herein, the term fusing refers to the process by which the chains of one particulate 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 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 polymer may melt, fuse and/or cure naturally in the prevailing temperature conditions in the borehole.

The polymer may have a non-uniform fusing or curing time, at a given temperature. In the case of particulate polymer, 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. When a plurality of sets of particulates is used, the sets may comprise polymer having a fusing or curing time, that is different between sets.

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

Preferably at least one of the polymers used in the method of the invention has a melting point of 40 to 200 00 more preferably 50 to 150 CC and still more preferably 70 to 100 00, e.g. when measured by melting point apparatus. Preferably at least one of the 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 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 polymer used in the method of the present invention is preferably curable. The polymer may be cured, for example, by addition of a curing agent or hardener, heat and/or radiation. Particularly preferably the polymer is heat curable.

The polymer used in the present invention is preferably an epoxy polymer. As used herein the term "epoxy polymer" is intended to refer to a polymer that is formed from monomers comprising at least one epoxide group and which comprises at least one epoxide group.

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 did 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 isocyanurate.

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); glycidylethor 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 diglyoidylether (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 polymer preferably comprises a mixture of different types of polymers. The blending of different types of epoxy polymer is often beneficial to achieve the desired melting, fusing and/or curing profile. Suitable polymers for use in the methods of the present invention are commercially available, e.g. from Akzo Nobel.

The carrier is preferably a liquid carrier. The polymer is preferably insoluble in the carrier. Thus preferably the polymer is applied to the borehole as a dispersion in the carrier. The carrier may be aqueous or non-aqueous. Preferred non-aqueous carriers include hydrocarbon or hydrocarbon mixtures, alcohols and polyols, for example mineral oil. More preferably, however, the carrier is aqueous, e.g. water. The carrier may be water based mud, e.g. a water based drilling mud.

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.

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 01 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 ito 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.

The method may further comprise delivering a curing agent or hardener into the borehole at the surface of the borehole to cause the deposited 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 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 polymer to flocculate. As used herein, the term flocculate refers to the formation of aggregates of particulate polymer by particulates clumping or grouping together. The average diameter of a flocculated particulate 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, Ca4 or Cs and especially preferably Nat 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 %wt.

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

The particulate polymer may consist of polymer material only. Preferably, the particulate polymer comprises solid particles coated with fusible and/or curable polymer material to mechanically strengthen the liner formed on the wall of the borehole. In a preferred embodiment, the solid particles are comprised of metal, in particular steel, to provide for ductility and toughness of the liner while the polymer material will bind the composite together.

Preferably, the particles of the particulate polymer material 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 polymer material is coated onto particulate metal cores.

The liner may be continuously produced on the wall of the borehole. The thickness can be controlled by controlling the concentration of the 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 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 polymer material contained in the drilling fluid starting from the average concentration of the polymer material in the drilling fluid, A treatment device may be adapted and used to specifically raise the concentration of the polymer material in the vicinity of the wall e.g. in a limited space therein.

Additional pressure may be exerted onto particulate polymer material by magnetic forces produced by at least one magnet of the treatment device. The particulate polymer material comprises solid particles 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 particles towards and into the formation where the particles concentrate for forming the liner.

If the drilling fluid contains particulate polymer material comprising solid particles having a particle density higher than the density of the drilling fluid including particulate material other than the particulate polymer material, the concentration of the 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 particulate polymer material 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 material 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 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 particles onto the wall of the borehole.

According to a second aspect of the invention, 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.

According to a third aspect of the invention, there is provided apparatus for performing the method of the first or second aspect above.

According to fourth aspect of the invention, there is provided a polymer and carrier for use in the method of the first or second aspect above.

According to a fifth aspect of the invention, there is provided a lining for treating a borehole produced by the methods of the first or second aspect or using the apparatus of the third aspect.

Each of the second to fifth aspects may have further features as defined in relation to the first aspect. Any of the above aspects may have further features in any combination as described herein whether in the drawings, description and/or claims.

Descrirtion and drawings There will now be described, by way of example only, embodiments of the invention with reference to the accompanying drawings of which: Figure 1 is a representation of a borehole extending into the earth during the delivery of drilling fluid in a well whilst drilling the borehole, according to an embodiment of the invention; Figure 2 is a close-up representation of a surface of the borehole in the region to be treated, and the deposition of polymer in the pill of Figure 1 upon that surface; Fig. 3 is a cross-section of a particle contained in the drilling fluid used with the equipment while drilling; 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 drilling fluid 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 11 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 alter treatment in the fourth test of Figure 12; Figure 14 is an image of epoxy polymer in water-based mud with flocculation due to KCI brine; and Figure 15 is an image of epoxy polymer in water-based mud with flocculation due to NaCI brine.

With reference firstly to Figure 1, a fluid carrier in the form of drilling fluid 2 and a polymer, is being circulated into a borehole 3 of a well 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 Ga 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 drilling fluid 2 is pumped into the borehole, and reaches borehole wall region to be treated 12. The region to be treated 12 requires reinlorcement, strengthening, pressure containment, andlor 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 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 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, craoks, 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 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 polymer material enters to a certain degree into the pores of the formation 2. The 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 polymer then melts, fuses together, and cures. The melting, fusing and curing process produces a polymer lining on the surface of the borehole wall which gives the borehole strength, support and provides fluid resistance and containment.

In embodiments when 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 I? can be controlled by controlling the density of the 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 polymer present in the fluid which is not used to treat the borehole typically circulates to the surface of the borehole.

When the 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 polymer directly. The heat from the rock formation is sufficient to cause melting, fusing and/or curing of the polymer. Thus, the 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 polymers can be used in the technique described above, provided they are able to melt, fuse andjbr 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 polymer used as described in the above can be seen with reference now to Figures 2 to 4. As seen in Figure 2, the polymer is provided in particulate form, i.e. in particles for example as powder. The particulate polymer comprises a metal core coated with polymer. In Figure 3, an individual particle of the polymer 20 is shown, having a metal core 22 surrounded by a polymer shell or layer 21.

The metal core may help to transfer heat to the 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 polymer are formed entirely of polymer.

The 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 material should withstand well fluids and drilling fluids. It is essential that the 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 polymer material can be a one-component system or a two-component system.

The fusible and/or curable polymer material 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 polymer material, but preferably have a structure as shown in Fig. 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 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 methcniacl support and strength.

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

The relative sizes of the particles of the particulate polymer vary, as indicated in Figure 4. The particulate 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 tirst crack.

Thus, the particles have a distribution of different sizes. The distribution of sizes can typically be in the range of 20 jim to 2 mm, for example 70 m to 1 mm, preferably selected from any of 80, 180 and 800 rim.

The drilling may have a certain concentration of polymer therein. The concentration of polymer could 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 drilling fluid could be for example oil or water based drilling fluid or mud.

In specific embodiments, the particulate polymer includes some particulates comprising a metal core coated with polymer such as in Figure 3, and also some particles individually formed entirely of polymer. This could be desirable so that some particles are heated more quickly than others. For example, larger particles, may be provided as 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 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 till 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 polymer and an effective lining produced. This may allow good penetration and strength of the lining.

It may be desired to provide 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 polymer. 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 and strong and provides an effective fluid barrier. The pressure in the borehole helps to push the polymer into the spaces and gaps in the region to be treated to press particles together and/or against surfaces at which they are deposited to help produce an effective lining.

The production of an strong and eftective lining on the borehole surface may also be controlled by way of other properties of the polymer such as the melting, fusing and/or curing time and/or temperature of the polymer, or its viscosity prior to curing. For example, the curing temperature of the 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 polymer being tully 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. Dferent particles, for example different particle-size fractions, may have different viscosity properties.

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

The technique of treating a borehole as described herein, using a polymer that melts, fuses and/or cures to produce a lining on the borehole surface can provide improved strength, reinforcement and pressure integrity compared with traditional methods. It can be possible to fully fill and seal opening. By controlling the content of polymer in the pill, for example particle size distribution, make-up of particles, 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 polymer to flocculate provides another way to facilitate and control the plugging or bridging of openings and formation of the lining.

In some embodiments (not illustrated), the particles have the structure as shown in Fig. 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, the treatment device the 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 01 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 polymer material comprises solid particles as shown in Fig. 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 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 Sd. A motor may then rotate the fan wheel to produce a centrifugating whirl of drilling fluid within the annulus. Again the particulate 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 polymer material in the vicinity of the drill pipe string.

Crack Qenetration results Laboratory tests with different polymer-containing fluids have been carried out. Figure 5 shows a test device 100 for testing the suitability of drilling fluid carrying polymer.

The test device has two half-cylinders lOla, 101 b designed to be clamped together to make up a cylinder with a converging cylindrical space tilled 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 region to be treated of a borehole wall. Thus, the test device provides in effect an artificial converging crack for testing the 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 500pm (wide end) and an outlet width of 5Opm (narrow I restricted end). In Figure 5, the two half-cylinders are detached from one another, allowing the surfaces 1 03a, 1 03b 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 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 dA = 500 psi. and a temperature of I = 70°C was applied. Heat was applied to the test device providing a temperature of I = 70°C such that the filler material and the polymer is heated, causing the polymer to melt, fuse and/or cure. The fluid was thus pushed into and through the crack.

In the experiments the polymer is present in a concentration of 1% polymer by weight, that is, 10 g/l polymer in water, being the carrier Iluid to represent the drilling 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 HNHO7R, having a real density 1- 1.9 g/cm3, bulk density 300-1000 kg/m3, and softening point of >50CC.

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 alter treatment of the crack with fluid containing the following polymer blend: 70 wt% epoxy polymer Resicoat® HNHO7R coated iron particles of which 30 wt% have an average diameter of 80 pm and 70% have an average diameter of 800 pm; and wt% pure epoxy polymer Resicoat® HNHO7R particles with an average diameter of 180 pm.

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. 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 Iluid containing a different blend of polymer as follows: wt% polymer Resicoat® HNHO7R coated iron particles of which 10 wt% have an average diameter of 80 pm and 90 wt% have an average diameter of 800 pm; and wt% pure polymer Resicoat® HNHO7R particles with an average diameter of 130pm.

The difference from Test 1 is that there are fewer smaller particles (10%wt instead of 30%wt of the 80 pm average diameter) amongst the iron coated particles. These results also show high penetration. Polymer particles are distributed in the whole flow area from 500 pm to 50 pm, although mostly in the particle size distribution range 450 pm to 5Opm. 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.

Test3: Figures 10 and 11 show the results after treatment of the crack with fluid containing another blend of polymer as follows: wt% polymer Resicoat® HNHO7R coated iron particles with an average diameter of 80 pm; and 60 wt% polymer Resicoat® HNHO7R coated iron particles with an average diameter of 800 pm.

Compared with Tests 1 and 2, this test omits particles with the intermediate size of 180 pm average diameter of pure polymer. Some particles 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® HNHO7R coated iron particles with an average diameter of 800 pm.

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

Summary attests

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 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.

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 14 and 15 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.

Various modlications and improvements may be male without depatting from the scope of the Invention herein described.

Claims

CLAIMS: 1. 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 by heat from the formation, to produce a lining or liner at said wall portion to treat the borehole.
2. A method as claimed in claim 1, wherein no heater or other energy concentration device is required to be used to produce melting, fusing and/or curing of the polymer or the lining at the region to be treated.
3. A method as claimed in claim 1, wherein the circulating step is performed to deposit the 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.
4. A method as claimed in any preceding claim, wherein the polymer comprises an epoxy polymer.
5. A method as claimed in claim 1 or claim 2, performed during drilling, wherein the carrier comprises drilling fluid.
6. A method as claimed in any preceding claim, wherein the lining and/or polymer penetrates into pores, cracks, passageways and/or openings in a wall of the borehole to strengthen the geological formation.
7. A method as claimed in any preceding claim, wherein the polymer is designed with at least one melting, fusing and/or curing temperature and the deposited polymer melts, fuses and/or cures by exceeding the predetermined temperature naturally by the heat from the formation.
8. A method as claimed in any preceding claim, wherein the polymer is provided in particulate form.
9. A method as claimed in claim 8, wherein the particulate polymer comprises particulates having a metal core and a polymer coating surrounding the core
10. A method as claimed in claim 8 or 9, wherein the particulate polymer comprises particulates consisting of polymer.
11. A method as claimed in any of claims 8to 10, wherein the particulate polymer comprises particles differing in size in order to penetrate into spaces such as pores cracks, passageways, and/or openings differing in size in the wall of the borehole.
12. A method as claimed in any of claims 8 to 10 wherein the particulate polymer comprises a plurality of sets of particulates.
13. A method as claimed in claim 12, wherein the particulate polymer comprises 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.
14. A method as claimed in claim 13, wherein the particulate polymer comprises a third set of particulates having an average diameter of 120 to 300 microns.
15. A method as claimed in any of claims 12 to 14, wherein any of the sets comprises particulates comprising a metal core and a polymer coating, particulates consisting of polymer or mixtures thereof.
16. Apparatus for performing the method of any preceding claim.
17. A polymer and carrier for use in the method of any of claims ito 15.
18. A lining for treating a borehole, produced by the method of any of claims 1 to 15.