WO2015128454A1 - Method and system for lining a tubular - Google Patents
Method and system for lining a tubular Download PDFInfo
- Publication number
- WO2015128454A1 WO2015128454A1 PCT/EP2015/054115 EP2015054115W WO2015128454A1 WO 2015128454 A1 WO2015128454 A1 WO 2015128454A1 EP 2015054115 W EP2015054115 W EP 2015054115W WO 2015128454 A1 WO2015128454 A1 WO 2015128454A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- liner
- tubing string
- tubing
- coating
- string
- Prior art date
Links
- 238000000034 method Methods 0.000 title claims description 46
- 238000005260 corrosion Methods 0.000 claims abstract description 54
- 230000007797 corrosion Effects 0.000 claims abstract description 53
- 239000012530 fluid Substances 0.000 claims abstract description 42
- 238000000576 coating method Methods 0.000 claims abstract description 41
- 239000011248 coating agent Substances 0.000 claims abstract description 34
- 239000003292 glue Substances 0.000 claims abstract description 6
- 229920000642 polymer Polymers 0.000 claims description 60
- 239000002131 composite material Substances 0.000 claims description 55
- 238000004519 manufacturing process Methods 0.000 claims description 53
- 229910052751 metal Inorganic materials 0.000 claims description 38
- 239000002184 metal Substances 0.000 claims description 38
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- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 16
- 229920000247 superabsorbent polymer Polymers 0.000 claims description 11
- 239000000853 adhesive Substances 0.000 claims description 10
- 230000001070 adhesive effect Effects 0.000 claims description 10
- 229910000831 Steel Inorganic materials 0.000 claims description 9
- 239000010959 steel Substances 0.000 claims description 9
- 230000002787 reinforcement Effects 0.000 claims description 7
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 claims description 6
- 239000000654 additive Substances 0.000 claims description 6
- 239000007788 liquid Substances 0.000 claims description 6
- 238000005507 spraying Methods 0.000 claims description 6
- 229910052799 carbon Inorganic materials 0.000 claims description 5
- 229920000058 polyacrylate Polymers 0.000 claims description 5
- 239000003365 glass fiber Substances 0.000 claims description 4
- 239000000017 hydrogel Substances 0.000 claims description 4
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 claims description 3
- 238000005086 pumping Methods 0.000 claims description 3
- 239000000741 silica gel Substances 0.000 claims description 3
- 229910002027 silica gel Inorganic materials 0.000 claims description 3
- 229960001866 silicon dioxide Drugs 0.000 claims description 3
- 230000001939 inductive effect Effects 0.000 claims description 2
- 239000011888 foil Substances 0.000 abstract description 4
- 239000010410 layer Substances 0.000 description 85
- 238000003466 welding Methods 0.000 description 25
- 229910000975 Carbon steel Inorganic materials 0.000 description 12
- 229910045601 alloy Inorganic materials 0.000 description 12
- 239000000956 alloy Substances 0.000 description 12
- 239000007789 gas Substances 0.000 description 12
- 239000010962 carbon steel Substances 0.000 description 11
- 230000008878 coupling Effects 0.000 description 10
- 238000010168 coupling process Methods 0.000 description 10
- 238000005859 coupling reaction Methods 0.000 description 10
- 229920006254 polymer film Polymers 0.000 description 10
- 229930195733 hydrocarbon Natural products 0.000 description 8
- 150000002430 hydrocarbons Chemical class 0.000 description 8
- 239000007787 solid Substances 0.000 description 8
- 229910000990 Ni alloy Inorganic materials 0.000 description 7
- 239000012790 adhesive layer Substances 0.000 description 7
- 238000010438 heat treatment Methods 0.000 description 7
- -1 hydroxide ions Chemical class 0.000 description 7
- 230000008569 process Effects 0.000 description 7
- 239000004734 Polyphenylene sulfide Substances 0.000 description 6
- 238000005336 cracking Methods 0.000 description 6
- 239000000835 fiber Substances 0.000 description 6
- BASFCYQUMIYNBI-UHFFFAOYSA-N platinum Chemical compound [Pt] BASFCYQUMIYNBI-UHFFFAOYSA-N 0.000 description 6
- 229920000069 polyphenylene sulfide Polymers 0.000 description 6
- HCHKCACWOHOZIP-UHFFFAOYSA-N Zinc Chemical compound [Zn] HCHKCACWOHOZIP-UHFFFAOYSA-N 0.000 description 5
- 239000010935 stainless steel Substances 0.000 description 5
- 229910052725 zinc Inorganic materials 0.000 description 5
- 239000011701 zinc Substances 0.000 description 5
- 239000004411 aluminium Substances 0.000 description 4
- 229910052782 aluminium Inorganic materials 0.000 description 4
- XAGFODPZIPBFFR-UHFFFAOYSA-N aluminium Chemical compound [Al] XAGFODPZIPBFFR-UHFFFAOYSA-N 0.000 description 4
- 230000008901 benefit Effects 0.000 description 4
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- 238000001816 cooling Methods 0.000 description 4
- 238000005553 drilling Methods 0.000 description 4
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- 230000007246 mechanism Effects 0.000 description 4
- 238000002844 melting Methods 0.000 description 4
- 230000008018 melting Effects 0.000 description 4
- 239000000126 substance Substances 0.000 description 4
- 239000004215 Carbon black (E152) Substances 0.000 description 3
- PXHVJJICTQNCMI-UHFFFAOYSA-N Nickel Chemical compound [Ni] PXHVJJICTQNCMI-UHFFFAOYSA-N 0.000 description 3
- 239000004698 Polyethylene Substances 0.000 description 3
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 3
- 238000005253 cladding Methods 0.000 description 3
- 230000007423 decrease Effects 0.000 description 3
- 239000013505 freshwater Substances 0.000 description 3
- 238000003780 insertion Methods 0.000 description 3
- 230000037431 insertion Effects 0.000 description 3
- 150000002739 metals Chemical class 0.000 description 3
- 239000000203 mixture Substances 0.000 description 3
- 229910052697 platinum Inorganic materials 0.000 description 3
- 239000002861 polymer material Substances 0.000 description 3
- 229920000915 polyvinyl chloride Polymers 0.000 description 3
- 239000004800 polyvinyl chloride Substances 0.000 description 3
- 230000002829 reductive effect Effects 0.000 description 3
- 229910001220 stainless steel Inorganic materials 0.000 description 3
- 239000010936 titanium Substances 0.000 description 3
- 238000004804 winding Methods 0.000 description 3
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 2
- UQSXHKLRYXJYBZ-UHFFFAOYSA-N Iron oxide Chemical compound [Fe]=O UQSXHKLRYXJYBZ-UHFFFAOYSA-N 0.000 description 2
- 239000004696 Poly ether ether ketone Substances 0.000 description 2
- RTAQQCXQSZGOHL-UHFFFAOYSA-N Titanium Chemical compound [Ti] RTAQQCXQSZGOHL-UHFFFAOYSA-N 0.000 description 2
- 238000005299 abrasion Methods 0.000 description 2
- 239000008186 active pharmaceutical agent Substances 0.000 description 2
- 239000002313 adhesive film Substances 0.000 description 2
- 229920005601 base polymer Polymers 0.000 description 2
- 239000004020 conductor Substances 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 230000005611 electricity Effects 0.000 description 2
- 239000003792 electrolyte Substances 0.000 description 2
- 239000004744 fabric Substances 0.000 description 2
- 239000011152 fibreglass Substances 0.000 description 2
- 230000001965 increasing effect Effects 0.000 description 2
- 230000002401 inhibitory effect Effects 0.000 description 2
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- 230000036961 partial effect Effects 0.000 description 2
- 239000002245 particle Substances 0.000 description 2
- 239000012466 permeate Substances 0.000 description 2
- 229920002530 polyetherether ketone Polymers 0.000 description 2
- 229920000573 polyethylene Polymers 0.000 description 2
- 238000007789 sealing Methods 0.000 description 2
- 239000002356 single layer Substances 0.000 description 2
- 229910001256 stainless steel alloy Inorganic materials 0.000 description 2
- 239000000758 substrate Substances 0.000 description 2
- 239000004583 superabsorbent polymers (SAPs) Substances 0.000 description 2
- 229920001169 thermoplastic Polymers 0.000 description 2
- 229920001187 thermosetting polymer Polymers 0.000 description 2
- 239000004416 thermosoftening plastic Substances 0.000 description 2
- 229910052719 titanium Inorganic materials 0.000 description 2
- SMZOUWXMTYCWNB-UHFFFAOYSA-N 2-(2-methoxy-5-methylphenyl)ethanamine Chemical compound COC1=CC=C(C)C=C1CCN SMZOUWXMTYCWNB-UHFFFAOYSA-N 0.000 description 1
- NIXOWILDQLNWCW-UHFFFAOYSA-N 2-Propenoic acid Natural products OC(=O)C=C NIXOWILDQLNWCW-UHFFFAOYSA-N 0.000 description 1
- VYZAMTAEIAYCRO-UHFFFAOYSA-N Chromium Chemical compound [Cr] VYZAMTAEIAYCRO-UHFFFAOYSA-N 0.000 description 1
- 239000004593 Epoxy Substances 0.000 description 1
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 description 1
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 description 1
- 229920000877 Melamine resin Polymers 0.000 description 1
- ZOKXTWBITQBERF-UHFFFAOYSA-N Molybdenum Chemical compound [Mo] ZOKXTWBITQBERF-UHFFFAOYSA-N 0.000 description 1
- 239000002033 PVDF binder Substances 0.000 description 1
- 239000004952 Polyamide Substances 0.000 description 1
- 239000004642 Polyimide Substances 0.000 description 1
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 1
- UCKMPCXJQFINFW-UHFFFAOYSA-N Sulphide Chemical compound [S-2] UCKMPCXJQFINFW-UHFFFAOYSA-N 0.000 description 1
- PTFCDOFLOPIGGS-UHFFFAOYSA-N Zinc dication Chemical compound [Zn+2] PTFCDOFLOPIGGS-UHFFFAOYSA-N 0.000 description 1
- 239000012190 activator Substances 0.000 description 1
- 125000003118 aryl group Chemical group 0.000 description 1
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 1
- 230000004888 barrier function Effects 0.000 description 1
- 238000010923 batch production Methods 0.000 description 1
- 238000005452 bending Methods 0.000 description 1
- JUPQTSLXMOCDHR-UHFFFAOYSA-N benzene-1,4-diol;bis(4-fluorophenyl)methanone Chemical compound OC1=CC=C(O)C=C1.C1=CC(F)=CC=C1C(=O)C1=CC=C(F)C=C1 JUPQTSLXMOCDHR-UHFFFAOYSA-N 0.000 description 1
- 239000007767 bonding agent Substances 0.000 description 1
- 239000012267 brine Substances 0.000 description 1
- 238000006243 chemical reaction Methods 0.000 description 1
- 229910052804 chromium Inorganic materials 0.000 description 1
- 239000011651 chromium Substances 0.000 description 1
- 230000006835 compression Effects 0.000 description 1
- 238000007906 compression Methods 0.000 description 1
- 238000009792 diffusion process Methods 0.000 description 1
- 229920001971 elastomer Polymers 0.000 description 1
- 239000013536 elastomeric material Substances 0.000 description 1
- 230000003628 erosive effect Effects 0.000 description 1
- 238000007765 extrusion coating Methods 0.000 description 1
- 239000000945 filler Substances 0.000 description 1
- 239000000499 gel Substances 0.000 description 1
- 239000010439 graphite Substances 0.000 description 1
- 229910002804 graphite Inorganic materials 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- 239000001257 hydrogen Substances 0.000 description 1
- 229910001293 incoloy Inorganic materials 0.000 description 1
- 230000006698 induction Effects 0.000 description 1
- 239000003999 initiator Substances 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 229910052500 inorganic mineral Inorganic materials 0.000 description 1
- 229910052742 iron Inorganic materials 0.000 description 1
- 230000014759 maintenance of location Effects 0.000 description 1
- 238000005259 measurement Methods 0.000 description 1
- JDSHMPZPIAZGSV-UHFFFAOYSA-N melamine Chemical compound NC1=NC(N)=NC(N)=N1 JDSHMPZPIAZGSV-UHFFFAOYSA-N 0.000 description 1
- 239000007769 metal material Substances 0.000 description 1
- 239000011707 mineral Substances 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 229910052750 molybdenum Inorganic materials 0.000 description 1
- 239000011733 molybdenum Substances 0.000 description 1
- 238000012806 monitoring device Methods 0.000 description 1
- 229910052759 nickel Inorganic materials 0.000 description 1
- 230000003647 oxidation Effects 0.000 description 1
- 238000007254 oxidation reaction Methods 0.000 description 1
- 229910052760 oxygen Inorganic materials 0.000 description 1
- 239000001301 oxygen Substances 0.000 description 1
- 239000011236 particulate material Substances 0.000 description 1
- ISWSIDIOOBJBQZ-UHFFFAOYSA-N phenol group Chemical group C1(=CC=CC=C1)O ISWSIDIOOBJBQZ-UHFFFAOYSA-N 0.000 description 1
- 229920003229 poly(methyl methacrylate) Polymers 0.000 description 1
- 239000004584 polyacrylic acid Substances 0.000 description 1
- 229920002647 polyamide Polymers 0.000 description 1
- 229920001721 polyimide Polymers 0.000 description 1
- 230000000379 polymerizing effect Effects 0.000 description 1
- 239000004926 polymethyl methacrylate Substances 0.000 description 1
- 239000004810 polytetrafluoroethylene Substances 0.000 description 1
- 229920001343 polytetrafluoroethylene Polymers 0.000 description 1
- 229920002635 polyurethane Polymers 0.000 description 1
- 239000004814 polyurethane Substances 0.000 description 1
- 239000000047 product Substances 0.000 description 1
- 239000011253 protective coating Substances 0.000 description 1
- 230000001681 protective effect Effects 0.000 description 1
- 230000005855 radiation Effects 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 230000002441 reversible effect Effects 0.000 description 1
- 239000005060 rubber Substances 0.000 description 1
- 239000013535 sea water Substances 0.000 description 1
- 239000011734 sodium Substances 0.000 description 1
- 229910052708 sodium Inorganic materials 0.000 description 1
- 239000011780 sodium chloride Substances 0.000 description 1
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 1
- 239000007921 spray Substances 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
- 229910052717 sulfur Inorganic materials 0.000 description 1
- 125000004434 sulfur atom Chemical group 0.000 description 1
- 229920006305 unsaturated polyester Polymers 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/10—Setting of casings, screens, liners or the like in wells
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F16—ENGINEERING ELEMENTS AND UNITS; GENERAL MEASURES FOR PRODUCING AND MAINTAINING EFFECTIVE FUNCTIONING OF MACHINES OR INSTALLATIONS; THERMAL INSULATION IN GENERAL
- F16L—PIPES; JOINTS OR FITTINGS FOR PIPES; SUPPORTS FOR PIPES, CABLES OR PROTECTIVE TUBING; MEANS FOR THERMAL INSULATION IN GENERAL
- F16L58/00—Protection of pipes or pipe fittings against corrosion or incrustation
- F16L58/02—Protection of pipes or pipe fittings against corrosion or incrustation by means of internal or external coatings
- F16L58/04—Coatings characterised by the materials used
- F16L58/10—Coatings characterised by the materials used by rubber or plastics
- F16L58/1009—Coatings characterised by the materials used by rubber or plastics the coating being placed inside the pipe
- F16L58/1036—Coatings characterised by the materials used by rubber or plastics the coating being placed inside the pipe the coating being a preformed pipe
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/10—Setting of casings, screens, liners or the like in wells
- E21B43/103—Setting of casings, screens, liners or the like in wells of expandable casings, screens, liners, or the like
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/10—Setting of casings, screens, liners or the like in wells
- E21B43/103—Setting of casings, screens, liners or the like in wells of expandable casings, screens, liners, or the like
- E21B43/105—Expanding tools specially adapted therefor
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/10—Setting of casings, screens, liners or the like in wells
- E21B43/103—Setting of casings, screens, liners or the like in wells of expandable casings, screens, liners, or the like
- E21B43/108—Expandable screens or perforated liners
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F16—ENGINEERING ELEMENTS AND UNITS; GENERAL MEASURES FOR PRODUCING AND MAINTAINING EFFECTIVE FUNCTIONING OF MACHINES OR INSTALLATIONS; THERMAL INSULATION IN GENERAL
- F16L—PIPES; JOINTS OR FITTINGS FOR PIPES; SUPPORTS FOR PIPES, CABLES OR PROTECTIVE TUBING; MEANS FOR THERMAL INSULATION IN GENERAL
- F16L58/00—Protection of pipes or pipe fittings against corrosion or incrustation
- F16L58/02—Protection of pipes or pipe fittings against corrosion or incrustation by means of internal or external coatings
- F16L58/04—Coatings characterised by the materials used
- F16L58/10—Coatings characterised by the materials used by rubber or plastics
- F16L58/1009—Coatings characterised by the materials used by rubber or plastics the coating being placed inside the pipe
Definitions
- the invention relates to method and system for internally lining a tubing string to protect the tubing string against corrosion and/or leakage.
- casing is typically used to indicate a pipe string extending from surface into the wellbore
- liner may typically be used to indicate a pipe string which extends from a downhole location further down the wellbore.
- casing will be primarily used, but the invention is equally applicable to liner.
- the casing or liner strings may be designed to withstand a variety of forces, such as collapse, burst, and tensile failure, as well as chemically aggressive brines.
- the casing string is typically assembled from multiple interconnected pipe sections, having a length of for instance about 10 metres each. Casing connections connect adjacent pipe sections.
- the casing sections may be fabricated with male threads on each end, wherein shorter-length casing couplings with female threads are used to join the individual sections of casing together.
- pipe sections may be fabricated with male threads on one end and female threads on the other.
- Casing may be run to protect fresh water formations, isolate a zone of lost returns or isolate formation layers with significantly different pressure gradients.
- the operation during which the casing is put into the wellbore is commonly called “running pipe.”
- a wellbore may typically be provided with another tubing string, typically referred to as production string or production tubing.
- the production tubing may be assembled with other completion components to make up the production string.
- the production string is the primary conduit through which reservoir fluids are produced to surface.
- the production string is typically assembled with tubing and completion components in a configuration that suits the wellbore conditions and the production method.
- the tubing itself may be made up from interconnected pipe sections, in a similar fashion to the casing strings.
- An important function of the production string is to protect the primary wellbore tubulars, including the casing and liner, from corrosion or erosion by the reservoir fluid.
- Temperatures may range up to 175° C or more.
- Pressures may be as high as 1400 bars or more.
- the reservoir fluids may be highly corrosive, for instance due to the combination of hydrocarbons, C0 2 and/or H 2 S in the presence of water.
- the use of secondary and tertiary enhanced recovery methods in hydrocarbon production, such as gas injection, water flooding and chemical flooding, may further aggravate the situation.
- Pipe sections for wellbore tubulars including the casing or production tubular, are usually manufactured from plain carbon steel with varying compositions that is heat-treated to varying strengths.
- pipe sections may be specially fabricated of stainless steel, nickel alloys, aluminium, titanium, fiberglass and other materials .
- Carbon steel for instance is relatively inexpensive, but also more prone to corrosion than the other materials listed above.
- erosion-corrosion also known as impingement
- stress corrosion cracking also known as stress corrosion cracking
- sulphide stress cracking pitting
- galvanic corrosion including: erosion-corrosion (also known as impingement), stress corrosion cracking, sulphide stress cracking, pitting, and galvanic corrosion.
- Corrosion in metals may be caused by the flow of electricity from one metal to another metal or from one part of the surface of one piece of metal to another part of the same metal where conditions permit the flow of electricity. Further, a moist conductor or electrolyte must be present for this flow of energy to take place. Energy passes from a negative region to a positive region via the electrolyte media.
- Galvanic corrosion is quite prevalent and troublesome, occurring in a wide variety of circumstances. For example, coupling aluminium and iron pipe together will result in very rapid corrosion of the aluminium pipe section.
- the galvanic corrosion mechanism may be
- CRAs are increasingly more expensive. For instance, compared to API grade P110 carbon steel, the same pipe section made of CRA may be up to 5, 10 or even 25 times more expensive (when made of 316L, SM25CRW-110/125, or C22 CRA respectively) .
- CRA tubular such as stainless steel and nickel alloy.
- CRA tubular such as stainless steel and nickel alloy.
- insulating coatings may be applied.
- the coating In order for a coating to be used on tubular sections and threaded couplings to protect the metal substrate from corrosion, the coating must be resistant to attack and maintain its adherence to the metal substrate under the harsh downhole conditions referred to above.
- steel pipe is provided with a lining of corrosion-resistant material.
- arylene sulfide polymers have gained wide acceptance, see for instance US-3, 354, 129. Generally, these polymers consist of a recurring aromatic structure coupled in repeating units through a sulfur atom.
- Commercially available arylene sulfide polymers which have been used for coating oil and gas pipes and pipe couplings are polyphenylene sulfides .
- the polyphenylene sulfides used in oil and gas applications exhibit high melting points, outstanding chemical resistance, thermal stability and are non- flammable. They are also characterized by high stiffness and good retention of mechanical properties at elevated temperatures as well as the ability to deform smoothly, thereby, for example, preventing the galling of threads, even at high thicknesses.
- US-3,744,530 describes polyphenylene sulfide coated pipes, wherein the polyphenylene sulfide coating also contains a filler, such as iron oxide, in an amount of between 5% to 30%.
- connections where cracking may occur during assembly of the connection.
- polymeric coatings of threaded couplings are particularly prone to cracking due to the stresses imparted during assembly of connections.
- many polymers allow diffusion of hydrogen and other light hydrocarbons through the thickness of the coating or liner, thereby allowing gas to accumulate between layers, which, in the case of a corrosion resistant liner could result in collapse if the pressures in the bore and annulus become unbalanced.
- JP 60 109686 A (KAWASAKI HEAVY IND LTD) 15 June 1985 (1985-06-15) provides a pipe system for transport of corrosive fluids.
- the pipe system comprises a tubular member made of a corrosion prone metal.
- Each tubular member is provided with an inner lining of a corrosion resistant material.
- the tubular member and the inner lining are connected to a threaded coupling member, which is made of a corrosion resistant material.
- the tubular member and the liner are connected to the threaded coupling member by a weld seam.
- the welding of solid CRA couplings to a carbon steel pipe body, or the welding related method can cause issues in itself. See for instance the description of galvanic corrosion above.
- the cost saving from using clad steel rather than solid CRA is particularly valid when the total wall thickness of the pipe increases. When the product of outer diameter (OD) times wall thickness (T) decreases however, the cost benefit of corrosion
- chromium e.g. more than 10%
- molybdenum may exceed the price of carbon steel with a factor of about 20 to 30.
- Nickel alloys are often the material of choice in environments containing relatively large volumes of H 2 S. For instance when the
- H 2 S partial pressure exceeds 5 to 10 bars, nickel alloys may be required.
- polymeric coatings will be unsuitable when the partial pressures of either C0 2 , H 2 S and/or water exceed a certain threshold, as these materials may permeate through the polymeric coating, which may lead to corrosion of the carbon steel base material.
- the temperature range wherein polymeric coatings can be applied is typically limited to a maximum of about 100 to 150 degree C.
- US-2007/0095532 discloses an apparatus to deploy a patch comprising an inner metal tube and an outer resilient sealing member.
- the inner metal tube is formed from steel, preferably, carbon steel.
- the outer resilient sealing member is formed from an elastomeric material.
- the patch may be from 10 to 1000 feet in length.
- the length of the liner patch is inherently limited by the apparatus described.
- the liner patch is clamped by extending and retracting slips attached to the apparatus, so the weight of the liner patch is carried by the friction these slips exert on the liner.
- the force applied by these slips determines the frictional force.
- the extending and retracting slips will have insufficient capacity to support liner exceeding a certain length, such as several kilometres.
- the pressure that the slips can exert before deforming the liner is minimal, minimizing the friction force also.
- a thin liner is lighter than a thicker patch, the weight of the liner is still typically in the order of 1.3 kg/m. This would provide a total weight of several thousand kilograms if one would consider lining the production tubing along the length of the wellbore.
- the apparatus of US-2007/0095532 would be unsuitable to provide a liner patch to the entire inner surface of the production tubing. Furthermore, the apparatus of US-2007/0095532 is supported by a wireline which, in the configuration as disclosed, would have to travel through the liner. For longer lengths, the practicalities of threading several kilometres of wireline through the liner patch, while still supporting the weight of the liner by the wire line while running into the well, are unrealistic. This is supported by the exemplary length of liner patch as disclosed in US-2007/0095532, which is limited to 1000 feet (about 300 metres) .
- US-2010/0247794-Al wellbore tubing lining method wherein a polymer layer is cured downhole actinic radiation.
- the liner is introduced in the borehole via an apparatus attached to a wireline, which would than expand the liner via a vessel or bladder on a wire line.
- the bladder will inflate along the full length of the liner to expand the liner.
- the system is limited to the delivering of a polymer liner. Also, the system can only be applied for limited lengths.
- the fabrication of a bladder or vessel to expand the liner will inherently limit the length of the liner to be expanded. Providing a bladder which extends along the entire length of the production tubing will be impossible. Moreover, the necessity to run such a vessel into the hole will further limit the maximum length thereof.
- US-3785193 discloses a liner expanding apparatus and a method including lowering and affixing a liner by means of wireline. The liner is crimped onto an expansion tool, and hangs down from it. This configuration has similar limitations to patent documents US-2007/0095532 and US-
- a general problem with the known tubing lining systems and methods is that pockets of fluids may be trapped between the liner and tubing, which may result in detachment of the liner from the inner wall of the tubing and collapse of the liner.
- the present invention therefore provides a method for lining a tubing string, comprising; - inserting a folded liner having an outer surface which is at least partially coated with a fluid absorbing coating into the tubing string;
- the coating may comprise bonding and liquid absorbing additives, such as a sticky glue and a hygroscopic material, such as silicagel and/or a cross-linked acrylate polymer described in US patent 7,144,980, which is generally known as a Super Absorbent Polymer (SAP) or hydrogel, which absorbs any substantial pockets of water and/or other fluid trapped, and thereby enhances the bond, between the tubing string and the expanded liner.
- a sticky glue such as silicagel and/or a cross-linked acrylate polymer described in US patent 7,144,980, which is generally known as a Super Absorbent Polymer (SAP) or hydrogel, which absorbs any substantial pockets of water and/or other fluid trapped, and thereby enhances the bond, between the tubing string and the expanded liner.
- SAP Super Absorbent Polymer
- a system for lining a tubing string in a wellbore comprising a liner, which is configured to be folded in a collapsed state into the tubing string and to be unfolded against an inner surface of the tubing string and which is at least partially coated with a fluid absorbing coating that is configured to absorb fluid trapped between the inner surface of the tubing string and the expanded liner.
- the method and system according to the invention enable continuous cladding of a kilometres long oil and/or gas well tubing and/or casing string by a single thin foil corrosion resistant liner that may be coated with hygroscopic and sticky glue to enhance the bonding of the liner to, and inhibit corrosion and leakage of, the tubing and/or casing string.
- Fig. 1 shows a perspective view of separate layers of a liner according to the invention
- Fig. 2 shows a perspective view of separate layers of a liner according to the invention
- Fig. 3 shows a perspective view of an embodiment of a liner of the invention
- Fig. 4 shows a perspective view of an embodiment of a liner according to the present invention
- Fig. 5 shows a perspective view of another embodiment of a liner according to the present invention.
- Fig. 6 shows a perspective view of a practical embodiment of the liner of the invention
- Fig. 7 shows a perspective view of a reel comprising the liner according to the invention
- Fig. 8 shows a perspective view of a cross section of a tubular, which in a first step is provided with a liner according to the invention
- Fig. 9 shows a perspective view of a cross section of a tubular, which in a second step is provided with a liner according to the invention.
- Fig. 10 shows a perspective view of a cross section of a tubular, which in a third step is provided with a liner according to the invention
- Fig. 11 shows a schematic cross section of a wellbore provided with a liner according to the invention
- Figs. 12 to 19 show exemplary steps of various embodiments to fabricate the composite material of the invention
- Figures 20 and 21 show respective embodiments of methods to manufacture the composite liner of the invention
- Figures 22 to 24 show perspective views of respective methods to manufacture a pipe using the composite liner
- Figures 25 to 27 show cross-sectional views of respective methods to manufacture a pipe using the composite liner
- Figure 28 shows a cross-section of an embodiment of a liner of the invention arranged on wellbore tubing
- Figure 29 shows an exemplary graph of a signal to monitor integrity of the liner
- Figures 30 to 32 show consecutive steps in an embodiment of a process to fabricate a liner of the invention
- Figure 33 shows a cross section of an embodiment of a system of the invention for introducing a liner in a wellbore ;
- Figure 34 shows a perspective view of an embodiment of an expander for the system of the invention;
- Figure 35 shows a cross section of a wellbore provided with the system of the invention, as well as a step in introducing the liner in the wellbore;
- Figures 36 to 39 show consecutive steps of an exemplary method for lining a wellbore tubular
- Figure 40 shows a perspective view of an embodiment of a method of lining a wellbore tubing according to the invention.
- Figure 1 shows an embodiment of a composite material 10 suitable for manufacturing a thin foil liner according to the present invention.
- the composite material is
- first polymer layer 12 comprises a first polymer layer 12, a second polymer layer 14 and an intermediate metallic layer 16.
- a first adhesive layer 18 may be arranged between the first polymer layer and the metallic layer.
- a second adhesive layer 20 may be arranged between the metallic layer and the second polymer layer .
- the first and/or second polymer layer may be a layer consisting of a single polymer, or may itself be a composite layer.
- Each polymer layer may in fact include steel, carbon, or glass fibre wire and/or particles of a relatively hard material embedded in the polymer. Hard herein implies being harder or stronger than the polymer base material. The hard particulate material may serve for abrasion protection on the inner diameter of the composite liner of the invention.
- the respective layers of the composite material are bonded to each adjacent layer, forming a layer of assembled composite material 10 as shown in Figure 3.
- the assembled composite material may have any desirable form, such as a longitudinal strip.
- Figures 4 and 5 show different examples of a method to form the composite material into a tubular shape.
- Figure 4 shows the first polymer layer 12 formed into a tubular shape.
- the metal layer 16 is provided in the form of a longitudinal strip 22 and bend around the tubular first polymer layer 12. After bending, the sides 24 of the metal layer 16, which extend in axial direction, are connected to each, for instance by welding.
- the metallic layer 16 is provided in the form of longitudinal strip 22. Said strip 22 is helically wound around the tubular first polymer layer 12. The sides 24 of the strip 22 may be connected to each other, for instance by welding. Alternatively, the metallic layer may be glued to the polymer layer.
- the second polymer layer 14 is applied in a similar fashion, providing a longitudinal tube 30 made of the composite material 10, see Figure 6.
- tool 32 may be used to model the longitudinal tube 30 of composite material in a collapsed tubular 34, having a reduced outer diameter.
- the tool 32 may have created one, two or more longitudinal folds 36 extending in axial direction.
- Said collapsed composite tube may have any suitable length and can be arranged on a reel 40, see Figure 7.
- the composite material, or components thereof may be manufactures as a collapsed tubular, rather than in the round shape and subsequently folded.
- the collapsed tube 34 may be used to line a pipe 50.
- a first step (Fig. 8)
- the collapsed tube 34 is arranged within the pipe 50.
- a second step (Fig. 9)
- the collapsed tube 34 is expanded, to a tubular form 30 (Fig. 10) .
- a wellbore 60 may be provided extending into a formation 62 below ground level 64.
- the wellbore is typically provided with one or more tubular casings or liners, such as conductor pipe 66, intermediate casing 68 and production tubing 70.
- the production tubing is typically included in a production casing, which is not shown however to improve clarity.
- Produced hydrocarbons will be transported to surface via the inside of the production tubing 70. Consequently, the inner surface of the production tubing 70 may be exposed to varying quantities of C02 and H2S in the presence of water, all of which may be transported to surface together with the hydrocarbons.
- the collapsed tube 34 is unreeled and inserted though the production tubing.
- the tube 34 herein extends all the way to the downhole end 72 of the production tubing above a Side Sliding
- the collapsed tube 34 can for instance be inserted into the wellbore by connecting a weight to the downhole end thereof and lowering said weight in the wellbore until it reaches the bottom.
- the collapsed tube can be inserted in the wellbore by applying
- the collapsed tube 34 is expanded to its expanded state.
- the expanded tube 30
- a problem with conventional cladding concepts is the continuity of the cladding layer, especially at the locations of the connections between respective tubular sections.
- the composite liner of the invention can be made in a factory and consequently the continuity can be thoroughly inspected on surface before installation in the wellbore.
- the outer diameter of the composite liner may be provided with protection means to protect against damage during running, installation or bonding to the inner surface of the wellbore tubing.
- Said protection means may include wires comprising a relatively damage resistant material arranged on the outer diameter of the composite liner.
- the damage resistant material may include one or more of steel, carbon, or glass fibre wires.
- the collapsed tube 34 can be expanded in a number of ways.
- the tube 34 can for instance be inflated with a pressurized fluid in its interior.
- the downhole end of the tube 34 is closed before inserting it in the wellbore. After insertion, the surface end is cut off, whereafter the pressurized fluid is introduced to inflate and expand the liner.
- an expander cone 74 having a largest outer diameter which is substantially similar to the inner diameter of the tubing 70, can be pushed or pulled through the collapsed tube 34 to expand it.
- the expander can be moved from surface towards the downhole end 72 by pumping a pressurized fluid to push the expander.
- an expander cone 74 can be pulled to surface to expand the tube 34.
- a string such as a coiled tubing string or a wireline, may have been integrated within the composite tube 30 during manufacturing thereof (not shown) .
- the expander 74 may be attached to an end of said string or wireline before inserting the composite liner in the wellbore.
- the expander may, for instance in a collapsed form, be lowered in the wellbore together with the liner.
- the expander cone When the composite liner is in the correct position, the expander cone may be transferred to its expanded form and pulled to surface using said string or wireline .
- the expander can be propelled to surface using hydraulic pressure generated by reverse circulating the well.
- the expanded composite liner 30 may stick to the inner surface of the tubing 70 by various means.
- the outer surface of the composite liner may have been provided with an adhesive layer. Said adhesive layer may be applied to the outer surface of the composite liner
- an adhesive applicator device 76 which may include a spraying device or a roller for applying the adhesive.
- Said adhesive may include a heat activated adhesive, which can be activated by introducing heated fluid into the wellbore or even by the elevated temperature in the wellbore, which as mentioned before are frequently in excess of 175° C.
- an activator which will activate the adhesive can be injected in the drilling fluid. As shown in Figure 12, in a first step of an
- strips of the first polymer layer 12, the metallic layer 16 and the second polymer layer 14 are arranged on top of each other.
- the adhesive layers 18, 20 are interposed as shown in Figure 2.
- the assembly of the stacked strips is folded in a tubular form along the length thereof, as shown in Figure 4, until the opposite longitudinal sides 24, 25 of the metallic layer 16 and the opposite longitudinal sides
- opposite longitudinal sides 84, 85 of the second polymer layer leave a longitudinal opening 86 in between them, exposing the abutting sides 24, 25 of the metallic layer.
- the opening 86 may for instance expose about 1 to 20 mm, for instance about 10 mm, of the metallic strip on each side of said abutting sides 24, 25.
- the sides 24, 25 of the metal layer 16 will be joined by welding (schematically indicated by flash 88), for instance using arc welding or laser welding or a combination of these two welding techniques, producing weld 90.
- the first polymer layer 12 may be heated simultaneously to a temperature exceeding the melting point of the respective polymer material by the heat produced while welding the metal layer, leading to polymer weld 92.
- mechanical force may be applied to ensure both sides 24, 25 are engaged during the welding process.
- an additional polymer strip 94 will be inserted in the opening 86, using a mechanical system.
- Said mechanical system may for instance include a roller 96.
- heat can be applied using a heat source 98 such as hot dry air, infrared, or microwave (Fig. 15) .
- sides 24, 25 of the metallic layer are engaged in a butt joining (Fig. 16) or lap joining (Fig. 17) fashion.
- openings 86, 100 expose both the outside surface and the inside surface of said sides 24, 25 respectively, which are subsequently joined using welding techniques, such as the techniques mentioned above, creating weld 90 (Fig. 18) .
- the openings 86, 100 are provided, for instance filled or spray coated, with polymer strips 94, 102 respectively, as described above.
- An attachment device 104 may ensure bonding of the strip 102 to the metallic layer 16.
- the liner may be fabricated as a composite strip, which can be made by the following processes:
- the first and/or second polymer layers can be applied only one side in composite strip manufacturing process stage.
- the application of Polymer layer for the other side can be applied in following pipe manufacturing processes .
- adhesives can be added.
- the polymer film can fully or partially cover each side of the metal strip according to the joining method of both longitudinal sides of the metal strip to make a pipe .
- the composite strip can be made into a strip coil or continuously be connected to next step, pipe
- Fig. 20 shows first polymer film roll 112, second polymer film roll 114, metallic strip roll 116, and the optional first adhesive film roll 118 and second adhesive film roll 120.
- the respective films are unrolled and jointly transferred through heating device 122.
- the heating device 122 comprises for instance an induction heater, infrared (IR) heater elements, microwave heating elements, or ultraviolet (UV) heating elements.
- the films may be jointly led past
- the bonded films are cooled by cooling device 126, for instance by spraying a substance 128 such as compressed air or water.
- the bonded strip of composite liner is rolled onto composite liner roll 130.
- Fig. 21 shows another embodiment, wherein metallic strip roll 116 is unrolled.
- Adhesive coating devices 138, 140 subsequently apply the first adhesive layer 18 and the second adhesive layer 20, for instance by spraying.
- polymer coating devices 132, 134 apply the first polymer layer 12 and the second polymer layer 14, for instance by spraying.
- the assembled composite material 10 may subsequently be transferred through heating device 122, led past compressive rollers 124, and cooled by cooling device 126.
- the bonded strip of composite liner is rolled onto composite liner roll 130.
- Figure 22 shows an embodiment of a composite pipe manufacturing process.
- the composite liner roll 130 is unrolled.
- a strip of the composite liner material 10 is fed to a number of rollers 140-158, which continuously form and bend said strip 10 in a tubular form 30, or maintain said tubular form.
- rollers 152 and 140-158 are arranged in between rollers 152 and 154.
- Tool 32 collapses the tube to a collapsed tubular 34, having a reduced outer diameter and longitudinal folds 36.
- the collapsed composite tube 34 is subsequently arranged on the reel 40.
- the first polymer film roll 112 is unrolled, providing the first polymer film 12.
- the rollers 140-158 form and bend the first polymer film 12 in tubular form, and the opposite sides 80, 81 of said film are bonded, for instance by welding as indicated by flash 88.
- a strip of metallic layer 16 is applied, by helically winding said strip around the tubular first polymer layer 12.
- the second polymer layer 14 is applied by the polymer coating device 132.
- the assembled composite tube 30 is led past heating device 122 to improve bonding between the respective layers and past cooling device 126 for cooling.
- the composite tube 30 is collapsed and arranged on the reel 40 (not shown) .
- the roll 130 is unrolled, providing a strip of composite liner material 10.
- the rollers 140-158 bend said strip in tubular form.
- the opposite sides of the strip, including all its respective layers, are bonded by welding 88.
- the composite tube 30 is collapsed and arranged on the reel 40 (not shown) .
- the strip of composite material 10 can make it through the following steps:
- Batch 1 process from a) to d) ;
- Figure 25 shows the welding of opposite sides 24, 25 of the metal layer 16 by fusion welding.
- the first polymer layer 12 is heated to a temperature exceeding the melting temperature of the polymer by the heat of the fusion welding, so that its sides 80, 81 are
- Figure 26 shows the bonding of the sides 24, 25 of the metal layer 16 by fusion welding.
- the first polymer layer 12 is heated to a temperature exceeding the melting temperature of the respective polymer by fusion welding heat, and its sides 80, 81 are simultaneously joined during welding of the metal layer.
- the uncovered part 86 of the outer surface of the metal layer 16 is covered by a coating of a polymer or by attaching of polymer film 94. Subsequently, the area covered by the polymer strip or coating 94 may be cooled followed by heating.
- Figure 27 shows the bonding of the sides 24, 25 of the metal layer 16 by laser welding.
- the polymer material of the second polymer layer 14 is transparent for the laser beam, and is not heated by the laser beam.
- the sides of the inner and outer polymer layers are heated by heat transferred from the metal layer, and bond as a result.
- the composite material of the present invention comprises a single combination of polymer-metal-polymer layers .
- the composite material may have a total thickness in the range of about 150 um to about 2 mm, typically about 1 mm or less.
- Each polymer layer in the polymer-metal-polymer composite material may be the same.
- the first and second polymer layers have a thickness in the range of about 50 um to 500 ⁇ .
- the polymer layers may comprise a base polymer selected from the group of thermoplastics such as PEEK
- PVDF Polyvinylidene fluoride
- PA polyamide
- PVC Polyvinyl chloride
- thermoset plastics such as expoxy, phenolic, melamine, unsaturated polyester, and
- Said base polymer may comprise a
- the reinforcement which may be a mixture of one or more of: short carbon fibre, PTFE, Graphite, nano oxide particle having a diameter below 20 nm.
- the blend may comprise additives to improve bonding with the reinforcement.
- the metal layer may have a thickness in the range of 50 um to 500 um.
- the metal may comprise one or more of aluminium (Al) alloy, nickel (Ni) alloy, titanium (Ti) alloy, stainless steel. To improve the bonding with the polymer layers, if necessary, chemical treatment may be applied .
- De-bonding is a major problem for conventional polymer clads in general.
- Well fluids may permeate into the polymer clad and expand when the well cycles to a lower pressure, thus pushing the clad away from the wall of the carbon steel base pipe. This problem is
- the composite liner of the present invention specifically prevented in the composite liner of the present invention, by including an impermeable metallic layer, preferably made of corrosion resistant alloy, between the wellbore fluids and the bonding agent on the outer diameter of our composite liner clad. Also, the de- bonding problem can be prevented on the inner diameter of the metallic layer, by making the polymer layer on that side (e.g. the first polymer layer) fully permeable, thus preventing pressure build-up.
- an impermeable metallic layer preferably made of corrosion resistant alloy
- Electrical circuit 200 may include electrical wires 202, 204 and electrical measurement device 206.
- the device 206 may be a volt meter, a current meter, or a resistivity meter.
- Fig. 29 shows an exemplary output of the monitoring device 206 (y-axis) in time (x-axis) .
- the liner 34 is properly applied to the tubing
- the output signal 210 of meter 206 will be within a predetermined bandwidth.
- An average value 212 of the signal will be substantially constant.
- an electrically conducting fluid 214 such as brine or water, may allow electrical contact between the metallic layer 16 of the liner and the wellbore tubing 70. Due to the electrical contact, indicated by event 216 in Fig. 29, the average value of the signal 210 will decrease, indicating liner failure to the wellbore staff at surface. In case of liner failure, the operation of applying a liner to the wellbore tubing may be repeated, providing a second layer of liner 34 to the inner surface of the tubing to restore corrosion resistivity.
- a liner may be
- the material may be a composite material as described above, a single layer metallic material, a single layer polymer material, or any combination thereof.
- the liner 220 may be provided as a sheet material 222 in a first step, shown in Fig. 30.
- opposite sides 224, 226 of the sheet material 222 may be bend upwards and toward each other, indicated by arrows 228 and 230.
- Interconnecting may be done by welding, by welding device 232.
- the resulting liner shown in Fig. 32, may be flat.
- the liner 220 as shown in Fig. 32 can be reeled. The reel
- 130 may be ready for transport to a wellbore.
- FIG. 33 An embodiment of application of the liner in a wellbore is shown in Fig. 33.
- the reel 130 comprising the reeled liner 220 is arranged on a drilling rig 240.
- an end of the liner 220 is provided with a plug 244.
- the plug 244 has a dimension
- the liner will be arranged on the inner surface of the production tubing 70.
- the production tubing is arranged within a production casing 69.
- the plug 244 will substantially plug the inner fluid passage of the production tubing 70.
- the plug 244 having the liner 220 attached to it, is introduced in the top end of the wellbore tubular 70 (Fig. 33) .
- a folding unit 246 is installed (Fig. 33) .
- Said folding unit may comprise one or more rollers 248 for folding the liner 220 in a predetermined form.
- Said predetermined form may be a C-shape in cross- section .
- the plug 244 including the folded liner 250 which is attached to it, is pumped downhole.
- a fluid such as water or drilling fluid, may be pumped into the wellbore tubular 70 via inlet 252.
- Any fluid below the plug 244 can be pumped out of the wellbore via the annulus 254 between the tubing 70 and casing 69, and via outlet 256 ( Figures 33 and 35) .
- the liner 220 is fixed at surface and the folding assembly 246 is removed.
- the liner 220 is then cut at surface, creating a free uphole end 262.
- the uphole end 262 of the liner is opened.
- the open end 262 is fixated using suitable connecting means 264.
- an expander tool 270 is introduced in the open uphole end 262 of the liner 220.
- the expander tool 270 may be pumped into the liner 220 to unfold the liner and press the unfolded liner in engagement with the inner surface of the wellbore tubing 70 (Fig. 37) .
- the expander tool may have a front section 272 providing a nose or tip to guide the expander through the liner.
- a middle section may be provided with a ridge 274 having a diameter close to the inner diameter of the wellbore tubing 70.
- the ridge diameter may for instance be in the range of about 99% to 99.9% of the inner diameter of the wellbore tubing.
- An aft end 276 may have a smaller diameter, to allow retrieval of the expander tool .
- the expander may be retrieved to surface after expansion the liner.
- the aft end 276 of the expander tool may be attached to wireline to retrieve the tool.
- the expander may be collapsible to simplify the retrieval.
- seals may be applied to the liner at selected locations along the liner (Fig. 38) .
- one or more seal rings 280 may be introduced in the wellbore tubing 70 and positioned at preselected locations along said tubing.
- a seal ring 280 may be positioned at or near the downhole end 260 of the wellbore tubing.
- Another seal ring may be positioned at a top end of the liner.
- the one or more seal rings 280 will provide an additional barrier, preventing wellbore fluids from entering between the liner 220 and the inner surface of the wellbore tubing 70.
- the expander may expand the one or more seal rings 280 at their respective locations.
- the expanded seal ring 280 will be forced into the wellbore tubing, creating a seal section 282 due to internal compressive residual stresses (Fig. 39) .
- the latter may be regarded as autofrettage, a metal
- the liner can be pumped downhole relatively easily, as described above.
- the liner is relatively thin, for instance 1 mm or less.
- the thickness of the liner may be in the range of about 200 to 800 ⁇ , for instance about 0.5 mm.
- the folded liner 250 will, as a result, have a diameter much smaller than the inner diameter (ID) of the wellbore tubular.
- ID inner diameter
- the folded liner 254 by comparison may, in its collapsed state, have a diameter of less than 3 inch (7.5 cm), for instance 2 to 3 inch (5 to 7.5 cm) . Engagement between liner and tubing 70 is minimal as a result. Friction is therefore also relatively low, allowing easy run in of the liner.
- Fig. 40 shows a drilling site 300.
- a truck 302 carrying a reel 130 and corresponding reeling mechanism 304 is arranged at the site 300.
- the liner 220 is unreeled in a flat form 306 and guided along a guiding structure 308 into the wellbore 310.
- Folding mechanism 246 folds the liner into a C-shape 312.
- the C-shaped liner is introduced in the wellbore tubing 70.
- the liner 220 may expand in shape.
- the liner may expand from a partially expanded shape 314 to a tubular shape 320.
- the expansion process may partially occur by elasticity of the liner.
- the liner may be expanded by introducing pressurized fluid and/or by moving an expander through the liner, as described above.
- the liner of the present invention may be any liner suitable for a particular downhole conditions.
- the liner may have one or more metallic layers.
- the one or more metallic layers may be combined with one or more
- polymeric layers as described above.
- the one or more polymer layers may be applied to the one or more metallic layers in any suitable way, for instance by spray coating or extrusion coating.
- spray coating or extrusion coating The above described embodiments herein provide examples, but alternative methods to fabricate the liner may be used as well.
- the liner material of the present invention and its application for lining tubing in a wellbore provides a relatively low cost option while providing the superior corrosion resistance properties of high-performance steel or solid CRA tubing.
- the liner material can applied to the tubing after installation thereof in the wellbore, the inner surfaces of the threaded connectors between pipe sections will also be effectively protected against corrosion. The latter allows the use of conventional, relatively low-cost threaded connectors, such as API approved carbon steel connectors.
- Cost saving on production tubing may exceed 80%.
- the added liner is relatively thin, thus minimally limiting the inner diameter of the borehole. The invention allows the rehabilitation of older wells in case of souring, increase in water cut, etc.
- an system according to the invention may be used to insert a kilometres long corrosion and leak inhibiting liner downhole along at least a substantial part of the length of an oil and/or gas production tubing from just above a Sliding Side Door (SSD) or Side Pocket Mandrel (SPM) to just below a Sub Surface Safety Valve (SSSV) .
- the unlined upper and lower sections of the production tubing string above the SSSV and below the SSD and/or SPM may be made of a Corrosion Resistant Alloy (CRA) .
- CRA Corrosion Resistant Alloy
- the expander for expanding and unfolding the liner may not be attached to a wireline or Coiled Tubing (CT) assembly but may be delivered to the bottom of the tubing string by the liner itself.
- CT Coiled Tubing
- the driving force for pushing the expander up through the tubing string may be hydraulic pressure from circulating the well via the annular space between the tubing string and surrounding well casing.
- the liner expander may be designed to self adjust its outer circumference to variations in the internal width of surrounding tubing string. Because the tubing string is not plastically deformed, the variations from
- This may be achieved by using a leaf spring and/or by a rubber expander.
- the expander may also be configured to preserve a residual compression force between the expanded liner and surrounding tubing string after expanding the liner, to ensure that despite elastic relaxation and spring back in the liner, a mechanical interference fit is achieved without plastically deforming the surrounding tubing string .
- the top seal will be set at surface, also in a special tubing joint intended for this purpose. If the liner is installed within a vertical or inclined tubing or casing string the liner may be provided with metal to metal seals surrounding an upper end and a lower end of the liner to ensure no production fluid can enter between the production tubing and the liner. The lower end seal may be locked to a locking joint in the tubing string.
- the corrosion resistant liner may be manufactured from a Corrosion Resistant Alloy (CRA), such as nickel alloy C22, as a kilometres long flattened tube with a wall thickness between 0.3 and 0.7mm.
- CRA Corrosion Resistant Alloy
- the curved inner surfaces of the flattened and folded liner may be provided with a gel or thick oil dope to prevent collapse of curves and creation of vertical leak paths.
- Protective coatings with thicknesses of a number of micrometres such as an abrasion resistant layer on the inside of the liner to protect it against wireline interventions and the fluid adsorbing coating on the outside, may be applied during manufacture and before folding of the liner and storage of the folded and flattened liner on a reeling drum.
- the fluid absorbing coating will swell on contact with water and/or other fluids trapped between the expanded liner and tubing string and thereby absorb any free water which might remain in the annulus between the liner and the surrounding tubing or casing string, and to prevent any detachment of the liner from the surrounding liner and creation of leak paths.
- Removal of water and other liquid pockets from the residual space between the expanded liner and a vertical or inclined tubing string is particularly relevant, since even isolated and both axially and circumferentially spaced small pockets of water and/or other liquids may, assisted by vibration and temperature fluctuations, slowly migrate downwards and coalesce into larger water and/or liquid pockets that may entirely circumvent a lower part of the liner and result in liner collapse and/or its detachment from the tubing.
- isolated gas pockets may accumulate in a similar manner and migrate as enlarged, optionally annular, gas pockets upwardly towards an upper end of the tubing string.
- the fluid absorbing coating may comprise a cross- linked acrylate polymer, which is generally known as a Super Absorbent Polymer (SAP) or hydrogel or, in dry state, as "slush powder", which can absorb an amount of fresh water of up to 500 times of its own weight in fresh water, and an amount of mildly saline water of up to 50 times of its own weight.
- SAP Super Absorbent Polymer
- slush powder which can absorb an amount of fresh water of up to 500 times of its own weight in fresh water, and an amount of mildly saline water of up to 50 times of its own weight.
- SAPs Super Absorbent Polymers
- This SAP is the most common type of SAP made today.
- the fluid absorbing coating may also comprise a sticky glue and/or other adhesive to firmly bond the liner to the tubing or casing string and further inhibit collapse and/or detachment of the thin foil liner from the surrounding tubing or casing string.
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- General Engineering & Computer Science (AREA)
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- Physics & Mathematics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
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- Laminated Bodies (AREA)
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Abstract
Description
Claims
Priority Applications (9)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
CN201711399477.1A CN108662355B (en) | 2014-02-27 | 2015-02-27 | Method and system for lining a pipe |
CN201580010632.9A CN106104135B (en) | 2014-02-27 | 2015-02-27 | For the lined method and system of pipe |
CA2938915A CA2938915C (en) | 2014-02-27 | 2015-02-27 | Method and system for lining a tubular |
US15/121,468 US10316628B2 (en) | 2014-02-27 | 2015-02-27 | Method and system for lining a tubular |
GB1613468.6A GB2539816B (en) | 2014-02-27 | 2015-02-27 | Method and system for lining a tubular |
BR112016019679-1A BR112016019679B1 (en) | 2014-02-27 | 2015-02-27 | method and jacket for laying a column of pipe |
AU2015222095A AU2015222095B2 (en) | 2014-02-27 | 2015-02-27 | Method and system for lining a tubular |
AU2017225087A AU2017225087B2 (en) | 2014-02-27 | 2017-09-07 | Method and system for lining a tubular |
US16/397,861 US10858918B2 (en) | 2014-02-27 | 2019-04-29 | Method and system for lining a tubular |
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US11578536B2 (en) | 2018-12-04 | 2023-02-14 | Sandvik Mining And Construction Oy | Apparatus for feeding tube elements, rock drilling rig and method of supporting drill hole openings |
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Also Published As
Publication number | Publication date |
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GB2539816A (en) | 2016-12-28 |
AU2015222095A1 (en) | 2016-08-18 |
CN108662355A (en) | 2018-10-16 |
AU2017225087A1 (en) | 2017-09-28 |
US20160362968A1 (en) | 2016-12-15 |
GB2539816B (en) | 2020-08-19 |
AU2017225087B2 (en) | 2019-04-18 |
CN108662355B (en) | 2024-03-19 |
US10316628B2 (en) | 2019-06-11 |
CA2938915C (en) | 2022-11-15 |
CN106104135B (en) | 2018-03-02 |
AU2015222095B2 (en) | 2017-06-15 |
CA3171397A1 (en) | 2015-09-03 |
US10858918B2 (en) | 2020-12-08 |
CA2938915A1 (en) | 2015-09-03 |
US20190257180A1 (en) | 2019-08-22 |
BR112016019679B1 (en) | 2021-02-17 |
CN106104135A (en) | 2016-11-09 |
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