EP1721059A1 - Suppression de la communication d'un fluide vers et a partir d'un puits de forage - Google Patents

Suppression de la communication d'un fluide vers et a partir d'un puits de forage

Info

Publication number
EP1721059A1
EP1721059A1 EP05707992A EP05707992A EP1721059A1 EP 1721059 A1 EP1721059 A1 EP 1721059A1 EP 05707992 A EP05707992 A EP 05707992A EP 05707992 A EP05707992 A EP 05707992A EP 1721059 A1 EP1721059 A1 EP 1721059A1
Authority
EP
European Patent Office
Prior art keywords
wellbore
fluid
polymer
interface
particles
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP05707992A
Other languages
German (de)
English (en)
Inventor
Jan Dirk Bossaerts
Gerbrand Jozef Maria Van Eijden
Marc Jozef Rans
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell Internationale Research Maatschappij BV
Original Assignee
Shell Internationale Research Maatschappij BV
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Shell Internationale Research Maatschappij BV filed Critical Shell Internationale Research Maatschappij BV
Priority to EP05707992A priority Critical patent/EP1721059A1/fr
Publication of EP1721059A1 publication Critical patent/EP1721059A1/fr
Withdrawn legal-status Critical Current

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/5086—Compositions based on water or polar solvents containing organic compounds macromolecular compounds obtained otherwise than by reactions only involving carbon-to-carbon unsaturated bonds
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/512—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
    • E21B33/138—Plastering the borehole wall; Injecting into the formation

Definitions

  • the present invention relates to a method for suppressing fluid communication to or from a wellbore in a subsurface earth formation, and to a well fluid for use in a wellbore.
  • the fluid produced from hydrocarbon oil or gas wells often comprises substantial amounts of water.
  • the term water shall be used to also include brine.
  • the source of the water can be formation water breakthrough from formation layers adjacent the hydrocarbon carrying layers, or breakthrough of water injected into the formation from surface.
  • Water in the produced fluid reduces the lift capacity of the oil or gas well, and once produced the water becomes an environmental problem.
  • the water concentration of the produced fluid increases with the age of the well, and at some stage it is then desired to treat the well so that less water is produced.
  • a similar task is the suppression of fluid communication through fractures in the formation surrounding the wellbore.
  • Fractures can lead to undesired loss of drilling fluid into the surrounding formation so that it can be needed to seal fluid communication through the fractures.
  • Other situations in which it can be desired to suppress fluid communication downhole are encountered in leaking well casings, e.g. when there are cavities behind casing, or when there are voids or annuli between the metal casing and the surrounding cement. Such situations will be referred hereafter to as cement irregularities.
  • the subsurface formation is formed of plurality of stacked oil-bearing layers, and the wellbore extends through the formation with perforations arranged in all oil-bearing layers .
  • One mechanical option would be to install a selective well completion with multiple zones. This would imply that first the existing completion, i.e. the assembly of downhole tubulars and equipment has to be removed. Thereafter a selective completion would have to be installed in which all the relevant layers are isolated by packer elements, so that production from either of these zones can be controlled by valves.
  • Another conventional mechanical option would be to cement in a liner over the existing perforations to shut off fluid communication between all perforations and the wellbore, followed by re-perforating the hydrocarbon- bearing zones. Again, this would require removal of the existing completion.
  • European patent application with publication No. EP 1369401 discloses a sealing composition for use in a wellbore, which composition comprises water, cementitious material, and water-soluble cross-linkable material such as 2-hydroxyethyl acrylate monomer or a copolymer of acrylamide and t-butyl acrylate.
  • a sealing composition is able to withstand much higher differential pressure (maximum flowback pressure) than conventional cement.
  • the composition could be introduced through the existing completion into the wellbore.
  • the cross-linkable material penetrates with the water some distance into the formation surrounding the wellbore and cross—links there.
  • the cement stays at the interface with the wellbore and is allowed to set there.
  • the known sealing composition is relatively difficult to prepare and handle and requires special expertise in the operation. Cement can for example set in the tubing or wellbore under the influence of wellbore fluids or local hot spots in the well, and removing set cement in the coiled tubing or production tubing is very costly. Further, after the cement injection excess cement needs to be circulated out with viscous brine. This will expose the entire well completions to this brine-cement mixture potentially contaminating vital parts in the well like lift gas valves and side pocket mandrels.
  • US patent specification 3 525 398 describes a process for sealing a fracture in a permeable formation wherein a thixotropic liquid suspension of a particulate deformable solid resin is injected into the fracture, and wherein deformation of the particles is caused by pressure to form a substantially impermeable barrier in the fracture.
  • Another physical process for providing a liquid seal in a fracture is known from US patent specification 3 302 719, wherein solid polymer/wax/resin particles are injected to form a temporary plug during fracturing, which can subsequently be dissolved by formation hydrocarbon.
  • Yet another physical process to provide a subsurface liquid seal is known from International Patent Application Publication No.
  • WO 01/74967 wherein a gel- forming polymer is injected to a lost circulation zone and allowed to swell there. It is an object of the present invention to provide an improved method for suppressing fluid communication between a wellbore and a surrounding earth formation. It is a further object to provide a special well fluid suitable to be used in this improved method.
  • a method for suppressing fluid communication to or from a wellbore in a subsurface formation comprises: providing a well fluid which comprises solid particles in a carrying fluid, which solid particles include a reactive polymer; introducing the well fluid into the wellbore so that carrier fluid passes through an interface between the wellbore and its surroundings, wherein particles are accumulated at the interface; and allowing the polymer to form a solid plug suppressing fluid communication through the interface.
  • a well fluid for use in a wellbore which well fluid comprises solid particles in a carrying fluid, which solid particles include a reactive polymer.
  • the invention further relates to the use of this well fluid in a wellbore, in particular for suppressing fluid communication at an interface.
  • the present invention is based on the insight gained by Applicant that solid polymer particles in a carrier fluid form a particularly easy to handle sealing composition for use in a wellbore.
  • a standard gravel pack mixing unit will be sufficient for preparation of the well fluid.
  • No special cement mixers and pumps are necessary like in the preparation of complex multi- component components cement mixtures.
  • No dusty components are present and the invention therefore provides a much safer system for the operator.
  • the term polymer plug includes layers of polymer that are formed along the interface.
  • the reactive polymer is allowed to react in order to form the solid plug. Suitably the polymer plug cannot be dissolved by reservoir fluids.
  • Polymer plugs formed from reactive polymers can handle much higher differential pressures than conventional sealing systems, e.g. 21 MPa and more.
  • the mechanical properties of the polymer this could be as high as 50 MPa or even more, based on unconfined compressive strength of the polymer.
  • carrier fluid brine or a hydrocarbon liquid such as diesel oil can be used for example.
  • the particles are solid and suitably non-sticky at surface conditions. Chemical and physical properties can be tailor-selected for a specific application.
  • the particles contain at least 50 wt% of polymer or polymer composition, more preferably at least 90 wt%, most preferably they consist only of polymer or polymer composition.
  • the carrier fluid will be squeezed into the formation so that the solid particles are accumulated at the interface.
  • the size of the particles is preferably selected such that they reach the interface but do not significantly enter the formation, suitably less than 10 cm, preferably less than 2 cm, typically about 1 cm or less.
  • the particles When the interface is formed by a perforation from the wellbore into the formation, the particles have suitably a smallest linear dimension in the range between 1 mm and 2 cm.
  • the smallest linear size is suitably between 500 micron and 2 cm.
  • particles are suitably smaller, in the range of 1-200 micron.
  • the shape of the particles can also be suitably selected, e.g. generally spherical, cylindrical, or cubical but also irregular.
  • the particles are accumulated at the interface and, unlike the water-soluble cross-linkable material of the prior art sealing compositions do not penetrate in the formation so that after curing a solid layer or plug is formed directly at the interface.
  • a solid layer at the interface has the advantage that fluid communication can straightforwardly and selectively be restored again if desired by standard perforation techniques. Otherwise, i.e. if the seal was formed some distance into the formation, re-perforating could become a problem.
  • Another advantage of the solid layer at the interface is that the risk that producable hydrocarbons are locked in place is eliminated.
  • reactive polymer particles known curable polymers or polymer composition can be used, e.g.
  • the curable composition comprises at least two different compounds, e.g. a reactive polymer chain and a cross-linking agent or hardener, which compounds react, often cross-link to form a (cross-linked) polymer network.
  • Each reactive polymer particle suitably contains both compounds .
  • the temperature at the interface is generally higher than the temperature at surface.
  • a typical temperature of oil-bearing reservoir layers is between 110 and 180 degrees, e.g. 150 degrees Centigrade.
  • a reactive polymer can be allowed to react simply by subjecting it to the temperature at the interface for a sufficiently long period of time, e.g. 1-24 hours.
  • Cross-linking occurs suitably both intra-particle and inter-particle so that a macroscopic seal structure is formed.
  • a cooling fluid into the wellbore prior to introduction of the reactive polymer particles, e.g. to lower the temperature in the wellbore near the interface to be sealed by 20-50 Kelvin.
  • Another option with reactive polymers would be to select them such that additional heating above the formation temperature at the interface is required in order for the reaction to occur.
  • a suitable heater such as an electrical heater on wireline can be used in the wellbore in order to allow the reaction to take place.
  • a pre-flush of the interface with a heating liquid such as hot brine could be used to locally and temporarily heat up the formation.
  • the relative density of the polymer particles and the carrier fluid can be selected such that the density of the particles is about equal, or higher, or lower than that of the carrier fluid. Densities at ambient temperature can suitably be 500 kg/rn ⁇ or higher, but not exceeding 1500 kg/m 3 . At equal densities particles will float in the liquid so that a relatively stable suspension is obtained which can easily be handled at surface. A higher density of the particles will have the effect that excess particles which are not accumulated at the interface will be automatically disposed to the bottom of the wellbore.
  • the invention also provides a well fluid for use in a wellbore, which well fluid comprises solid particles in a carrying fluid, which solid particles include a reactive polymer.
  • a well fluid treatment fluid
  • the reactive polymer of the well fluid comprises an epoxy resin composition comprising an epoxy resin, a curing agent, and optionally an accelerator, catalyst and/or filler material.
  • Figures 1-4 show several stages of the application of the method of the present invention in a wellbore extending into a layered reservoir formation; and Figure 5 shows schematically a testing cell for testing the present invention.
  • Figure 1 shows the lower part a wellbore 1 extending from surface (not shown) into an earth formation 4.
  • the earth formation in this example is layered.
  • Layers 6 and 7 carry hydrocarbon oil, and layer 8 carries water.
  • the layers 6,7,8 are separated by boundaries or impermeable layers 10,11.
  • the wellbore 1 is provided with a casing 14 formed of a metal casing string wherein the annulus 15 with the wall of the wellbore 1 is filled with cement.
  • the downhole well completion is indicated by tubing 16 extending to surface, and packer 18.
  • Fluid is received in the wellbore 1 from the layers 6,7,8 via perforations 20,21,22 as indicated by the arrows and is produced to surface through the tubing 16.
  • This fluid contains oil 23 and a significant amount of water 24 received from layer 8. It is desired to seal off influx of water from the water-bearing layer 8, in particular through the perforations 21 which form the interface between the wellbore and the waterbearing layer.
  • a coiled tubing 25 is lowered through the tubing 16, and a cooling fluid 27 is introduced via the coiled tubing 25 into the wellbore 1 from where it will flow some distance in the formation layers 6,7,8.
  • the cooling fluid can be 2 wt% KC1 in water.
  • the volume and rate of injection can be determined on the basis of temperature simulations .
  • 200-2000 bbls (31.8-318 m 3 ) of cooling fluid can be injected at a rate of 1-5 bbls/min (0.159- 0.795 m 3 /min) , in order to achieve a cool down of the interface by 20-50 Kelvin.
  • the well fluid comprises a suspension of solid reactive polymer particles 29 in a carrying fluid.
  • concentration of the particles can be between 1 and 50 wt% of the total well fluid, and the particle size between 0.1 mm and
  • a suitable reactive polymer includes an epoxy resin and a cross-linking agent, which are both contained in the same particles .
  • At least a part of the carrier fluid which can also be 2 wt% KC1 in water, will flow into the formation layers 6,7,8, through the perforations 20,21,22.
  • the reactive polymer particles will not penetrate the formation layers, and will be accumulated at the interface between the wellbore and the formation layers in the perforation tunnels. This can be noticed at surface by an increase in pressure due to the reduction in injectivity. Injection is suitably continued until a maximum surface pressure is reached. Pressure (so-called overbalance) is maintained for a certain time period, e.g. 2-16 hours. During this period the temperature at the interface increases again to approach the normal formation temperature.
  • the reactive polymer composition is selected such that at this temperature increase the reaction occurs.
  • the reaction speed at surface temperatures and also at the temperatures pertaining during the travel of the particles down the wellbore during injection can be neglected.
  • Some softening of the solid particles may occur at increased temperatures before the onset of the curing reaction that forms the solid plug.
  • the glass transition temperature of the polymer after reaction is above the temperature of the environment at the sealed interface.
  • the cured polymer is substantially non-deformable.
  • cross-links are formed within a particle and between adjacent particles, so that a plug or sealing layer 31 of polymer is formed at the interface.
  • the particles are selected so as to soften at the increased temperature so that they come into close contact with each other for good inter- particle bonding. It is also possible that the polymer swells after curing for even better sealing. A swollen polymer is still considered as a solid polymer.
  • the perforations 20,21,22 are sealed so that fluid communication between the wellbore and the layers 6,7,8, is suppressed.
  • the coiled tubing is withdrawn, and the oil-bearing layers 6,7 can be selectively re-perforated via the tubing 16 with techniques known in the art.
  • the result is displayed in Figure 4.
  • Oil 23 is received from the layers 6,7, via the new perforations 35,36, and water production from layer 8 is suppressed by the sealing layer 31 at the interface. It shall be clear that the cooling step may not be needed if the injection of particles into the wellbore and accumulation at the interface occurs much faster than the reaction.
  • the reactive polymer is an epoxy resin composition.
  • An epoxy resin composition generally comprises an epoxy resin, a cross-linking or curing agent, and optionally an accelerator, catalyst and/or a filling material.
  • An epoxy resin is a molecule containing more than one epoxide groups.
  • Two main categories of epoxy resins can be distinguished, glycidyl epoxy, and non-glycidyl epoxy resins.
  • the glycidyl epoxies can be further classified as glycidyl-ether, glycidyl-ester and glycidyl-amine .
  • the non-glycidyl epoxies are either aliphatic or cycloaliphatic epoxy resins.
  • Glycidyl epoxies can be prepared via a condensation reaction of appropriate dihydroxy compound, dibasic acid or a diamine and epichlorohydrin.
  • Non-glycidyl epoxies can be formed by peroxidation of olefinic double bond.
  • Suitable and common glycidyl-ether epoxies are diglycidyl ether of bisphenol-A (DGEBA) and novolac epoxy resins.
  • DGEBA diglycidyl ether of bisphenol-A
  • DGEBA diglycidyl ether of bisphenol-A
  • DGEBA diglycidyl ether of bisphenol-A
  • DGEBA diglycidyl ether of bisphenol-A
  • DGEBA can be synthesised by reacting bisphenol-A with epichlorohydrin, in the presence of a basic catalyst.
  • the properties of the DGEBA resins depend on the value of number of repeating units forming the resin chain, also known as degree of polymerisation. Typically, the number ranges from 0 to 25 in many commercial products.
  • Other suitable epoxy resins are Novolac epoxy resins, which are glycidyl ethers of phenolic novolac resins. Phenols are reacted in excess, with formaldehyde in presence of acidic catalyst to produce phenolic novolac resin.
  • Novolac epoxy resins can be synthesised by reacting phenolic novolac resin with epichlorohydrin in presence of sodium hydroxide as a catalyst.
  • Novolac epoxy resins generally contain multiple epoxide groups.
  • the number of epoxide groups per molecule depends upon the number of phenolic hydroxyl groups in the starting phenolic novolac resin, the extent to which they reacted and the degree of low molecular species being polymerised during synthesis.
  • the multiple epoxide groups allow these resins to achieve high cross-link density resulting in excellent temperature, chemical and solvent resistance.
  • Novolac epoxy resins show, inter alia, superior performance at elevated temperature, excellent mouldability, and mechanical properties.
  • Another suitable epoxy resin can also be used, such as an epoxy resin based on orto-cresol instead of bisphenol-A.
  • the curing process is a chemical reaction in which the epoxide groups in epoxy resin reacts with a curing agent (hardener) to form a highly crosslinked, three- dimensional network.
  • a curing agent hardener
  • Epoxy resins can be designed to cure quickly and easily at practically any temperature from 5-160 °C depending on the choice of curing agent.
  • the composition is designed to cure at temperatures prevailing at the location where sealing is desired, in particular above 50°C, preferably between 80 and 150 °C.
  • a wide variety of curing agents for epoxy resins is known in the art.
  • Common curing agents for epoxies include amines, polyamides, phenolic resins, anhydrides, isocyanates and polymercaptans.
  • the cure kinetics and the Tg of cured system are dependent on the molecular structure of the hardener. The choice of resin and hardeners depends on the application and the properties desired. The stoichiometry of the epoxy-hardener system also affects the properties of the cured material.
  • Amines are the most 'commonly used curing agents for epoxy cure.
  • Primary and secondary amines are highly reactive with epoxy. Tertiary amines are generally used as catalysts, commonly known as accelerators for cure reactions. Use of excessive amount of catalyst achieves faster curing, but usually at the expense of working life, and thermal stability.
  • Epoxy resins can also be cured with phenolic hardener. Use of an accelerator can be preferred for the complete cure to occur.
  • Suitable epoxy resin compositions according to the invention can also be based on liquid epoxy resin, which can be mixed with a curing agent and set to undergo an incomplete curing reaction thereby forming a solid polymer with epoxy resin for injection into the wellbore. The solid particles can be further cured by further reaction with curing agent after exposure to appropriate temperature at the interface.
  • the liquid epoxy resin can for example be an epoxy novolac with an epoxy group content of 5500-5700 mmol/kg.
  • a medium viscosity bisphenol-A/epichlorohydrin resin with an epoxy group content of 5000-5500 mmol/kg such as a material known as EPIKOTE 828.
  • the curing agent in both cases can be di-ethyl-toluene-di-aniline.
  • Suitable compositions can also be based on powder coating epoxy formulations, such as EPIKOTE 1001 or 3003, or on high temperature powder coating formulations. EPIKOTE are materials marketed by Resolution Performance Products.
  • Filler material can be added to the epoxy resin composition for cost reduction, limiting shrinkage after curing, limiting sticking properties of the solid particles, and/or to control density of the particles.
  • suitable fillers can be used calcium carbonate, silica, or glass beads.
  • Example The present invention has been tested in a so-called shut-off test.
  • a cylindrical core 50 of Berea sandstone of 500 milliDarcy permeability was mounted in a steel cell 53 which could be placed in an oven (not shown) .
  • At one face 55 of the core 50 a small perforation 60 was drilled.
  • the core had an outer diameter and a height of both 5 cm, and the perforation had a diameter of 0.8 cm and a depth of 1 cm.
  • the surface of the core outside the perforation 60 and outside the face 63 opposite the face 55 was liquid sealed with epoxy resin 65.
  • a suspension of a grinded high-temperature epoxy powder coating powder without filling material in 2% KC1 brine was prepared with a particle size of less than 1 mm and 20% by weight solids.
  • the suspension was squeezed into the perforation at 0.5-1 bar pressure.
  • the composition was allowed to cure for 48 hours at 150 °C, to form a solid plug in the perforation 60 and also in region 68 at the interface between core 50 and perforation 60. Thereafter the resulting permeability was determined by putting 180 bar of liquid pressure (brine) at 150 °C via opening 70 onto face 63.
  • the resulting permeability (return permeability) was 0.02% of the original permeability of the core.

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  • Life Sciences & Earth Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Geology (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Physics & Mathematics (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Sealing Material Composition (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
  • Solid-Sorbent Or Filter-Aiding Compositions (AREA)
  • Devices And Processes Conducted In The Presence Of Fluids And Solid Particles (AREA)
  • Water Treatment By Sorption (AREA)

Abstract

Procédé de suppression de la communication fluidique vers et à partir d'un puits de forage dans une formation souterraine, consistant à prévoir un fluide de forage comportant des particules solides dans un fluide véhicule, lesdites particules solides comprenant un polymère réactif ; à introduire le fluide de forage dans le puits de forage de telle manière que le fluide véhicule traverse une interface entre le puits de forage et son environnement, les particules étant accumulées au niveau de l'interface ; et à permettre au polymère de former un bouchon solide qui supprime toute communication fluidique au travers de l'interface ; et fluide véhicule utilisable dans un puits de forage, ce fluide comportant des particules solides dans un fluide véhicule, et lesdites particules solides comprenant un polymère réactif.
EP05707992A 2004-02-12 2005-02-10 Suppression de la communication d'un fluide vers et a partir d'un puits de forage Withdrawn EP1721059A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
EP05707992A EP1721059A1 (fr) 2004-02-12 2005-02-10 Suppression de la communication d'un fluide vers et a partir d'un puits de forage

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
EP04100547 2004-02-12
EP05707992A EP1721059A1 (fr) 2004-02-12 2005-02-10 Suppression de la communication d'un fluide vers et a partir d'un puits de forage
PCT/EP2005/050589 WO2005078235A1 (fr) 2004-02-12 2005-02-10 Suppression de la communication fluidique vers et a partir d'un puits de forage

Publications (1)

Publication Number Publication Date
EP1721059A1 true EP1721059A1 (fr) 2006-11-15

Family

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Family Applications (1)

Application Number Title Priority Date Filing Date
EP05707992A Withdrawn EP1721059A1 (fr) 2004-02-12 2005-02-10 Suppression de la communication d'un fluide vers et a partir d'un puits de forage

Country Status (8)

Country Link
EP (1) EP1721059A1 (fr)
CN (1) CN1918361A (fr)
AU (1) AU2005212638B2 (fr)
CA (1) CA2554237A1 (fr)
EA (1) EA008963B1 (fr)
NO (1) NO20064082L (fr)
NZ (1) NZ548688A (fr)
WO (1) WO2005078235A1 (fr)

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US7267174B2 (en) 2005-01-24 2007-09-11 Halliburton Energy Services, Inc. Methods of plugging a permeable zone downhole using a sealant composition comprising a crosslinkable material and a reduced amount of cement
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CN101701517B (zh) * 2009-12-11 2012-09-05 安东石油技术（集团）有限公司 一种从便于将井下过滤器管柱拔出的油气井中提出井下过滤器管柱的方法
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CN1918361A (zh) 2007-02-21
WO2005078235A9 (fr) 2006-12-28
WO2005078235A1 (fr) 2005-08-25
NZ548688A (en) 2010-06-25
CA2554237A1 (fr) 2005-08-25
AU2005212638B2 (en) 2007-11-29
EA008963B1 (ru) 2007-10-26
NO20064082L (no) 2006-11-10
AU2005212638A1 (en) 2005-08-25
EA200601465A1 (ru) 2007-04-27

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