WO2002066783A1 - Cuvelage pour puits de forage a un seul diametre - Google Patents

Cuvelage pour puits de forage a un seul diametre Download PDF

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Publication number
WO2002066783A1
WO2002066783A1 PCT/US2002/004353 US0204353W WO02066783A1 WO 2002066783 A1 WO2002066783 A1 WO 2002066783A1 US 0204353 W US0204353 W US 0204353W WO 02066783 A1 WO02066783 A1 WO 02066783A1
Authority
WO
WIPO (PCT)
Prior art keywords
shoe
expansion cone
wellbore casing
radially expanded
borehole
Prior art date
Application number
PCT/US2002/004353
Other languages
English (en)
Inventor
Robert Lance Cook
Lev Ring
Original Assignee
Enventure Global Technology
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 Enventure Global Technology filed Critical Enventure Global Technology
Priority to CA002438807A priority Critical patent/CA2438807C/fr
Priority to GB0320747A priority patent/GB2390622B/en
Priority to AU2002240366A priority patent/AU2002240366B2/en
Publication of WO2002066783A1 publication Critical patent/WO2002066783A1/fr
Priority to US10/504,361 priority patent/US7516790B2/en
Priority to US10/644,101 priority patent/US7195064B2/en

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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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/14—Casing shoes for the protection of the bottom of the casing
    • 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

Definitions

  • This invention relates generally to wellbore casings, and in particular to wellbore casings that are formed using expandable tubing.
  • a relatively large borehole diameter is required at the upper part of the wellbore.
  • Such a large borehole diameter involves increased costs due to heavy casing handling equipment, large drill bits and increased volumes of drilling fluid and drill cuttings.
  • increased drilling rig time is involved due to required cement pumping, cement hardening, required equipment changes due to large variations in hole diameters drilled in the course of the well, and the large volume of cuttings drilled and removed.
  • the present invention is directed to overcoming one or more of the limitations of the existing procedures for forming new sections of casing in a wellbore.
  • an apparatus for forming a wellbore casing in a borehole located in a subterranean formation including a preexisting wellbore casing includes a support member including a first fluid passage, an expansion cone coupled to the support member including a second fluid passage fluidicly coupled to the first fluid passage, an expandable tubular liner movably coupled to the expansion cone, and an expandable shoe coupled to the expandable tubular liner.
  • a shoe is provided that includes an upper annular portion, an intermediate annular portion, and a lower annular portion. The intermediate annular portion has an outer circumference that is larger than the outer circumferences of the upper and lower annular portions.
  • a method of forming a wellbore casing in a subterranean formation having a preexisting wellbore casing positioned in a borehole includes installing a tubular liner, an expansion cone, and a shoe in the borehole, radially expanding at least a portion of the shoe by injecting a fluidic material into the shoe, and radially expanding at least a portion of the tubular liner by injecting a fluidic material into the borehole below the expansion cone.
  • an apparatus for forming a wellbore casing in a subterranean formation having a preexisting wellbore casing positioned in a borehole includes means for installing a tubular liner, an expansion cone, and a shoe in the borehole, means for radially expanding at least a portion of the shoe, and means for radially expanding at least a portion of the tubular liner.
  • an apparatus for forming a wellbore casing within a subterranean formation including a preexisting wellbore casing positioned in a borehole includes a tubular liner, and means for radially expanding and coupling the tubular liner to an overlapping portion of the preexisting wellbore casing.
  • the inside diameter of the radially expanded tubular liner is substantially equal to the inside diameter of a non-overlapping portion of the preexisting wellbore casing.
  • a wellbore casing positioned in a borehole within a subterranean formation includes a first wellbore casing, and a second wellbore casing coupled to and overlapping with the first wellbore casing.
  • the second wellbore casing is coupled to the first wellbore casing by the process of: installing the second wellbore casing, an expansion cone, and a shoe in the borehole, radially expanding at least a portion of the shoe by injecting a fluidic material into the shoe, and radially expanding at least a portion of the second wellbore casing by injecting a fluidic material into the borehole below the expansion cone.
  • a method of forming a tubular structure in a subterranean formation having a preexisting tubular member positioned in a borehole includes installing a tubular liner, an expansion cone, and a shoe in the borehole, radially expanding at least a portion of the shoe by injecting a fluidic material into the shoe, and radially expanding at least a portion of the tubular liner by injecting a fluidic material into the borehole below the expansion cone.
  • an apparatus for forming a tubular structure in a subterranean formation having a preexisting tubular member positioned in a borehole includes means for installing a tubular liner, an expansion cone, and a shoe in the borehole, means for radially expanding at least a portion of the shoe, and means for radially expanding at least a portion of the tubular liner.
  • an apparatus for forming a tubular structure within a subterranean formation including a preexisting tubular member positioned in a borehole includes a tubular liner and means for radially expanding and coupling the tubular liner to an overlapping portion of the preexisting tubular member.
  • the inside diameter of the radially expanded tubular liner is substantially equal to the inside diameter of a non-overlapping portion of the preexisting tubular member.
  • a tubular structure positioned in a borehole within a subterranean formation includes a first tubular member and a second tubular member coupled to and overlapping with the first tubular member.
  • the second tubular member is coupled to the first tubular member by the process of: installing the second tubular member, an expansion cone, and a shoe in the borehole, radially expanding at least a portion of the shoe by injecting a fluidic material into the shoe, and radially expanding at least a portion of the second tubular member by injecting a fluidic material into the borehole below the expansion cone.
  • FIG. 1 is a fragmentary cross-sectional view illustrating the drilling of a new section of a well borehole.
  • FIG. 2 is a fragmentary cross-sectional view illustrating the placement of an embodiment of an apparatus for creating a mono-diameter wellbore casing within the new section of the well borehole of FIG. 1.
  • FIG. 2a is a cross-sectional view of a portion of the shoe of the apparatus of FIG. 2.
  • FIG. 2b is a cross-sectional view of another portion of the shoe of the apparatus of FIG. 2.
  • FIG. 2c is a cross-sectional view of another portion of the shoe of the apparatus of FIG. 2.
  • FIG. 2d is a cross-sectional view of another portion of the shoe of the apparatus of FIG. 2.
  • FIG. 2e is a cross-sectional view of a portion of the shoe of the apparatus of FIG. 2c.
  • FIG. 3 is a fragmentary cross-sectional view illustrating the injection of a hardenable fluidic sealing material through the apparatus and into the new section of the well borehole of FIG. 2.
  • FIG. 3a is a cross-sectional view of a portion of the shoe of the apparatus of FIG. 3.
  • FIG. 3b is a cross-sectional view of a portion of the shoe of the apparatus of FIG. 3a.
  • FIG. 4 is a fragmentary cross-sectional view illustrating the injection of a fluidic material into the apparatus of FIG. 3 in order to fluidicly isolate the interior of the shoe.
  • FIG. 4a is a cross-sectional view of a portion of the shoe of the apparatus of FIG.
  • FIG. 4b is a cross-sectional view of a portion of the shoe of the apparatus of FIG. 4a.
  • FIG. 5 is a cross-sectional view illustrating the radial expansion of the shoe of FIG. 4.
  • FIG. 6 is a cross-sectional view illustrating the lowering of the expandable expansion cone into the radially expanded shoe of the apparatus of FIG. 5.
  • FIG. 7 is a cross-sectional view illustrating the expansion of the expandable expansion cone of the apparatus of FIG. 6.
  • FIG. 8 is a cross-sectional view illustrating the injection of fluidic material into the radially expanded shoe of the apparatus of FIG. 7.
  • FIG. 9 is a cross-sectional view illustrating the completion of the radial expansion of the expandable tubular member of the apparatus of FIG. 8.
  • FIG. 10 is a cross-sectional view illustrating the removal ofthe bottom portion of the radially expanded shoe ofthe apparatus of FIG. 9.
  • FIG. 11 is a cross-sectional view illustrating the formation of a mono-diameter wellbore casing that includes a plurality of overlapping mono-diameter wellbore casings.
  • FIG. 12 is a fragmentary cross-sectional view illustrating the placement of an alternative embodiment of an apparatus for creating a mono-diameter wellbore casing within the wellbore of FIG. 1.
  • FIG. 12a is a cross-sectional view of a portion of the shoe of the apparatus of FIG. 12.
  • FIG. 12b is a cross-sectional view of a portion of the shoe of the apparatus of
  • FIG. 12c is a cross-sectional view of another portion of the shoe of the apparatus of FIG. 12.
  • FIG. 12d is a cross-sectional view of another portion of the shoe of the apparatus of FIG. 12.
  • FIG. 13 is a fragmentary cross-sectional view illustrating the injection of a hardenable fluidic sealing material through the apparatus and into the new section of the well borehole of FIG. 12.
  • FIG. 13a is a cross-sectional view of a portion of the shoe of the apparatus of FIG. 13.
  • FIG. 14 is a fragmentary cross-sectional view illustrating the injection of a fluidic material into the apparatus of FIG. 13 in order to fluidicly isolate the interior of the shoe.
  • FIG. 14a is a cross-sectional view of a portion of the shoe of the apparatus of FIG. 14.
  • FIG. 15 is a cross-sectional view illustrating the radial expansion of the shoe of FIG. 14.
  • FIG. 16 is a cross-sectional view illustrating the lowering of the expandable expansion cone into the radially expanded shoe of the apparatus of FIG. 15.
  • FIG. 17 is a cross-sectional view illustrating the expansion of the expandable expansion cone of the apparatus of FIG. 16.
  • FIG. 18 is a cross-sectional view illustrating the injection of fluidic material into the radially expanded shoe ofthe apparatus of FIG. 17.
  • FIG. 19 is a cross-sectional view illustrating the completion of the radial expansion of the expandable tubular member of the apparatus of FIG. 18.
  • FIG. 20 is a cross-sectional view illustrating the removal of the bottom portion of the radially expanded shoe of the apparatus of FIG. 19. Detailed Description of the Illustrative Embodiments
  • a wellbore 100 is positioned in a subterranean formation 105.
  • the wellbore 100 includes a pre-existing cased section 110 having a tubular casing 115 and an annular outer layer 120 of a fluidic sealing material such as, for example, cement.
  • the wellbore 100 may be positioned in any orientation from vertical to horizontal.
  • the pre-existing cased section 110 does not include the annular outer layer 120.
  • a drill string 125 is used in a well known manner to drill out material from the subterranean formation 105 to form a new wellbore section 130.
  • the inside diameter of the new wellbore section 130 is greater than the inside diameter of the preexisting wellbore casing 115.
  • an apparatus 200 for forming a wellbore casing in a subterranean formation is then positioned in the new section 130 of the wellbore 100.
  • the apparatus 200 preferably includes an expansion cone 205 having a fluid passage 205a that supports a tubular member 210 that includes a lower portion 210a, an intermediate portion 210b, an upper portion 210c, and an upper end portion 210d.
  • the expansion cone 205 may be any number of conventional commercially available expansion cones.
  • the expansion cone 205 may be controllably expandable in the radial direction, for example, as disclosed in U.S. patent nos. 5,348,095, and/or 6,012,523, the disclosures of which are incorporated herein by reference.
  • the tubular member 210 may be fabricated from any number of conventional commercially available materials such as, for example, Oilfield Country Tubular Goods (OCTG), 13 chromium steel tubing/casing, or plastic tubing/casing.
  • OCTG Oilfield Country Tubular Goods
  • the tubular member 210 is fabricated from OCTG in order to maximize strength after expansion.
  • the tubular member 210 may be solid and/or slotted.
  • the length of the tubular member 210 is preferably limited to between about 40 to 20,000 feet in length.
  • the lower portion 210a of the tubular member 210 preferably has a larger inside diameter than the upper portion 210c of the tubular member.
  • the wall thickness of the intermediate portion 210b of the tubular member 201 is less than the wall thickness of the upper portion 210c of the tubular member in order to faciliate the initiation of the radial expansion process.
  • the upper end portion 210d of the tubular member 210 is slotted, perforated, or otherwise modified to catch or slow down the expansion cone 205 when it completes the extrusion of tubular member 210.
  • wall thickness of the upper end portion 210d of the tubular member 210 is gradually tapered in order to gradually reduce the required radial expansion forces during the latter stages ofthe radial expansion process. In this manner, shock loading conditions during the latter stages of the radial expansion process are at least minimized.
  • a shoe 215 is coupled to the lower portion 210a of the tubular member.
  • the shoe 215 includes an upper portion 215a, an intermediate portion 215b, and lower portion 215c having a valveable fluid passage 220 that is preferably adapted to receive a plug, dart, or other similar element for controllably sealing the fluid passage 220.
  • the fluid passage 220 may be optimally sealed off by introducing a plug, dart and/or ball sealing elements into the fluid passage 220.
  • the upper and lower portions, 215a and 215c, of the shoe 215 are preferably substantially tubular, and the intermediate portion 215b of the shoe is preferably at least partially folded inwardly. Furthermore, in a preferred embodiment, when the intermediate portion 215b of the shoe 215 is unfolded by the application of fluid pressure to the interior region 230 of the shoe, the inside and outside diameters of the intermediate portion are preferably both greater than the inside and outside diameters of the upper and lower portions, 215a and 215c. In this manner, the outer circumference of the intermediate portion 215b of the shoe 215 is preferably greater than the outside circumferences of the upper and lower portions, 215a and 215b, of the shoe.
  • the shoe 215 further includes one or more through and side outlet ports in fluidic communication with the fluid passage 220. In this manner, the shoe 215 optimally injects hardenable fluidic sealing material into the region outside the shoe 215 and tubular member 210.
  • the flow passage 220 is omitted.
  • a support member 225 having fluid passages 225a and 225b is coupled to the expansion cone 205 for supporting the apparatus 200.
  • the fluid passage 225a is preferably fluidicly coupled to the fluid passage 205a. In this manner, fluidic materials may be conveyed to and from the region 230 below the expansion cone 205 and above the bottom of the shoe 215.
  • the fluid passage 225b is preferably fluidicly coupled to the fluid passage 225a and includes a conventional control valve. In this manner, during placement of the apparatus 200 within the wellbore 100, surge pressures can be relieved by the fluid passage 225b.
  • the support member 225 further includes one or more conventional centralizers (not illustrated) to help stabilize the apparatus 200.
  • the fluid passage 225a is preferably selected to transport materials such as, for example, drilling mud or formation fluids at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to minimize drag on the tubular member being run and to minimize surge pressures exerted on the wellbore 130 which could cause a loss of wellbore fluids and lead to hole collapse.
  • materials such as, for example, drilling mud or formation fluids at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to minimize drag on the tubular member being run and to minimize surge pressures exerted on the wellbore 130 which could cause a loss of wellbore fluids and lead to hole collapse.
  • the fluid passage 225b is preferably selected to convey fluidic materials at flow rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to reduce the drag on the apparatus 200 during insertion into the new section 130 of the wellbore 100 and to minimize surge pressures on the new wellbore section 130.
  • a cup seal 235 is coupled to and supported by the support member 225. The cup seal 235 prevents foreign materials from entering the interior region of the tubular member 210 adjacent to the expansion cone 205.
  • the cup seal 235 may be any number of conventional commercially available cup seals such as, for example, TP cups, or Selective Injection Packer (SIP) cups modified in accordance with the teachings of the present disclosure.
  • the cup seal 235 is a SIP cup seal, available from Halliburton Energy Services in Dallas, TX in order to optimally block foreign material and contain a body of lubricant.
  • the cup seal 235 may include a plurality of cup seals.
  • One or more sealing members 240 are preferably coupled to and supported by the exterior surface of the upper end portion 210d of the tubular member 210.
  • the sealing members 240 preferably provide an overlapping joint between the lower end portion 115a of the casing 115 and the upper end portion 210d of the tubular member 210.
  • the sealing members 240 may be any number of conventional commercially available seals such as, for example, lead, rubber, Teflon, or epoxy seals modified in accordance with the teachings of the present disclosure.
  • the sealing members 240 are molded from Stratalock epoxy available from Halliburton Energy Services in Dallas, TX in order to optimally provide a load bearing interference fit between the upper end portion 210d of the tubular member 210 and the lower end portion 115a of the existing casing 115.
  • the sealing members 240 are selected to optimally provide a sufficient frictional force to support the expanded tubular member 210 from the existing casing 115.
  • the frictional force optimally provided by the sealing members 240 ranges from about 1,000 to 1,000,000 lbf in order to optimally support the expanded tubular member 210.
  • the sealing members 240 are omitted from the upper end portion 210d of the tubular member 210, and a load bearing metal-to-metal interference fit is provided between upper end portion of the tubular member and the lower end portion 115a of the existing casing 115 by plastically deforming and radially expanding the tubular member into contact with the existing casing.
  • a quantity of lubricant 245 is provided in the annular region above the expansion cone 205 within the interior of the tubular member 210. In this manner, the extrusion of the tubular member 210 off of the expansion cone 205 is facilitated.
  • the lubricant 245 may be any number of conventional commercially available lubricants such as, for example, Lubriplate, chlorine based lubricants, oil based lubricants or Climax 1500 Antisieze (3100).
  • the lubricant 245 is Climax 1500 Antisieze (3100) available from Climax Lubricants and Equipment Co. in Houston, TX in order to optimally provide optimum lubrication to faciliate the expansion process.
  • the support member 225 is thoroughly cleaned prior to assembly to the remaining portions of the apparatus 200. In this manner, the introduction of foreign material into the apparatus 200 is minimized. This minimizes the possibility of foreign material clogging the various flow passages and valves of the apparatus 200.
  • a couple of wellbore volumes are circulated in order to ensure that no foreign materials are located within the wellbore 100 that might clog up the various flow passages and valves of the apparatus 200 and to ensure that no foreign material interferes with the expansion process.
  • fluidic materials 250 within the wellbore that are displaced by the apparatus are at least partially conveyed through the fluid passages 220, 205a, 225a, and 225b. In this manner, surge pressures created by the placement of the apparatus within the wellbore 100 are reduced.
  • the fluid passage 225b is then closed and a hardenable fluidic sealing material 255 is then pumped from a surface location into the fluid passages 225a and 205a.
  • the material 255 then passes from the fluid passage 205a into the interior region 230 of the shoe 215 below the expansion cone 205.
  • the material 255 then passes from the interior region 230 into the fluid passage 220.
  • the material 255 then exits the apparatus 200 and fills an annular region 260 between the exterior of the tubular member 210 and the interior wall of the new section 130 of the wellbore 100. Continued pumping of the material 255 causes the material to fill up at least a portion of the annular region 260.
  • the material 255 is preferably pumped into the annular region 260 at pressures and flow rates ranging, for example, from about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively.
  • the optimum flow rate and operating pressures vary as a function of the casing and wellbore sizes, wellbore section length, available pumping equipment, and fluid properties of the fluidic material being pumped.
  • the optimum flow rate and operating pressure are preferably determined using conventional empirical methods.
  • the hardenable fluidic sealing material 255 may be any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement, latex or epoxy.
  • the hardenable fluidic sealing material 255 is a blended cement prepared specifically for the particular well section being drilled from Halliburton Energy Services in Dallas, TX in order to provide optimal support for tubular member 210 while also maintaining optimum flow characteristics so as to minimize difficulties during the displacement of cement in the annular region 260.
  • the optimum blend of the blended cement is preferably determined using conventional empirical methods.
  • the hardenable fluidic sealing material 255 is compressible before, during, or after curing.
  • the annular region 260 preferably is filled with the material 255 in sufficient quantities to ensure that, upon radial expansion of the tubular member 210, the annular region 260 of the new section 130 of the wellbore 100 will be filled with the material 255.
  • the injection of the material 255 into the annular region 260 is omitted, or is provided after the radial expansion of the tubular member 210.
  • a plug 265, or other similar device is introduced into the fluid passage 220, thereby fluidicly isolating the interior region 230 from the annular region 260.
  • a non-hardenable fluidic material 270 is then pumped into the interior region 230 causing the interior region to pressurize. In this manner, the interior region 230 of the expanded tubular member 210 will not contain significant amounts of the cured material 255. This also reduces and simplifies the cost of the entire process. Alternatively, the material 255 may be used during this phase of the process. As illustrated in FIG.
  • the continued injection of the fluidic material 270 pressurizes the region 230 and unfolds the intermediate portion 215b of the shoe 215.
  • the outside diameter of the unfolded intermediate portion 215b of the shoe 215 is greater than the outside diameter of the upper and lower portions, 215a and 215b, of the shoe.
  • the inside and outside diameters of the unfolded intermediate portion 215b of the shoe 215 are greater than the inside and outside diameters, respectively, of the upper and lower portions, 215a and 215b, of the shoe.
  • the inside diameter of the unfolded intermediate portion 215b of the shoe 215 is substantially equal to or greater than the inside diameter of the preexisting casing 115 in order to optimally facilitate the formation of a mono-diameter wellbore casing.
  • the expansion cone 205 is then lowered into the unfolded intermediate portion 215b of the shoe 215.
  • the expansion cone 205 is lowered into the unfolded intermediate portion 215b of the shoe 215 until the bottom of the expansion cone is proximate the lower portion 215c of the shoe 215.
  • the material 255 within the annular region 260 and/or the bottom of the wellbore section 130 maintains the shoe 215 in a substantially stationary position.
  • the outside diameter of the expansion cone 205 is then increased.
  • the outside diameter of the expansion cone 205 is increased as disclosed in U.S. patent nos. 5,348,095, and/or 6,012,523, the disclosures of which are incorporate herein by reference.
  • the outside diameter of the radially expanded expansion cone 205 is substantially equal to the inside diameter of the preexisting wellbore casing 115.
  • the expansion cone 205 is not lowered into the radially expanded portion of the shoe 215 prior to being radially expanded. In this manner, the upper portion 210c of the shoe 210 may be radially expanded by the radial expansion of the expansion cone 205. In another alternative embodiment, the expansion cone 205 is not radially expanded.
  • a fluidic material 275 is then injected into the region 230 through the fluid passages 225a and 205a.
  • the upper portion 215a of the shoe 215 and the tubular member 210 are preferably plastically deformed, radially expanded, and extruded off of the expansion cone 205.
  • the upper portion 210d of the tubular member and the lower portion of the preexisting casing 115 that overlap with one another are simultaneously plastically deformed and radially expanded. In this manner, a mono-diameter wellbore casing may be formed that includes the preexisting wellbore casing 115 and the radially expanded tubular member 210.
  • the expansion cone 205 may be raised out of the expanded portion of the tubular member 210.
  • the expansion cone 205 is raised at approximately the same rate as the tubular member 210 is expanded in order to keep the tubular member 210 stationary relative to the new wellbore section 130. In this manner, an overlapping joint between the radially expanded tubular member 210 and the lower portion of the preexisting casing 115 may be optimally formed.
  • the expansion cone 205 is maintained in a stationary position during the extrusion process thereby allowing the tubular member 210 to extrude off of the expansion cone 205 and into the new wellbore section 130 under the force of gravity and the operating pressure of the interior region 230.
  • the expansion cone 205 is displaced out of the wellbore 100 by both the operating pressure within the region 230 and a upwardly directed axial force applied to the tubular support member 225.
  • the overlapping joint between the lower portion of the preexisting casing 115 and the radially expanded tubular member 210 preferably provides a gaseous and fluidic seal.
  • the sealing members 245 optimally provide a fluidic and gaseous seal in the overlapping joint.
  • the sealing members 245 are omitted.
  • the operating pressure and flow rate of the fluidic material 275 is controllably ramped down when the expansion cone 205 reaches the upper end portion 210d of the tubular member 210. In this manner, the sudden release of pressure caused by the complete extrusion of the tubular member 210 off of the expansion cone 205 can be minimized.
  • the operating pressure is reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when the expansion cone 205 is within about 5 feet from completion of the extrusion process.
  • the wall thickness of the upper end portion 210d of the tubular member is tapered in order to gradually reduce the required operating pressure for plastically deforming and radially expanding the upper end portion of the tubular member. In this manner, shock loading of the apparatus is at least reduced.
  • a shock absorber is provided in the support member 225 in order to absorb the shock caused by the sudden release of pressure.
  • the shock absorber may comprise, for example, any conventional commercially available shock absorber, bumper sub, or jars adapted for use in wellbore operations.
  • an expansion cone catching structure is provided in the upper end portion 210d of the tubular member 210 in order to catch or at least decelerate the expansion cone 205.
  • the apparatus 200 is adapted to minimize tensile, burst, and friction effects upon the tubular member 210 during the expansion process. These effects will be depend upon the geometry of the expansion cone 205, the material composition of the tubular member 210 and expansion cone 205, the inner diameter of the tubular member 210, the wall thickness of the tubular member 210, the type of lubricant, and the yield strength of the tubular member 210. In general, the thicker the wall thickness, the smaller the inner diameter, and the greater the yield strength of the tubular member 210, then the greater the operating pressures required to extrude the tubular member 210 off of the expansion cone 205.
  • the extrusion of the tubular member 210 off of the expansion cone 205 will begin when the pressure of the interior region 230 reaches, for example, approximately 500 to 9,000 psi.
  • the expansion cone 205 may be raised out of the expanded portion of the tubular member 210 at rates ranging, for example, from about 0 to 5 ft/sec. In a preferred embodiment, during the extrusion process, the expansion cone 205 is raised out of the expanded portion of the tubular member 210 at rates ranging from about 0 to 2 ft/sec in order to minimize the time required for the expansion process while also permitting easy control of the expansion process.
  • the expansion cone 205 is removed from the wellbore 100.
  • the integrity of the fluidic seal of the overlapping joint between the upper end portion 210d of the tubular member 210 and the lower end portion 115a of the preexisting wellbore casing 115 is tested using conventional methods.
  • any uncured portion of the material 255 within the expanded tubular member 210 is then removed in a conventional manner such as, for example, circulating the uncured material out of the interior of the expanded tubular member 210.
  • the expansion cone 205 is then pulled out of the wellbore section 130 and a drill bit or mill is used in combination with a conventional drilling assembly to drill out any hardened material 255 within the tubular member 210.
  • the material 255 within the annular region 260 is then allowed to fully cure.
  • the bottom portion 215c of the shoe 215 may then be removed by drilling out the bottom portion of the shoe using conventional drilling methods.
  • the wellbore 100 may then be extended in a conventional manner using a conventional drilling assembly.
  • the inside diameter of the extended portion of the wellbore 100 is greater than the inside diameter of the radially expanded shoe 215.
  • the method of FIGS. 1-10 may be repeatedly performed in order to provide a mono-diameter wellbore casing that includes overlapping wellbore casings 115 and 210a-210e.
  • the wellbore casing 115, and 210a-210e preferably include outer annular layers of fluidic sealing material.
  • a mono-diameter wellbore casing may be formed within the subterranean formation that extends for tens of thousands of feet. More generally still, the teachings of FIGS. 1-11 may be used to form a mono-diameter wellbore casing, a pipeline, a structural support, or a tunnel within a subterranean formation at any orientation from the vertical to the horizontal.
  • the formation of a mono-diameter wellbore casing is further provided as disclosed in one or more of the following: (1) U.S. patent application serial no. 09/454,139, attorney docket no. 25791.03.02, filed on 12/3/1999, (2) U.S. patent application serial no. 09/510,913, attorney docket no. 25791J.02, filed on 2/23/2000, (3) U.S. patent application serial no. 09/502,350, attorney docket no. 25791.8.02, filed on 2/10/2000, (4) U.S. patent application serial no. 09/440,338, attorney docket no.
  • an apparatus 300 for forming a mono-diameter wellbore casing is positioned within the wellbore casing 115 that is substantially identical in design and operation to the apparatus 200 except that a shoe 305 is substituted for the shoe 215.
  • the shoe 305 includes an upper portion 305a, an intermediate portion 305b, and a lower portion 305c having a valveable fluid passage 310 that is preferably adapted to receive a plug, dart, or other similar element for controllably sealing the fluid passage 310.
  • the fluid passage 310 may be optimally sealed off by introducing a plug, dart and/or ball sealing elements into the fluid passage 310.
  • the upper and lower portions, 305a and 305c, of the shoe 305 are preferably substantially tubular, and the intermediate portion 305b of the shoe includes corrugations 305ba-305bh. Furthermore, in a preferred embodiment, when the intermediate portion 305b of the shoe 305 is radially expanded by the application of fluid pressure to the interior 315 of the shoe 305, the inside and outside diameters of the radially expanded intermediate portion are preferably both greater than the inside and outside diameters of the upper and lower portions, 305a and 305c. In this manner, the outer circumference of the intermediate portion 305b of the shoe 305 is preferably greater than the outer circumferences of the upper and lower portions, 305a and 305c, of the shoe.
  • the shoe 305 further includes one or more through and side outlet ports in fluidic communication with the fluid passage 310. In this manner, the shoe 305 optimally injects hardenable fluidic sealing material into the region outside the shoe 305 and tubular member 210.
  • the flow passage 310 is omitted.
  • fluidic materials 250 within the wellbore that are displaced by the apparatus are conveyed through the fluid passages 310, 205a, 225a, and 225b. In this manner, surge pressures created by the placement of the apparatus within the wellbore 100 are reduced.
  • the fluid passage 225b is then closed and a hardenable fluidic sealing material 255 is then pumped from a surface location into the fluid passages 225a and 205a.
  • the material 255 then passes from the fluid passage 205a into the interior region 315 of the shoe 305 below the expansion cone 205.
  • the material 255 then passes from the interior region 315 into the fluid passage 310.
  • the material 255 then exits the apparatus 300 and fills the annular region 260 between the exterior of the tubular member 210 and the interior wall of the new section 130 of the wellbore 100. Continued pumping of the material 255 causes the material to fill up at least a portion of the annular region 260.
  • the material 255 is preferably pumped into the annular region 260 at pressures and flow rates ranging, for example, from about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively.
  • the optimum flow rate and operating pressures vary as a function of the casing and wellbore sizes, wellbore section length, available pumping equipment, and fluid properties of the fluidic material being pumped.
  • the optimum flow rate and operating pressure are preferably determined using conventional empirical methods.
  • the hardenable fluidic sealing material 255 may be any number of conventional commercially available hardenable fluidic sealing materials such as, for example, slag mix, cement, latex or epoxy.
  • the hardenable fluidic sealing material 255 is a blended cement prepared specifically for the particular well section being drilled from Halliburton Energy Services in Dallas, TX in order to provide optimal support for tubular member 210 while also maintaining optimum flow characteristics so as to minimize difficulties during the displacement of cement in the annular region 260.
  • the optimum blend of the blended cement is preferably determined using conventional empirical methods.
  • the hardenable fluidic sealing material 255 is compressible before, during, or after curing.
  • the annular region 260 preferably is filled with the material 255 in sufficient quantities to ensure that, upon radial expansion of the tubular member 210, the annular region 260 of he new section 130 of the wellbore 100 will be filled with the material 255.
  • the injection of the material 255 into the annular region 260 is omitted.
  • a plug 265, or other similar device is introduced into the fluid passage 310, thereby fluidicly isolating the interior region 315 from the annular region 260.
  • a non-hardenable fluidic material 270 is then pumped into the interior region 315 causing the interior region to pressurize. In this manner, the interior region 315 will not contain significant amounts of the cured material 255. This also reduces and simplifies the cost of the entire process.
  • the material 255 may be used during this phase of the process.
  • the continued injection of the fluidic material 270 pressurizes the region 315 and unfolds the corrugations 305ba- 305bh of the intermediate portion 305b of the shoe 305.
  • the outside diameter of the unfolded intermediate portion 305b of the shoe 305 is greater than the outside diameter of the upper and lower portions, 305a and 305b, of the shoe.
  • the inside and outside diameters of the unfolded intermediate portion 305b of the shoe 305 are greater than the inside and outside diameters, respectively, of the upper and lower portions, 305a and 305b, of the shoe.
  • the inside diameter of the unfolded intermediate portion 305b of the shoe 305 is substantially equal to or greater than the inside diameter of the preexisting casing 305 in order to optimize the formation of a mono-diameter wellbore casing.
  • the expansion cone 205 is then lowered into the unfolded intermediate portion 305b of the shoe 305.
  • the expansion cone 205 is lowered into the unfolded intermediate portion 305b of the shoe 305 until the bottom of the expansion cone is proximate the lower portion 305c of the shoe 305.
  • the material 255 within the annular region 260 maintains the shoe 305 in a substantially stationary position.
  • the outside diameter of the expansion cone 205 is then increased.
  • the outside diameter of the expansion cone 205 is increased as disclosed in U.S. patent nos. 5,348,095, and/or 6,012,523, the disclosures of which are incorporate herein by reference.
  • the outside diameter of the radially expanded expansion cone 205 is substantially equal to the inside diameter of the preexisting wellbore casing 115.
  • the expansion cone 205 is not lowered into the radially expanded portion of the shoe 305 prior to being radially expanded. In this manner, the upper portion 305c of the shoe 305 may be radially expanded by the radial expansion of the expansion cone 205.
  • the expansion cone 205 is not radially expanded.
  • a fluidic material 275 is then injected into the region 315 through the fluid passages 225a and 205a.
  • the upper portion 305a of the shoe 305 and the tubular member 210 are preferably plastically deformed, radially expanded, and extruded off of the expansion cone 205.
  • the upper portion 210d of the tubular member and the lower portion of the preexisting casing 115 that overlap with one another are simultaneously plastically deformed and radially expanded. In this manner, a mono-diameter wellbore casing may be formed that includes the preexisting wellbore casing 115 and the radially expanded tubular member 210.
  • the expansion cone 205 may be raised out of the expanded portion of the tubular member 210.
  • the expansion cone 205 is raised at approximately the same rate as the tubular member 210 is expanded in order to keep the tubular member 210 stationary relative to the new wellbore section 130. In this manner, an overlapping joint between the radially expanded tubular member 210 and the lower portion of the preexisting casing 115 may be optimally formed.
  • the expansion cone 205 is maintained in a stationary position during the extrusion process thereby allowing the tubular member 210 to extrude off of the expansion cone 205 and into the new wellbore section 130 under the force of gravity and the operating pressure of the interior region 230.
  • the expansion cone 205 is displaced out of the wellbore 100 by both the operating pressure within the region 230 and a upwardly directed axial force applied to the tubular support member 225.
  • the overlapping joint between the lower portion of the preexisting casing 115 and the radially expanded tubular member 210 preferably provides a gaseous and fluidic seal.
  • the sealing members 245 optimally provide a fluidic and gaseous seal in the overlapping joint. In an alternative embodiment, the sealing members 245 are omitted.
  • the operating pressure and flow rate of the fluidic material 275 is controllably ramped down when the expansion cone 205 reaches the upper end portion 210d of the tubular member 210. In this manner, the sudden release of pressure caused by the complete extrusion of the tubular member 210 off of the expansion cone 205 can be minimized.
  • the operating pressure is reduced in a substantially linear fashion from 100% to about 10% during the end of the extrusion process beginning when the expansion cone 205 is within about 5 feet from completion of the extrusion process.
  • the wall thickness of the upper end portion 210d of the tubular member is tapered in order to gradually reduce the required operating pressure for plastically deforming and radially expanding the upper end portion of the tubular member. In this manner, shock loading of the apparatus may be at least partially minimized.
  • a shock absorber is provided in the support member 225 in order to absorb the shock caused by the sudden release of pressure.
  • the shock absorber may comprise, for example, any conventional commercially available shock absorber adapted for use in wellbore operations.
  • an expansion cone catching structure is provided in the upper end portion 210d of the tubular member 210 in order to catch or at least decelerate the expansion cone 205.
  • the apparatus 200 is adapted to minimize tensile, burst, and friction effects upon the tubular member 210 during the expansion process. These effects will be depend upon the geometry of the expansion cone 205, the material composition of the tubular member 210 and expansion cone 205, the inner diameter of the tubular member 210, the wall thickness of the tubular member 210, the type of lubricant, and the yield strength of the tubular member 210.
  • the extrusion of the tubular member 210 off of the expansion cone 205 will begin when the pressure of the interior region 230 reaches, for example, approximately 500 to 9,000 psi.
  • the expansion cone 205 may be raised out of the expanded portion of the tubular member 210 at rates ranging, for example, from about 0 to 5 ft/sec. In a preferred embodiment, during the extrusion process, the expansion cone 205 is raised out of the expanded portion of the tubular member 210 at rates ranging from about 0 to 2 ft/sec in order to minimize the time required for the expansion process while also permitting easy control of the expansion process.
  • the expansion cone 205 is removed from the wellbore 100.
  • the integrity of the fluidic seal of the overlapping joint between the upper end portion 210d of the tubular member 210 and the lower end portion 115a of the preexisting wellbore casing 115 is tested using conventional methods.
  • any uncured portion of the material 255 within the expanded tubular member 210 is then removed in a conventional manner such as, for example, circulating the uncured material out of the interior of the expanded tubular member 210.
  • the expansion cone 205 is then pulled out of the wellbore section 130 and a drill bit or mill is used in combination with a conventional drilling assembly to drill out any hardened material 255 within the tubular member 210.
  • the material 255 within the annular region 260 is then allowed to fully cure. As illustrated in FIG.
  • the bottom portion 305c of the shoe 305 may then be removed by drilling out the bottom portion of the shoe using conventional drilling methods.
  • the wellbore 100 may then be extended in a conventional manner using a conventional drilling assembly.
  • the inside diameter of the extended portion of the wellbore is greater than the inside diameter of the radially expanded shoe 305.
  • the method of FIGS. 12-20 may be repeatedly performed in order to provide a mono-diameter wellbore casing that includes overlapping wellbore casings.
  • the overlapping wellbore casing preferably include outer annular layers of fluidic sealing material.
  • the outer annular layers of fluidic sealing material may be omitted.
  • a mono-diameter wellbore casing may be formed within the subterranean formation that extends for tens of thousands of feet.
  • the teachings of FIGS. 12-20 may be used to form a mono-diameter wellbore casing, a pipeline, a structural support, or a tunnel within a subterranean formation at any orientation from the vertical to the horizontal.
  • the formation of a mono-diameter wellbore casing is further provided as disclosed in one or more of the following: (1) U.S. patent application serial no. 09/454,139, attorney docket no. 25791.03.02, filed on 12/3/1999, (2) U.S. patent application serial no. 09/510,913, attorney docket no. 25791J.02, filed on 2/23/2000, (3) U.S. patent application serial no. 09/502,350, attorney docket no. 25791.8.02, filed on 2/10/2000, (4) U.S. patent application serial no. 09/440,338, attorney docket no.
  • the apparatus 200 and 300 are used to form and/or repair wellbore casings, pipelines, and/or structural supports.
  • the folded geometries of the shoes 215 and 305 are provided in accordance with the teachings of U.S. Patent Nos. 5,425,559 and/or 5,794,702, the disclosures of which are incorporated herein by reference.
  • An apparatus for forming a wellbore casing in a borehole located in a subterranean formation including a preexisting wellbore casing includes a support member including a first fluid passage, an expansion cone coupled to the support member including a second fluid passage fluidicly coupled to the first fluid passage, an expandable tubular liner movably coupled to the expansion cone, and an expandable shoe coupled to the expandable tubular liner.
  • the expansion cone is expandable.
  • the expandable shoe includes a valveable fluid passage for controlling the flow of fluidic materials out of the expandable shoe.
  • the expandable shoe includes: an expandable portion and a remaining portion, wherein the outer circumference of the expandable portion is greater than the outer circumference of the remaining portion.
  • the expandable portion includes: one or more inward folds.
  • the expandable portion includes: one or more corrugations.
  • the expandable shoe includes: one or more inward folds.
  • the expandable shoe includes: one or more corrugations.
  • a shoe has also been described that includes an upper annular portion, an intermediate annular portion, and a lower annular portion, wherein the intermediate annular portion has an outer circumference that is larger than the outer circumferences of the upper and lower annular portions.
  • the lower annular portion includes a valveable fluid passage for controlling the flow of fluidic materials out of the shoe.
  • the intermediate portion includes one or more inward folds. In a preferred embodiment, the intermediate portion includes one or more corrugations.
  • a method of forming a wellbore casing in a subterranean formation having a preexisting wellbore casing positioned in a borehole includes installing a tubular liner, an expansion cone, and a shoe in the borehole, radially expanding at least a portion of the shoe by injecting a fluidic material into the shoe, and radially expanding at least a portion of the tubular liner by injecting a fluidic material into the borehole below the expansion cone.
  • the method further includes radially expanding the expansion cone.
  • the method further includes lowering the expansion cone into the radially expanded portion of the shoe, and radially expanding the expansion cone.
  • the method further includes radially expanding at least a portion of the shoe and the tubular liner by injecting a fluidic material into the borehole below the radially expanded expansion cone. In a preferred embodiment, the method further includes injecting a hardenable fluidic sealing material into an annulus between the tubular liner and the borehole. In a preferred embodiment, the method further includes radially expanding at least a portion of the preexisting wellbore casing. In a preferred embodiment, the method further includes overlapping a portion of the radially expanded tubular liner with a portion of the preexisting wellbore casing.
  • the inside diameter of the radially expanded tubular liner is substantially equal to the inside diameter of a nonoverlapping portion of the preexisting wellbore casing.
  • the method further includes applying an axial force to the expansion cone.
  • the inside diameter of the radially expanded shoe is greater than or equal to the inside diameter of the radially expanded tubular liner.
  • An apparatus for forming a wellbore casing in a subterranean formation having a preexisting wellbore casing positioned in a borehole includes means for installing a tubular liner, an expansion cone, and a shoe in the borehole, means for radially expanding at least a portion of the shoe, and means for radially expanding at least a portion of the tubular liner.
  • the apparatus further includes means for radially expanding the expansion cone.
  • the apparatus further includes means for lowering the expansion cone into the radially expanded portion of the shoe, and means for radially expanding the expansion cone.
  • the apparatus further includes means for injecting a fluidic material into the borehole below the radially expanded expansion cone. In a preferred embodiment, the apparatus further includes means for injecting a hardenable fluidic sealing material into an annulus between the tubular liner and the borehole. In a preferred embodiment, the apparatus further includes means for radially expanding at least a portion of the preexisting wellbore casing. In a preferred embodiment, the apparatus further includes means for overlapping a portion of the radially expanded tubular liner with a portion of the preexisting wellbore casing. In a preferred embodiment, the inside diameter of the radially expanded tubular liner is substantially equal to the inside diameter of a nonoverlapping portion of the preexisting wellbore casing.
  • the apparatus further includes means for applying an axial force to the expansion cone.
  • the inside diameter of the radially expanded shoe is greater than or equal to the inside diameter of the radially expanded tubular liner.
  • a wellbore casing positioned in a borehole within a subterranean formation has also been described that includes a first wellbore casing and a second wellbore casing coupled to and overlapping with the first wellbore casing, wherein the second wellbore casing is coupled to the first wellbore casing by the process of: installing the second wellbore casing, an expansion cone, and a shoe in the borehole, radially expanding at least a portion of the shoe by injecting a fluidic material into the shoe, and radially expanding at least a portion of the second wellbore casing by injecting a fluidic material into the borehole below the expansion cone.
  • the process for forming the wellbore casing further includes radially expanding the expansion cone.
  • the process for forming the wellbore casing further includes lowering the expansion cone into the radially expanded portion of the shoe, and radially expanding the expansion cone.
  • the process for forming the wellbore casing further includes radially expanding at least a portion of the shoe and the second wellbore casing by injecting a fluidic material into the borehole below the radially expanded expansion cone.
  • the process for forming the wellbore casing further includes injecting a hardenable fluidic sealing material into an annulus between the second wellbore casing and the borehole.
  • the process for forming the wellbore casing further includes radially expanding at least a portion of the first wellbore casing.
  • the process for forming the wellbore casing further includes overlapping a portion of the radially expanded second wellbore casing with a portion of the first wellbore casing.
  • the inside diameter of the radially expanded second wellbore casing is substantially equal to the inside diameter of a nonoverlapping portion of the first wellbore casing.
  • the process for forming the wellbore casing further includes applying an axial force to the expansion cone.
  • the inside diameter of the radially expanded shoe is greater than or equal to the inside diameter of the radially expanded second wellbore casing.
  • a method of forming a tubular structure in a subterranean formation having a preexisting tubular member positioned in a borehole includes installing a tubular liner, an expansion cone, and a shoe in the borehole, radially expanding at least a portion of the shoe by injecting a fluidic material into the shoe, and radially expanding at least a portion of the tubular liner by injecting a fluidic material into the borehole below the expansion cone.
  • the method further includes radially expanding the expansion cone.
  • the method further includes lowering the expansion cone into the radially expanded portion of the shoe, and radially expanding the expansion cone.
  • the method further includes radially expanding at least a portion of the shoe and the tubular liner by injecting a fluidic material into the borehole below the radially expanded expansion cone. In a preferred embodiment, the method further includes injecting a hardenable fluidic sealing material into an annulus between the tubular liner and the borehole. In a preferred embodiment, the method further includes radially expanding at least a portion of the preexisting tubular member. In a preferred embodiment, the method further includes overlapping a portion of the radially expanded tubular liner with a portion of the preexisting tubular member. In a preferred embodiment, the inside diameter of the radially expanded tubular liner is substantially equal to the inside diameter of a nonoverlapping portion of the preexisting tubular member. In a preferred embodiment, the method further includes applying an axial force to the expansion cone. In a preferred embodiment, the inside diameter of the radially expanded shoe is greater than or equal to the inside diameter of the radially expanded tubular liner.
  • An apparatus for forming a tubular structure in a subterranean formation having a preexisting tubular member positioned in a borehole includes means for installing a tubular liner, an expansion cone, and a shoe in the borehole, means for radially expanding at least a portion of the shoe, and means for radially expanding at least a portion of the tubular liner.
  • the apparatus further includes means for radially expanding the expansion cone.
  • the apparatus further includes means for lowering the expansion cone into the radially expanded portion of the shoe, and means for radially expanding the expansion cone.
  • the apparatus further includes means for injecting a fluidic material into the borehole below the radially expanded expansion cone.
  • the apparatus further includes means for injecting a hardenable fluidic sealing material into an annulus between the tubular liner and the borehole.
  • the apparatus further includes means for radially expanding at least a portion of the preexisting tubular member.
  • the apparatus further includes means for overlapping a portion of the radially expanded tubular liner with a portion of the preexisting tubular member.
  • the inside diameter of the radially expanded tubular liner is substantially equal to the inside diameter of a nonoverlapping portion of the preexisting tubular member.
  • the apparatus further includes means for applying an axial force to the expansion cone.
  • the inside diameter of the radially expanded shoe is greater than or equal to the inside diameter of the radially expanded tubular liner.
  • An apparatus for forming a tubular structure within a subterranean formation including a preexisting tubular member positioned in a borehole has also been described that includes a tubular liner and means for radially expanding and coupling the tubular liner to an overlapping portion of the preexisting tubular member.
  • the inside diameter of the radially expanded tubular liner is substantially equal to the inside diameter of a non-overlapping portion of the preexisting tubular member.
  • a tubular structure positioned in a borehole within a subterranean formation has also been described that includes a first tubular member and a second tubular member coupled to and overlapping with the first tubular member, wherein the second tubular member is coupled to the first tubular member by the process of: installing the second tubular member, an expansion cone, and a shoe in the borehole, radially expanding at least a portion of the shoe by injecting a fluidic material into the shoe, and radially expanding at least a portion of the second tubular member by injecting a fluidic material into the borehole below the expansion cone.
  • the process for forming the tubular structure further includes radially expanding the expansion cone.
  • the process for forming the tubular structure further includes lowering the expansion cone into the radially expanded portion of the shoe, and radially expanding the expansion cone.
  • the process for forming the tubular structure further includes radially expanding at least a portion of the shoe and the second tubular member by injecting a fluidic material into the borehole below the radially expanded expansion cone.
  • the process for forming the tubular structure further includes injecting a hardenable fluidic sealing material into an annulus between the second tubular member and the borehole.
  • the process for forming the tubular structure further includes radially expanding at least a portion of the first tubular member.
  • the process for forming the tubular structure further includes overlapping a portion of the radially expanded second tubular member with a portion of the first tubular member.
  • the inside diameter of the radially expanded second tubular member is substantially equal to the inside diameter of a nonoverlapping portion of the first tubular member.
  • the process for forming the tubular structure further includes applying an axial force to the expansion cone.
  • the inside diameter of the radially expanded shoe is greater than or equal to the inside diameter of the radially expanded second tubular member.

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Earth Drilling (AREA)
  • Structures Of Non-Positive Displacement Pumps (AREA)
  • Gasket Seals (AREA)

Abstract

L'invention concerne un cuvelage pour puits de forage (100) à un seul diamètre. Si le joint étanche fluidique du joint de recouvrement entre la partie d'extrémité supérieure (210d) de l'élément tubulaire (210) et la partie d'extrémité inférieure (115a) du cuvelage est satisfaisant, alors n'importe quelle partie non traitée du matériau (255) à l'intérieur de l'élément tubulaire allongé (210) est enlevée d'une manière conventionnelle.
PCT/US2002/004353 1998-12-07 2002-02-14 Cuvelage pour puits de forage a un seul diametre WO2002066783A1 (fr)

Priority Applications (5)

Application Number Priority Date Filing Date Title
CA002438807A CA2438807C (fr) 2001-02-20 2002-02-14 Cuvelage pour puits de forage a un seul diametre
GB0320747A GB2390622B (en) 2001-02-20 2002-02-14 Mono-diameter wellbore casing
AU2002240366A AU2002240366B2 (en) 2001-02-20 2002-02-14 Mono-diameter wellbore casing
US10/504,361 US7516790B2 (en) 1999-12-03 2003-01-09 Mono-diameter wellbore casing
US10/644,101 US7195064B2 (en) 1998-12-07 2003-08-13 Mono-diameter wellbore casing

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US27000701P 2001-02-20 2001-02-20
US60/270,007 2001-02-20

Related Parent Applications (1)

Application Number Title Priority Date Filing Date
US09/454,139 Continuation-In-Part US6497289B1 (en) 1998-11-16 1999-12-03 Method of creating a casing in a borehole

Related Child Applications (3)

Application Number Title Priority Date Filing Date
US11644101 A-371-Of-International 2002-02-14
US10504361 Continuation-In-Part 2003-01-09
US10/644,101 Continuation US7195064B2 (en) 1998-12-07 2003-08-13 Mono-diameter wellbore casing

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WO2002066783A1 true WO2002066783A1 (fr) 2002-08-29

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CA (1) CA2438807C (fr)
GB (1) GB2390622B (fr)
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US7740076B2 (en) 2002-04-12 2010-06-22 Enventure Global Technology, L.L.C. Protective sleeve for threaded connections for expandable liner hanger
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US7918284B2 (en) 2002-04-15 2011-04-05 Enventure Global Technology, L.L.C. Protective sleeve for threaded connections for expandable liner hanger
WO2021119613A1 (fr) * 2019-12-13 2021-06-17 Mohawk Energy Ltd. Système empilable de pièce de rapiéçage métallique déployable en ligne de fil métallique

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US7665532B2 (en) 1998-12-07 2010-02-23 Shell Oil Company Pipeline
GB2409218B (en) * 2001-08-20 2006-03-15 Enventure Global Technology Apparatus and method for radially expanding tubular members including an adjustable tubular expansion device
GB2409216A (en) * 2001-08-20 2005-06-22 Enventure Global Technology Method of forming a wellbore casing by radial expansion
GB2409217A (en) * 2001-08-20 2005-06-22 Enventure Global Technology An adjustable expansion cone for expanding a tubular member
GB2409218A (en) * 2001-08-20 2005-06-22 Enventure Global Technology An apparatus for radially-expanding a tubular member
GB2409216B (en) * 2001-08-20 2006-04-12 Enventure Global Technology Apparatus for radially expanding tubular members including a segmented expansion cone
GB2409217B (en) * 2001-08-20 2005-12-28 Enventure Global Technology Apparatus for radially expanding tubular members including an adjustable expansion device
US7384981B2 (en) 2001-11-14 2008-06-10 N.V. Nutricia Preparation for improving the action of receptors
US7740076B2 (en) 2002-04-12 2010-06-22 Enventure Global Technology, L.L.C. Protective sleeve for threaded connections for expandable liner hanger
US7918284B2 (en) 2002-04-15 2011-04-05 Enventure Global Technology, L.L.C. Protective sleeve for threaded connections for expandable liner hanger
US7739917B2 (en) 2002-09-20 2010-06-22 Enventure Global Technology, Llc Pipe formability evaluation for expandable tubulars
EP1549824A2 (fr) * 2002-09-20 2005-07-06 Enventure Global Technology Tubage de puits de forage a diametre unique
EP1549824A4 (fr) * 2002-09-20 2006-04-19 Enventure Global Technology Tubage de puits de forage a diametre unique
GB2396634A (en) * 2002-12-27 2004-06-30 Weatherford Lamb Downhole cutting tool and method
US7140444B2 (en) 2002-12-27 2006-11-28 Weatherford/Lamb, Inc Downhole cutting tool and method
GB2396634B (en) * 2002-12-27 2006-07-26 Weatherford Lamb Downhole cutting tool and method
US7886831B2 (en) 2003-01-22 2011-02-15 Enventure Global Technology, L.L.C. Apparatus for radially expanding and plastically deforming a tubular member
US7793721B2 (en) 2003-03-11 2010-09-14 Eventure Global Technology, Llc Apparatus for radially expanding and plastically deforming a tubular member
US7775290B2 (en) 2003-04-17 2010-08-17 Enventure Global Technology, Llc Apparatus for radially expanding and plastically deforming a tubular member
GB2402952A (en) * 2003-06-16 2004-12-22 Weatherford Lamb A method of expanding a tubing in a multiple stage process
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CA2438807C (fr) 2009-05-26
AU2002240366B2 (en) 2007-01-04
GB2390622A (en) 2004-01-14
GB2390622B (en) 2005-08-24
GB0320747D0 (en) 2003-10-08
CA2438807A1 (fr) 2002-08-29

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