EP0935051A2 - Method of forming a wellbore junction - Google Patents
Method of forming a wellbore junction Download PDFInfo
- Publication number
- EP0935051A2 EP0935051A2 EP99300795A EP99300795A EP0935051A2 EP 0935051 A2 EP0935051 A2 EP 0935051A2 EP 99300795 A EP99300795 A EP 99300795A EP 99300795 A EP99300795 A EP 99300795A EP 0935051 A2 EP0935051 A2 EP 0935051A2
- Authority
- EP
- European Patent Office
- Prior art keywords
- wellbore
- drilling
- formation
- forcing
- junction
- 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- Withdrawn
Links
- 238000000034 method Methods 0.000 title claims abstract description 70
- 239000000463 material Substances 0.000 claims abstract description 84
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 47
- 238000005553 drilling Methods 0.000 claims abstract description 31
- 230000000087 stabilizing effect Effects 0.000 claims abstract description 21
- 239000000203 mixture Substances 0.000 claims description 40
- 239000004593 Epoxy Substances 0.000 claims description 14
- 239000007788 liquid Substances 0.000 claims description 14
- 239000003795 chemical substances by application Substances 0.000 claims description 13
- 150000002118 epoxides Chemical class 0.000 claims description 13
- 230000000051 modifying effect Effects 0.000 claims description 5
- 239000011148 porous material Substances 0.000 claims description 5
- 238000005755 formation reaction Methods 0.000 description 35
- 239000000945 filler Substances 0.000 description 18
- 239000004568 cement Substances 0.000 description 14
- 239000003822 epoxy resin Substances 0.000 description 13
- 229920000647 polyepoxide Polymers 0.000 description 13
- WERYXYBDKMZEQL-UHFFFAOYSA-N butane-1,4-diol Chemical compound OCCCCO WERYXYBDKMZEQL-UHFFFAOYSA-N 0.000 description 10
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 description 6
- VEIOBOXBGYWJIT-UHFFFAOYSA-N cyclohexane;methanol Chemical compound OC.OC.C1CCCCC1 VEIOBOXBGYWJIT-UHFFFAOYSA-N 0.000 description 5
- GYZLOYUZLJXAJU-UHFFFAOYSA-N diglycidyl ether Chemical class C1OC1COCC1CO1 GYZLOYUZLJXAJU-UHFFFAOYSA-N 0.000 description 5
- 239000012530 fluid Substances 0.000 description 5
- SLCVBVWXLSEKPL-UHFFFAOYSA-N neopentyl glycol Chemical compound OCC(C)(C)CO SLCVBVWXLSEKPL-UHFFFAOYSA-N 0.000 description 5
- RNLHGQLZWXBQNY-UHFFFAOYSA-N 3-(aminomethyl)-3,5,5-trimethylcyclohexan-1-amine Chemical compound CC1(C)CC(N)CC(C)(CN)C1 RNLHGQLZWXBQNY-UHFFFAOYSA-N 0.000 description 4
- -1 aliphatic amines Chemical class 0.000 description 4
- IISBACLAFKSPIT-UHFFFAOYSA-N bisphenol A Chemical compound C=1C=C(O)C=CC=1C(C)(C)C1=CC=C(O)C=C1 IISBACLAFKSPIT-UHFFFAOYSA-N 0.000 description 4
- 238000003801 milling Methods 0.000 description 4
- PIICEJLVQHRZGT-UHFFFAOYSA-N Ethylenediamine Chemical compound NCCN PIICEJLVQHRZGT-UHFFFAOYSA-N 0.000 description 3
- XAGFODPZIPBFFR-UHFFFAOYSA-N aluminium Chemical compound [Al] XAGFODPZIPBFFR-UHFFFAOYSA-N 0.000 description 3
- 229910052782 aluminium Inorganic materials 0.000 description 3
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 description 3
- 239000010428 baryte Substances 0.000 description 3
- 229910052601 baryte Inorganic materials 0.000 description 3
- 229910000019 calcium carbonate Inorganic materials 0.000 description 3
- 238000007796 conventional method Methods 0.000 description 3
- 150000004985 diamines Chemical class 0.000 description 3
- 230000035699 permeability Effects 0.000 description 3
- 238000007789 sealing Methods 0.000 description 3
- 235000012239 silicon dioxide Nutrition 0.000 description 3
- BRLQWZUYTZBJKN-UHFFFAOYSA-N Epichlorohydrin Chemical compound ClCC1CO1 BRLQWZUYTZBJKN-UHFFFAOYSA-N 0.000 description 2
- 239000008365 aqueous carrier Substances 0.000 description 2
- 150000004982 aromatic amines Chemical class 0.000 description 2
- 150000001244 carboxylic acid anhydrides Chemical class 0.000 description 2
- 239000007859 condensation product Substances 0.000 description 2
- 238000013461 design Methods 0.000 description 2
- 230000000149 penetrating effect Effects 0.000 description 2
- 229920000642 polymer Polymers 0.000 description 2
- 238000005086 pumping Methods 0.000 description 2
- 230000003252 repetitive effect Effects 0.000 description 2
- 239000012260 resinous material Substances 0.000 description 2
- VILCJCGEZXAXTO-UHFFFAOYSA-N 2,2,2-tetramine Chemical compound NCCNCCNCCN VILCJCGEZXAXTO-UHFFFAOYSA-N 0.000 description 1
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- HJOVHMDZYOCNQW-UHFFFAOYSA-N Isophorone Natural products CC1=CC(=O)CC(C)(C)C1 HJOVHMDZYOCNQW-UHFFFAOYSA-N 0.000 description 1
- 239000004743 Polypropylene Substances 0.000 description 1
- 238000007792 addition Methods 0.000 description 1
- 150000008064 anhydrides Chemical class 0.000 description 1
- 230000000295 complement effect Effects 0.000 description 1
- 239000004020 conductor Substances 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 238000012217 deletion Methods 0.000 description 1
- 230000037430 deletion Effects 0.000 description 1
- 238000006073 displacement reaction Methods 0.000 description 1
- 229920001971 elastomer Polymers 0.000 description 1
- 239000000806 elastomer Substances 0.000 description 1
- 230000003628 erosive effect Effects 0.000 description 1
- 239000000835 fiber Substances 0.000 description 1
- 239000010439 graphite Substances 0.000 description 1
- 229910002804 graphite Inorganic materials 0.000 description 1
- 230000001939 inductive effect Effects 0.000 description 1
- 125000006838 isophorone group Chemical group 0.000 description 1
- 230000013011 mating Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 239000002991 molded plastic Substances 0.000 description 1
- 239000002861 polymer material Substances 0.000 description 1
- 229920001155 polypropylene Polymers 0.000 description 1
- 230000001681 protective effect Effects 0.000 description 1
- 229920005989 resin Polymers 0.000 description 1
- 239000011347 resin Substances 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 238000010008 shearing Methods 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
- 230000006641 stabilisation Effects 0.000 description 1
- 238000011105 stabilization Methods 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
Images
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
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/0035—Apparatus or methods for multilateral well technology, e.g. for the completion of or workover on wells with one or more lateral branches
- E21B41/0042—Apparatus or methods for multilateral well technology, e.g. for the completion of or workover on wells with one or more lateral branches characterised by sealing the junction between a lateral and a main bore
Definitions
- the present invention relates generally to operations performed in conjunction with subterranean wells, and more particularly provides apparatus and methods for achieving a lateral wellbore connection.
- exit joint made of a drillable material in the parent wellbore casing string, so that the time involved in milling through the casing would be virtually eliminated.
- the exit joint it would be desirable for the exit joint to be configured as a cementing shoe or other portion of a typical casing string.
- one deflection device may be used to guide a drill bit to cut through the casing string, and thereafter another deflection device may be used to guide other equipment from the parent wellbore to the lateral wellbore.
- the second deflection device could be rotationally oriented using the rotational orientation of the first deflection device.
- lateral wellbore connections which do not include materials which must be milled through to form lateral wellbores may nevertheless be stabilized.
- Such stabilized formations might have reduced permeability, increased fracture gradient and leak-off pressures, increased tensile and compressive strength, increased ductility, and/or otherwise modified properties.
- a lateral wellbore connection is provided which is efficient and economical in its construction and operation.
- Apparatus and methods provided by the present invention provide well bore junctions which are stabilized without the need for using non-drillable materials.
- the invention encompasses apparatus and methods for achieving a lateral wellbore connection.
- a material is disposed within a radially enlarged portion of a first wellbore and permitted to harden therein. The material is then drilled through to form a wellbore junction.
- the material may be forced into pores of a formation or subterranean strata surrounding the well bore junction. The material may be forced therein before or after a second wellbore is drilled intersecting the first wellbore.
- the material may be a hardenable epoxy composition having flexibility upon hardening, such as an epoxide containing liquid selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol, and a hardening agent selected from the group of aliphatic amines and carboxylic acid anhydrides.
- a hardenable epoxy composition having flexibility upon hardening, such as an epoxide containing liquid selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol, and a hardening agent selected from the group of aliphatic amines and carboxylic acid anhydrides.
- the composition is forced into a subterranean stratum by way of a wellbore penetrating it and by way of the porosity of the stratum.
- the epoxy composition is then allowed to hard
- the resulting flexible epoxy composition reduces the permeability of the stratum and increases its resistance to shear failure adjacent to the wellbore whereby the fracture gradient of the stratum is appreciably increased.
- a method of forming a wellbore junction comprising the steps of: drilling a first wellbore intersecting a subterranean formation; drilling a second wellbore intersecting the first wellbore and the formation; and forcing a stabilizing material into the formation surrounding the intersection of the first and second wellbores.
- the forcing step may be performed before or after the step of drilling the second wellbore.
- the method may further comprise the step of preparing the stabilizing material as a hardenable epoxy composition having a viscosity at 25°C in the range of from about 10 to about 100 centipoises and having flexibility upon hardening, and comprising an epoxide containing liquid and a hardening agent.
- the forcing step may further comprise forcing the epoxy composition into the formation by way of at least one of the first and second wellbores, and further comprising the step of allowing the epoxy composition to harden in the formation.
- the epoxide containing liquid may be selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol.
- the hardening agent may be selected from the group of aliphatic amines, aromatic amines and anhydrides. More specifically, the hardening agent may be selected from the group of triethylenetetramine, ethylene diamine, N-cocoalkyltrimethylene diamine and isophorone diamine and may be present in the composition in an amount in the range of from about 15% to about 31% by weight of the epoxide containing liquid in the composition.
- the hardening agent is isophorone present in the composition in an amount of about 25% by weight of the epoxide containing liquid in the composition.
- the epoxy composition may further comprise a filler selected from the group consisting of crystalline silicas, amorphous silicas, clays, calcium carbonate and barite.
- a method of modifying properties of a subterranean stratum surrounding a wellbore junction comprising the steps of: forcing a material into the stratum surrounding the wellbore junction; and permitting the material to harden within pores of the stratum.
- the method may further comprise the step of forming the junction by drilling a second wellbore intersecting a first wellbore, and the forcing step may be performed prior to, or after, drilling the second wellbore.
- the method may further comprise the step of preparing the material as a hardenable epoxy resin composition having a viscosity at 25°C in the range of from about 90 to about 120 centipoises and having flexibility upon hardening, and comprising an epoxy resin selected from the condensation products of epichlorohydrin and bisphenol A, an epoxide containing liquid and a hardening agent.
- the epoxy resin may have a molecular weight of 340 and a one gram equivalent of epoxide per about 180 to about 195 grams of resin.
- the method may further comprise the step of dispersing the hardenable epoxy resin composition in an aqueous carrier liquid.
- the epoxide containing liquid may be selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol and is present in the composition in an amount in the range of from about 15% to about 40%, for example 25%, by weight of the epoxy resin in the composition.
- the epoxide containing liquid may have a molecular weight in the range of from about 200 to about 260 and a one gram equivalent of epoxide per about 120 to about 165 grams of the liquid.
- the hardening agent may be selected from the group of ethylene diamine, N-cocoalkyltrimethylene diamine and isophorone diamine.
- the hardening agent may be present in the composition in an amount in the range of from about 5% to about 25% by weight of the composition.
- the hardening agent may be isophorone diamine and may be present in the composition in an amount of about 20% by weight of the composition.
- the epoxy resin composition may further comprise a filler selected from the group consisting of crystalline silicas, amorphous silicas, clays, calcium carbonate and barite.
- the filler may be present in the composition in an amount in the range of from about 15% to about 30% by weight of the composition.
- a method of modifying properties of a formation surrounding a wellbore junction comprising the steps of: preparing a hardenable epoxy resin composition having a viscosity at 25°C in the range of from about 90 to about 120 centipoises and having flexibility upon hardening comprising an epoxy resin selected from the condensation products of epichlorohydrin and bisphenol A, an epoxide containing liquid selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol present in the composition in an amount in the range of from about 15% to about 40% by weight of the epoxy resin in the composition and a hardening agent selected from the group of ethylenediamine, N-cocoalkyltrimethylene diamine and isophorone diamine present in the composition in an amount in the range of from about 5% to about 25% by weight on the composition; forcing the epoxy resin composition into the formation by way of at
- the method may further comprise the step of dispersing the hardenable epoxy resin composition in an aqueous carrier liquid.
- the epoxy resin composition may further comprise a filler selected from the group consisting of crystalline silicas, amorphous silicas, clays, calcium carbonate and barite.
- a method of stabilizing a subterranean formation comprising the steps of: drilling a first wellbore into the formation; positioning a tubular string in the first wellbore; flowing a stabilizing material into an annulus formed between the tubular string and the first well bore; permitting the stabilizing material to harden; and drilling through a sidewall of the tubular string and the hardened stabilizing material, thereby forming a second wellbore intersecting the first wellbore.
- the method may further comprise the steps of forcing the stabilizing material outwardly into the formation surrounding the first wellbore, and permitting the stabilizing material to harden within the formation.
- the forcing step may be performed before the step of drilling through the tubular string sidewall.
- the stabilizing material may be a hardenable epoxy composition.
- FIG. 1 Representatively and schematically illustrated in FIG. 1 is a method 10 which embodies principles of the present invention.
- directional terms such as “above”, “below”, “upper”, “lower”, etc., are used for convenience in referring to the accompanying drawings. Additionally, it is to be understood that the various embodiments of the present invention described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., without departing from the principles of the present invention.
- initial steps of the method 10 have been performed.
- a parent wellbore 12 has been drilled to a depth at which it is desired to install a string of casing 14.
- the method 10 advantageously uses a specially configured cementing shoe 16 as a part of the casing string 14.
- the cementing shoe 16 may be threadedly or otherwise attached to the remainder of the casing string 14 and is sealingly attached thereto.
- the cementing shoe 16 is also configured for use as an exit joint for drilling a lateral wellbore 18 (see FIG. 2).
- the cementing shoe 16 is made of one or more drillable materials.
- the cementing shoe 16 may include an inner filler material 20 and an outer case or container 22 enveloping the filler material.
- the inner filler material 20 may be cement or other cementitious material, may be reinforced, as with graphite or polypropylene fibers, etc., and may be integrally formed with the outer case 22.
- the outer case 22 may be fiber-reinforced resinous material, or it may be metallic, such as aluminum, etc. Of course, other materials may be used to construct the cementing shoe 16 without departing from the principles of the present invention.
- the cementing shoe/exit joint 16 is positioned at or very near the lower end of the casing string 14. This is an advantageous position for the exit joint 16 in the method 10, since in normal practice the lower end of a casing string is usually located in rock or other consolidated and stable formation.
- the lower end of the casing string 14 is preferably in a stable formation and is at least somewhat protected from damage during subsequent drilling and completion operations.
- conventional steps and items of equipment used in the cementing operation are not shown in the drawings or described herein, these being well known to those of ordinary skill in the art.
- the parent wellbore 12 has been extended by drilling downward through the casing string 14.
- Another casing or liner 24 has then been installed in a lower portion 26 of the parent wellbore 12 and cemented in place.
- the orienting member 28 Threadedly and sealingly attached at an upper end of the casing or liner 24 is an orienting member 28.
- the orienting member 28 includes an internal laterally inclined annular surface 30 and an internal annular recess or latching profile 32. Threadedly and sealingly attached above the orienting member 28 is a seal bore or polished bore receptacle (PBR) 34.
- PBR polished bore receptacle
- the casing 24, orienting member 28 and PBR 34 are installed in the parent wellbore 12, and the casing is cemented in place, before the lateral wellbore 18 is drilled.
- the inclined surface 30 may be oriented to face radially toward the lateral wellbore-to-be-drilled, or it may be otherwise directed, as will be explained in further detail below.
- the PBR 34 and an upper portion of the orienting member 28 extend above the lower parent wellbore 26, with at least the PBR extending into the cementing shoe 16.
- cement about the PBR 34 and orienting member 28 to further isolate the formation surrounding the lateral wellbore connection (see FIG. 4).
- an assembly 36 is conveyed into the parent wellbore 12, for example, by lowering the assembly via a work string, coiled tubing, etc. in a conventional manner.
- the assembly 36 includes a deflection device 38 and an orienting member 40.
- the deflection device 38 has a laterally inclined upper surface 42 formed thereon for deflecting cutting tools, such as drill bits, tubular members, other items of equipment, etc., laterally with respect to the parent wellbore 12.
- the deflection device 38 and orienting member 40 are representatively shown in FIG. 2 as being solid, but it will be readily appreciated that these elements could be made generally tubular, that is, having axial flow passages formed therethrough.
- the deflection device 38 When the assembly 36 is conveyed into the parent wellbore 12, the deflection device 38 is free to rotate relative to the orienting member 40.
- a release member or annular shear ring 44 attaches the deflection device 38 to the orienting member 40 and permits relative rotation therebetween.
- the deflection device 38 has been downwardly displaced relative to the orienting member 40, thus shearing the shear ring 44, and the deflection device is no longer permitted to rotate relative to the orienting member.
- Complementarily shaped mating splines 46 are formed on each of the deflection device 38 and orienting member 40, so that, when the assembly 36 is being conveyed into the well, the splines are disengaged, thereby permitting relative rotation between the deflection device and the orienting member 40.
- the deflection device 38 when the orienting member 40 is engaged with the PBR 34 and orienting member 28, and a downwardly directed axial force is applied to the deflection device 38 to shear the shear ring 44, such as by slacking off on a work string attached thereto at the earth's surface to thereby apply a portion of the work string's weight to the deflection device, the deflection device will displace axially downward and the splines 46 will engage, thereby preventing relative rotation between the deflection device and the orienting member 40.
- rotational locks may be used in place of the splines 46, such as clutches, other cooperatively engageable projections and recesses, etc., and other types of release members may be used in place of the shear ring 44, without departing from the principles of the present invention.
- a latch member or snap ring 48 is carried externally on the deflection device 38.
- the snap ring 48 radially outwardly extends into an annular recess or groove 50 formed internally on the orienting member 40.
- the snap ring 48 prevents the deflection device 38 from displacing upwardly relative to the orienting member 40 after the deflection device has displaced downwardly as shown in FIG. 2.
- the snap ring 48 maintains the splines 46 in engagement, and thereby prevents any relative rotation between the deflection device 38 and the orienting member 40.
- the orienting member 40 has a circumferential seal 52 carried externally thereon, which sealingly engages the PBR 34 when the assembly 36 is installed.
- seal 52 is optional, since it may not be desired to sealingly engage the assembly 36 with the orienting member 28, liner 24, etc. In that case use of the PBR 34 would be optional as well.
- orienting member 40 Also carried on the orienting member 40 are a series of circumferentially spaced apart keys or lugs 54 of conventional design for latching engagement with the latching profile 32. Additionally, a laterally inclined annular surface 56 is formed externally on the orienting member 40 for complementary engagement with the inclined surface 30 of the orienting member 28.
- the seal 52 sealingly engages the PBR 34.
- the inclined surfaces 30, 56 engage each other. If the upper orienting member 40 is not radially aligned with the lower orienting member 28, the surfaces 30, 56 will cooperate to cause the upper orienting member to rotate into radial alignment with the lower orienting member. At this point, the upper orienting member 40 is free to rotate relative to the deflection device 38.
- the keys 54 engage the latching profile 32, thereby latching the orienting members together, with the surfaces 30, 56 preventing further rotation of the orienting members relative to each other.
- the deflection device 38 is oriented so that the surface 42 faces toward the lateral wellbore-to-be-drilled using conventional methods, such as by using a gyroscope included in the work string used to convey the assembly 36 into the parent wellbore 12.
- An axially downwardly directed force is then applied to the deflection device 38, such as by applying a portion of the work string's weight to the deflection device. This force causes the shear ring 44 to shear, releasing the deflection device 38 for displacement relative to the orienting member 40.
- the deflection device 38 displaces downward, engaging the splines 46 and engaging the snap ring 48 in the groove 50. At this point, the deflection device 38 is rotationally locked with respect to the wellbore 12, and will remain in this position indefinitely, with the surface 42 facing toward the lateral wellbore-to-be-drilled.
- One or more cutting tools such as drill bits, may be lowered through the casing string 14 and deflected by the surface 42 to cut laterally through the cementing collar 16. In this manner, no milling is required to cut a window through the casing string 14.
- An opening 58 is drilled through a sidewall of the cementing collar 16 and extended outward from the parent wellbore 12 to form the lateral wellbore 18.
- the method 10 and apparatus shown in FIGS. 1 & 2 and described above are particularly well suited for repetitive rotational alignment of items of equipment relative to the wellbore 12 in these circumstances.
- the upper orienting member 40 may be unlatched from the lower orienting member 28, such as by applying an axially upwardly directed force to the assembly 36 to disengage the keys 54 from the latching profile 32, and the upper orienting member may be retrieved to the earth's surface with the deflection device 38 attached thereto.
- the deflection device 38 remains rotationally locked to the orienting member 40 as they are retrieved.
- an operator may note the orientation of the deflection device 38 relative to the orienting member 40. The operator may then attach another deflection device or other item of equipment to the orienting member 40 in the same orientation as the previously attached deflection device 38.
- the newly-attached item of equipment and the upper orienting member 40 are installed in the well and the orienting members 40, 28 are again engaged with each other, the newly-attached item of equipment may have the same radial orientation relative to the wellbore 12 as the deflection device 38 previously had.
- the newly-attached item of equipment might also be attached to the upper orienting member 40 with a different radial orientation, without departing from the principles of the present invention.
- the newly-attached item of equipment might be attached to another upper orienting member, similar to the upper orienting member 40, but not necessarily including the features which permit rotation and then rotational locking between the item of equipment and the upper orienting member, since radial orientation of the newly attached item of equipment relative to the upper orienting member may be fixed before conveyance into the well.
- FIGS. 3 & 4 optional steps of the method 10 are schematically shown, which may be utilized when relatively high pressure drilling or other operations are performed through the lateral wellbore connection.
- a liner 60 or other tubular member is shown inserted through the opening 58 formed through the cementing shoe 16 sidewall.
- the upper end of the liner 60 is sealingly disposed within the parent wellbore 12 in the interior ofthe casing 14.
- the lower end of the liner 60 is sealingly disposed within the lateral wellbore 18.
- the upper end of the liner 60 is sealingly engaged with the casing string 14 by a packer or liner hanger 62 attached to the liner.
- the lower end of the liner 60 is sealingly engaged with a PBR 64 attached to another liner or other tubular member 66 cemented in the lateral wellbore 18.
- a packer or liner hanger 62 attached to the liner.
- the lower end of the liner 60 is sealingly engaged with a PBR 64 attached to another liner or other tubular member 66 cemented in the lateral wellbore 18.
- many other ways of sealing the liner 60 in the parent and lateral wellbores 12, 18 may be used in the method 10 without departing from the principles of the present invention.
- another liner or other tubular member 68 is positioned extending through the lateral wellbore connection, but in this case the liner is used before the lateral wellbore 18 is drilled. However, it is to be clearly understood that the liner 68 could also be used after the lateral wellbore 18 has been drilled.
- the liner 68 is inserted through the cementing shoe 16 after the casing 24, orienting member 28 and PBR 34 are installed and cemented within the lower parent wellbore 26.
- the liner 68 is sealingly engaged within the casing string 14 above the cementing shoe 16 using a packer or liner hanger 70.
- the lower end of the liner 68 is sealingly engaged with the PBR 34.
- the parent wellbore 12 may be extended by passing drill bits, etc. through the casing string 14, liner 68 and casing 24, without applying any excessive fluid pressure to the lateral wellbore connection.
- an apparatus 80 embodying principles of the present invention is representatively and schematically illustrated.
- the apparatus 80 may be used in the method 10 described above, and may be used in other methods as well.
- the apparatus 80 is similar to the cementing shoe 16 described above, but differs in some respects also.
- the apparatus 80 includes a float collar 82 similar to float collars of conventional design and well known to those skilled in the art.
- the float collar 82 includes a float valve 84, which permits flow of cement or other material downwardly through an axial flow passage 86 formed therethrough, but prevents flow upwardly through the float collar.
- At least the float valve 84 portion of the float collar 82 is made of drillable material, such as aluminum, etc., and an annular area 88 between the float valve and an outer tubular housing 90 may be filled with the same or another drillable material, such as cement.
- An upper end of the housing 90 is configured for threaded and sealing attachment to a tubular member, such as casing of the casing string 14 shown in FIG. 1.
- Threadedly and sealingly attached below the float collar 82 is a cementing shoe 92.
- An axial flow passage 94 formed through the cementing shoe 92 is aligned with the flow passage 86 of the float collar 82.
- the float valve 84 When the float valve 84 is open, fluid or other material may flow from the flow passage 86 to the flow passage 94.
- the flow passage 94 is lined with a tubular flow conductor 96, which limits erosion of a filler material 98 radially outwardly surrounding the flow passage.
- the filler material 98 may be similar to the filler material 20 used in the cementing shoe 16 described above.
- the filler material 98 is shown in FIG. 5 as being made of cement, but it is to be understood that it may actually be a resinous material, a polymer, a fiber-reinforced material, an elastomer, or any of a variety of drillable materials.
- the cementing shoe 92 is attached to the float collar 82 by means of an outer tubular housing or case 100.
- the case 100 at least partially radially outwardly surrounds the filler material 98 and may include retaining structures, such as annular recesses 102, etc., formed internally thereon or attached thereto, for preventing movement of the filler material 98 relative thereto.
- the case 100 is preferably made of a drillable material, such as aluminum, etc., so that an opening, such as opening 58 shown in FIG. 2, may be easily drilled laterally therethrough.
- case 100 envelopes a substantial portion of the filler material 98, but that a lower generally hemispherical-shaped portion 104 of the filler material extends downwardly and outwardly therefrom. Thus, it is not necessary for the case 100 to completely circumscribe the filler material 98 in keeping with the principles of the present invention.
- the lower portion 104 may be otherwise shaped, and the case 100 may otherwise envelope the filler material 98, or be integrally formed therewith, without departing from the principles of the present invention.
- the lower portion 104 has flow passages 106 formed therein, each of which intersects the flow passage 94. As shown in FIG. 5, the flow passages 106 are formed through the filler material 98 and are unlined, but it is to be understood that the flow passages may be lined with protective material, and may be otherwise positioned, without departing from the principles of the present invention.
- FIG. 6 another apparatus 110 and method 112 embodying principles of the present invention are representatively and schematically illustrated.
- the apparatus 110 may be used in the method 112, in any of the methods described above, or in any other method, without departing from the principles of the present invention.
- the method 112 may use the apparatus 110, any of the other apparatus described above, or other apparatus, in keeping with the principles of the present invention.
- the apparatus 110 includes a float collar 114 and a cementing shoe or float shoe 116, each of which is made of drillable material. As shown in FIG. 6, the float collar 114 and cementing shoe 116 are made of a molded plastic or polymer material, but it is to be understood that the float collar and cementing shoe may be made of other drillable materials, or combination of drillable materials, without departing from the principles of the present invention.
- Each of the float collar 114 and cementing shoe 116 includes a float valve 118.
- the float valves 118 permit flow from the interior of a casing or other tubular string 120, from which the apparatus 110 is suspended, to an annulus 122 between the casing string and a wellbore 124 of the well, but prevent flow from the annulus to the interior of the casing string.
- initial steps of the method 112 have been performed.
- the well bore 124 has been drilled, at least to a point where it is desired to drill a lateral wellbore 126 extending outwardly therefrom.
- the wellbore 124 has been underreamed, that is, radially enlarged at the junction of the parent wellbore and the lateral wellbore-to-be-drilled 126.
- the lateral wellbore 126 is shown in dashed lines in FIG. 6, since it has not yet been drilled.
- Radially outwardly extending tunnels or cavities 128 have been formed in the underreamed portion of the wellbore 124, so that they extend into the formation 130 surrounding the wellbore junction.
- the radial cavities 128 may be formed by conventional techniques, such as jet cutting, using shaped charges, fracturing the formation during pumping of material 134 thereinto, etc.
- the apparatus 110 is then conveyed into the wellbore 124 suspended from the casing string 120.
- the apparatus 110 is positioned at the wellbore junction, so that the lateral wellbore 126 may be drilled therethrough intersecting the parent wellbore 124, as described above.
- Cement 132 is then pumped downwardly through the casing string 120, through the apparatus 110, and upwardly into the annulus 122.
- Another material 134 is tailed-in behind the cement 132, so that the cement is pushed upwardly into the annulus 122 above the wellbore junction and the material 134 fills the annulus surrounding the apparatus 110, including the underreamed portion of the wellbore 124 and the cavities 128.
- the material 134 could also be cement, or another drillable material, without departing from the principles of the present invention.
- Turbulence inducing structures 136 may be included on the apparatus 110 to aid in ensuring that the material 134 "sweeps" through the entire annulus 122 at the wellbore junction.
- the cement 122 and material 134 are then allowed to set and/or harden.
- the material 134 may be cement, it may be cement with enhanced properties, such as fiber-reinforced cement, or it may be any of a variety of other materials, such as polymers, epoxy-type materials, etc.
- the material 134 may be a comparatively low viscosity material, which may be pumped into the formation 130 surrounding the wellbore junction.
- Dashed lines 138 in FIG. 6 indicate that the material 134 may be forced outwardly into the formation 130 surrounding the wellbore junction, in which case the cavities 128 may be used to present increased surface area for admitting the material into the formation.
- a conventional operation known as a "top-side squeeze” may be performed after the material has been positioned in the annulus 122 surrounding the apparatus 110.
- fluid pressure is applied to the annulus 122 at the earth's surface to squeeze the material 134 into the pores of the formation 130.
- the formation 130 preferably has at least a minimal degree of permeability to permit the material 134 to flow thereinto.
- the collapse resistance at the wellbore junction may be vastly improved.
- the tensile strength, compressive strength and ductility of the formation 130 may be improved.
- the formation 130 may be made impermeable in the area surrounding the wellbore junction by, for example, filling its pores with the material 134.
- the leak-off and fracture propagation pressures of the formation 130 may be increased. Resistance of the formation 130 to chemicals may be improved.
- EP-A-0899417 An example of a material which may be used for the material 134 in the method 112 is described in EP-A-0899417.
- This application describes a hardenable epoxy composition, such as an epoxide containing liquid selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol, and a hardening agent selected from the group of aliphatic amines and carboxylic acid anhydrides. Aromatic amines may also be used as a hardening agent.
- the application describes methods of pumping the epoxy composition into subterranean stratum byway of a well bore penetrating the stratum and by way of the porosity of the stratum, and then allowing the epoxy composition to harden in the stratum.
- the above-described methods of stabilizing a wellbore junction may be used in other types of junctions, and may be utilized before or after drilling a wellbore at a junction.
- the wellbore junctions representatively illustrated in FIGS. 2 & 6 may be stabilized by forcing the material 134 into the formations surrounding the junctions either before the lateral wellbores 18, 126 are drilled, or after the lateral wellbores are drilled. Additionally, these operations may be performed in conjunction with wellbore stabilization methods described in EP-A-0899417.
- the lateral wellbore 126 is drilled in a similar manner as that described above for the method 10.
- the apparatus 110 may be drilled through and a deflection device utilized to deflect cutting tools outwardly therethrough to form the lateral wellbore 126.
- the method 112 does not require any time-consuming milling operations and may be performed in the course of substantially normal drilling and cementing operations.
Landscapes
- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Physics & Mathematics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
- Design And Manufacture Of Integrated Circuits (AREA)
- Thyristors (AREA)
- Bulkheads Adapted To Foundation Construction (AREA)
Abstract
Description
- The present invention relates generally to operations performed in conjunction with subterranean wells, and more particularly provides apparatus and methods for achieving a lateral wellbore connection.
- Where it is desired to drill a lateral wellbore from a parent wellbore, it is common practice to position a whipstock in casing lining the parent wellbore, and then mill a window through the casing. The lateral wellbore may then be drilled outward from the parent wellbore by passing drill bits through the window. Unfortunately, these operations are usually very time-consuming and, therefore, very expensive to perform.
- It would be advantageous to provide an exit joint made of a drillable material in the parent wellbore casing string, so that the time involved in milling through the casing would be virtually eliminated. For operational efficiency and structural integrity of the lateral wellbore connection, it would be desirable for the exit joint to be configured as a cementing shoe or other portion of a typical casing string.
- Since passage of tools, tubular members and other equipment from the parent wellbore to the lateral wellbore generally requires some rotational orientation, it would also be advantageous to provide apparatus which reduces the time required to rotationally orient items of equipment in the well. For example, one deflection device may be used to guide a drill bit to cut through the casing string, and thereafter another deflection device may be used to guide other equipment from the parent wellbore to the lateral wellbore. The second deflection device could be rotationally oriented using the rotational orientation of the first deflection device.
- It would also be advantageous to provide methods of modifying properties of formations or subterranean strata surrounding lateral wellbore junctions, or otherwise stabilizing the lateral wellbore junctions. In this manner, lateral wellbore connections which do not include materials which must be milled through to form lateral wellbores may nevertheless be stabilized. Such stabilized formations might have reduced permeability, increased fracture gradient and leak-off pressures, increased tensile and compressive strength, increased ductility, and/or otherwise modified properties.
- Accordingly, it is an object of the present invention to provide a lateral wellbore connection which does not require time-consuming milling operations, and which does not require repetitive downhole rotational orientation of items of equipment used therein. It is another object of the present invention to provide methods of stabilizing formations intersected by wellbore junctions, or otherwise modifying properties of subterranean strata surrounding wellbore connections.
- In carrying out the principles of the present invention, in accordance with an embodiment thereof, a lateral wellbore connection is provided which is efficient and economical in its construction and operation. Apparatus and methods provided by the present invention provide well bore junctions which are stabilized without the need for using non-drillable materials.
- In broad terms, the invention encompasses apparatus and methods for achieving a lateral wellbore connection. In one embodiment of the present invention, a material is disposed within a radially enlarged portion of a first wellbore and permitted to harden therein. The material is then drilled through to form a wellbore junction. In one aspect of the present invention, the material may be forced into pores of a formation or subterranean strata surrounding the well bore junction. The material may be forced therein before or after a second wellbore is drilled intersecting the first wellbore.
- In another aspect of the present invention, the material may be a hardenable epoxy composition having flexibility upon hardening, such as an epoxide containing liquid selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol, and a hardening agent selected from the group of aliphatic amines and carboxylic acid anhydrides. The composition is forced into a subterranean stratum by way of a wellbore penetrating it and by way of the porosity of the stratum. The epoxy composition is then allowed to harden in the stratum.
- Upon hardening, the resulting flexible epoxy composition reduces the permeability of the stratum and increases its resistance to shear failure adjacent to the wellbore whereby the fracture gradient of the stratum is appreciably increased.
- According to one aspect of the invention there is provided a method of forming a wellbore junction, the method comprising the steps of: drilling a first wellbore intersecting a subterranean formation; drilling a second wellbore intersecting the first wellbore and the formation; and forcing a stabilizing material into the formation surrounding the intersection of the first and second wellbores.
- The forcing step may be performed before or after the step of drilling the second wellbore.
- The method may further comprise the step of preparing the stabilizing material as a hardenable epoxy composition having a viscosity at 25°C in the range of from about 10 to about 100 centipoises and having flexibility upon hardening, and comprising an epoxide containing liquid and a hardening agent. The forcing step may further comprise forcing the epoxy composition into the formation by way of at least one of the first and second wellbores, and further comprising the step of allowing the epoxy composition to harden in the formation.
- The epoxide containing liquid may be selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol.
- The hardening agent may be selected from the group of aliphatic amines, aromatic amines and anhydrides. More specifically, the hardening agent may be selected from the group of triethylenetetramine, ethylene diamine, N-cocoalkyltrimethylene diamine and isophorone diamine and may be present in the composition in an amount in the range of from about 15% to about 31% by weight of the epoxide containing liquid in the composition.
- Preferably the hardening agent is isophorone present in the composition in an amount of about 25% by weight of the epoxide containing liquid in the composition.
- The epoxy composition may further comprise a filler selected from the group consisting of crystalline silicas, amorphous silicas, clays, calcium carbonate and barite.
- According to another aspect of the invention there is provided a method of modifying properties of a subterranean stratum surrounding a wellbore junction, the method comprising the steps of: forcing a material into the stratum surrounding the wellbore junction; and permitting the material to harden within pores of the stratum.
- The method may further comprise the step of forming the junction by drilling a second wellbore intersecting a first wellbore, and the forcing step may be performed prior to, or after, drilling the second wellbore.
- The method may further comprise the step of preparing the material as a hardenable epoxy resin composition having a viscosity at 25°C in the range of from about 90 to about 120 centipoises and having flexibility upon hardening, and comprising an epoxy resin selected from the condensation products of epichlorohydrin and bisphenol A, an epoxide containing liquid and a hardening agent.
- The epoxy resin may have a molecular weight of 340 and a one gram equivalent of epoxide per about 180 to about 195 grams of resin.
- The method may further comprise the step of dispersing the hardenable epoxy resin composition in an aqueous carrier liquid.
- The epoxide containing liquid may be selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol and is present in the composition in an amount in the range of from about 15% to about 40%, for example 25%, by weight of the epoxy resin in the composition.
- The epoxide containing liquid may have a molecular weight in the range of from about 200 to about 260 and a one gram equivalent of epoxide per about 120 to about 165 grams of the liquid.
- The hardening agent may be selected from the group of ethylene diamine, N-cocoalkyltrimethylene diamine and isophorone diamine.
- The hardening agent may be present in the composition in an amount in the range of from about 5% to about 25% by weight of the composition.
- The hardening agent may be isophorone diamine and may be present in the composition in an amount of about 20% by weight of the composition.
- The epoxy resin composition may further comprise a filler selected from the group consisting of crystalline silicas, amorphous silicas, clays, calcium carbonate and barite.
- The filler may be present in the composition in an amount in the range of from about 15% to about 30% by weight of the composition.
- According to another aspect of the invention there is provided a method of modifying properties of a formation surrounding a wellbore junction, the method comprising the steps of: preparing a hardenable epoxy resin composition having a viscosity at 25°C in the range of from about 90 to about 120 centipoises and having flexibility upon hardening comprising an epoxy resin selected from the condensation products of epichlorohydrin and bisphenol A, an epoxide containing liquid selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol present in the composition in an amount in the range of from about 15% to about 40% by weight of the epoxy resin in the composition and a hardening agent selected from the group of ethylenediamine, N-cocoalkyltrimethylene diamine and isophorone diamine present in the composition in an amount in the range of from about 5% to about 25% by weight on the composition; forcing the epoxy resin composition into the formation by way of at least one wellbore intersecting at the wellbore junction and by way of the porosity of the formation; and allowing the epoxy resin composition to harden in the formation.
- The method may further comprise the step of dispersing the hardenable epoxy resin composition in an aqueous carrier liquid.
- The epoxy resin composition may further comprise a filler selected from the group consisting of crystalline silicas, amorphous silicas, clays, calcium carbonate and barite.
- According to another aspect of the invention there is provided a method of stabilizing a subterranean formation, the method comprising the steps of: drilling a first wellbore into the formation; positioning a tubular string in the first wellbore; flowing a stabilizing material into an annulus formed between the tubular string and the first well bore; permitting the stabilizing material to harden; and drilling through a sidewall of the tubular string and the hardened stabilizing material, thereby forming a second wellbore intersecting the first wellbore.
- The method may further comprise the steps of forcing the stabilizing material outwardly into the formation surrounding the first wellbore, and permitting the stabilizing material to harden within the formation.
- The forcing step may be performed before the step of drilling through the tubular string sidewall.
- The stabilizing material may be a hardenable epoxy composition.
- Reference is now made to the accompanying drawings, in which:
- FIG. 1 is a schematic cross-sectional view of a first embodiment of an apparatus and method of drilling a subterranean well according to the invention, initial steps of the method having been performed.
- FIG. 2 is a schematic cross-sectional view of a second embodiment of an apparatus according to the present invention, and in which further steps of the first method have been performed.
- FIG. 3 is a schematic cross-sectional view of the first embodiment in which optional steps in drilling a lateral wellbore are performed;
- FIG. 4 is a schematic cross-sectional view of the first embodiment in which optional steps in drilling a parent well bore are performed;
- FIG. 5 is a schematic cross-sectional view of a third embodiment of an apparatus according to the present invention; and
- FIG. 6 is a schematic cross-sectional view of a fourth embodiment of an apparatus and second embodiment of a method for drilling a subterranean well according to the present invention, initial steps of the method having been performed.
-
- Representatively and schematically illustrated in FIG. 1 is a
method 10 which embodies principles of the present invention. In the following description of themethod 10 and other methods and apparatus described herein, directional terms, such as "above", "below", "upper", "lower", etc., are used for convenience in referring to the accompanying drawings. Additionally, it is to be understood that the various embodiments of the present invention described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., without departing from the principles of the present invention. - As depicted in FIG. 1, initial steps of the
method 10 have been performed. A parent wellbore 12 has been drilled to a depth at which it is desired to install a string ofcasing 14. Themethod 10 advantageously uses a specially configured cementing shoe 16 as a part of thecasing string 14. The cementing shoe 16 may be threadedly or otherwise attached to the remainder of thecasing string 14 and is sealingly attached thereto. - The cementing shoe 16 is also configured for use as an exit joint for drilling a lateral wellbore 18 (see FIG. 2). For this purpose, the cementing shoe 16 is made of one or more drillable materials. For example, the cementing shoe 16 may include an
inner filler material 20 and an outer case orcontainer 22 enveloping the filler material. Theinner filler material 20 may be cement or other cementitious material, may be reinforced, as with graphite or polypropylene fibers, etc., and may be integrally formed with theouter case 22. Theouter case 22 may be fiber-reinforced resinous material, or it may be metallic, such as aluminum, etc. Of course, other materials may be used to construct the cementing shoe 16 without departing from the principles of the present invention. - As shown in FIG. 1, the cementing shoe/exit joint 16 is positioned at or very near the lower end of the
casing string 14. This is an advantageous position for the exit joint 16 in themethod 10, since in normal practice the lower end of a casing string is usually located in rock or other consolidated and stable formation. Thus, when the cementing operation is performed and the cementing shoe 16 is cemented in place as depicted in FIG. 1, the lower end of thecasing string 14 is preferably in a stable formation and is at least somewhat protected from damage during subsequent drilling and completion operations. For convenience and clarity of illustration, conventional steps and items of equipment used in the cementing operation are not shown in the drawings or described herein, these being well known to those of ordinary skill in the art. - Referring additionally now to FIG. 2, the
method 10 is schematically and representatively illustrated in which additional steps have been performed. The parent wellbore 12 has been extended by drilling downward through thecasing string 14. Another casing orliner 24 has then been installed in alower portion 26 of the parent wellbore 12 and cemented in place. - Threadedly and sealingly attached at an upper end of the casing or
liner 24 is an orientingmember 28. The orientingmember 28 includes an internal laterally inclinedannular surface 30 and an internal annular recess or latchingprofile 32. Threadedly and sealingly attached above the orientingmember 28 is a seal bore or polished bore receptacle (PBR) 34. - In the
method 10, thecasing 24, orientingmember 28 andPBR 34 are installed in the parent wellbore 12, and the casing is cemented in place, before thelateral wellbore 18 is drilled. As shown in FIG. 2, theinclined surface 30 may be oriented to face radially toward the lateral wellbore-to-be-drilled, or it may be otherwise directed, as will be explained in further detail below. Additionally, note that thePBR 34 and an upper portion of the orientingmember 28 extend above the lower parent wellbore 26, with at least the PBR extending into the cementing shoe 16. Thus, it is possible to place cement about thePBR 34 and orientingmember 28 to further isolate the formation surrounding the lateral wellbore connection (see FIG. 4). - When it is desired to drill the
lateral wellbore 18, anassembly 36 is conveyed into the parent wellbore 12, for example, by lowering the assembly via a work string, coiled tubing, etc. in a conventional manner. Theassembly 36 includes adeflection device 38 and an orientingmember 40. Thedeflection device 38 has a laterally inclinedupper surface 42 formed thereon for deflecting cutting tools, such as drill bits, tubular members, other items of equipment, etc., laterally with respect to the parent wellbore 12. Thedeflection device 38 and orientingmember 40 are representatively shown in FIG. 2 as being solid, but it will be readily appreciated that these elements could be made generally tubular, that is, having axial flow passages formed therethrough. - When the
assembly 36 is conveyed into the parent wellbore 12, thedeflection device 38 is free to rotate relative to the orientingmember 40. A release member orannular shear ring 44 attaches thedeflection device 38 to the orientingmember 40 and permits relative rotation therebetween. However, as shown in FIG. 2, thedeflection device 38 has been downwardly displaced relative to the orientingmember 40, thus shearing theshear ring 44, and the deflection device is no longer permitted to rotate relative to the orienting member. - Complementarily shaped mating splines 46 are formed on each of the
deflection device 38 and orientingmember 40, so that, when theassembly 36 is being conveyed into the well, the splines are disengaged, thereby permitting relative rotation between the deflection device and the orientingmember 40. However, when the orientingmember 40 is engaged with thePBR 34 and orientingmember 28, and a downwardly directed axial force is applied to thedeflection device 38 to shear theshear ring 44, such as by slacking off on a work string attached thereto at the earth's surface to thereby apply a portion of the work string's weight to the deflection device, the deflection device will displace axially downward and thesplines 46 will engage, thereby preventing relative rotation between the deflection device and the orientingmember 40. Of course, other types of rotational locks may be used in place of thesplines 46, such as clutches, other cooperatively engageable projections and recesses, etc., and other types of release members may be used in place of theshear ring 44, without departing from the principles of the present invention. - A latch member or snap ring 48 is carried externally on the
deflection device 38. When thedeflection device 38 is downwardly displaced relative to the orientingmember 40 as described above, the snap ring 48 radially outwardly extends into an annular recess or groove 50 formed internally on the orientingmember 40. The snap ring 48 prevents thedeflection device 38 from displacing upwardly relative to the orientingmember 40 after the deflection device has displaced downwardly as shown in FIG. 2. Thus, the snap ring 48 maintains thesplines 46 in engagement, and thereby prevents any relative rotation between thedeflection device 38 and the orientingmember 40. - The orienting
member 40 has a circumferential seal 52 carried externally thereon, which sealingly engages thePBR 34 when theassembly 36 is installed. Use of the seal 52 is optional, since it may not be desired to sealingly engage theassembly 36 with the orientingmember 28,liner 24, etc. In that case use of thePBR 34 would be optional as well. - Also carried on the orienting
member 40 are a series of circumferentially spaced apart keys or lugs 54 of conventional design for latching engagement with the latchingprofile 32. Additionally, a laterally inclined annular surface 56 is formed externally on the orientingmember 40 for complementary engagement with theinclined surface 30 of the orientingmember 28. - As the upper orienting
member 40 engages thePBR 34 and lower orientingmember 28, several functions are performed. The seal 52 sealingly engages thePBR 34. The inclined surfaces 30, 56 engage each other. If the upper orientingmember 40 is not radially aligned with the lower orientingmember 28, thesurfaces 30, 56 will cooperate to cause the upper orienting member to rotate into radial alignment with the lower orienting member. At this point, the upper orientingmember 40 is free to rotate relative to thedeflection device 38. When the upper orientingmember 40 is radially oriented with respect to the lower orientingmember 28, the keys 54 engage the latchingprofile 32, thereby latching the orienting members together, with thesurfaces 30, 56 preventing further rotation of the orienting members relative to each other. - After the orienting
members deflection device 38 is oriented so that thesurface 42 faces toward the lateral wellbore-to-be-drilled using conventional methods, such as by using a gyroscope included in the work string used to convey theassembly 36 into the parent wellbore 12. An axially downwardly directed force is then applied to thedeflection device 38, such as by applying a portion of the work string's weight to the deflection device. This force causes theshear ring 44 to shear, releasing thedeflection device 38 for displacement relative to the orientingmember 40. Thedeflection device 38 displaces downward, engaging thesplines 46 and engaging the snap ring 48 in thegroove 50. At this point, thedeflection device 38 is rotationally locked with respect to the wellbore 12, and will remain in this position indefinitely, with thesurface 42 facing toward the lateral wellbore-to-be-drilled. - One or more cutting tools, such as drill bits, may be lowered through the
casing string 14 and deflected by thesurface 42 to cut laterally through the cementing collar 16. In this manner, no milling is required to cut a window through thecasing string 14. Anopening 58 is drilled through a sidewall of the cementing collar 16 and extended outward from the parent wellbore 12 to form thelateral wellbore 18. - Due to wear or other reasons, it may be desired to install another deflection device or other item of equipment at the lateral wellbore connection. The
method 10 and apparatus shown in FIGS. 1 & 2 and described above are particularly well suited for repetitive rotational alignment of items of equipment relative to the wellbore 12 in these circumstances. The upper orientingmember 40 may be unlatched from the lower orientingmember 28, such as by applying an axially upwardly directed force to theassembly 36 to disengage the keys 54 from the latchingprofile 32, and the upper orienting member may be retrieved to the earth's surface with thedeflection device 38 attached thereto. - Note that the
deflection device 38 remains rotationally locked to the orientingmember 40 as they are retrieved. At the earth's surface, an operator may note the orientation of thedeflection device 38 relative to the orientingmember 40. The operator may then attach another deflection device or other item of equipment to the orientingmember 40 in the same orientation as the previously attacheddeflection device 38. - Thus, when the newly-attached item of equipment and the upper orienting
member 40 are installed in the well and the orientingmembers deflection device 38 previously had. Of course, the newly-attached item of equipment might also be attached to the upper orientingmember 40 with a different radial orientation, without departing from the principles of the present invention. Additionally, the newly-attached item of equipment might be attached to another upper orienting member, similar to the upper orientingmember 40, but not necessarily including the features which permit rotation and then rotational locking between the item of equipment and the upper orienting member, since radial orientation of the newly attached item of equipment relative to the upper orienting member may be fixed before conveyance into the well. - Referring additionally now to FIGS. 3 & 4, optional steps of the
method 10 are schematically shown, which may be utilized when relatively high pressure drilling or other operations are performed through the lateral wellbore connection. In FIG. 3, a liner 60 or other tubular member is shown inserted through theopening 58 formed through the cementing shoe 16 sidewall. The upper end of the liner 60 is sealingly disposed within the parent wellbore 12 in theinterior ofthe casing 14. The lower end of the liner 60 is sealingly disposed within thelateral wellbore 18. - The upper end of the liner 60 is sealingly engaged with the
casing string 14 by a packer or liner hanger 62 attached to the liner. The lower end of the liner 60 is sealingly engaged with aPBR 64 attached to another liner or other tubular member 66 cemented in thelateral wellbore 18. Of course, many other ways of sealing the liner 60 in the parent andlateral wellbores 12, 18 may be used in themethod 10 without departing from the principles of the present invention. - It will be readily appreciated that such sealing engagement of the liner 60 operates to isolate the lateral wellbore connection from fluid pressures present in the
casing string 14 above the liner 60, such as those that might be experienced when thelateral wellbore 18 is drilled further outward from the parent wellbore 12. Thus, drill bits or other equipment may be conveniently transported through the lateral wellbore connection via the liner 60, and fluid pressures present in the parent wellbore 12 above the lateral wellbore connection will be isolated from the lateral wellbore connection during these operations. When there is no longer a need for the liner 60, it may be retrieved using conventional methods. - In FIG. 4, another liner or other tubular member 68 is positioned extending through the lateral wellbore connection, but in this case the liner is used before the
lateral wellbore 18 is drilled. However, it is to be clearly understood that the liner 68 could also be used after thelateral wellbore 18 has been drilled. - As shown in FIG. 4, the liner 68 is inserted through the cementing shoe 16 after the
casing 24, orientingmember 28 andPBR 34 are installed and cemented within thelower parent wellbore 26. The liner 68 is sealingly engaged within thecasing string 14 above the cementing shoe 16 using a packer orliner hanger 70. The lower end of the liner 68 is sealingly engaged with thePBR 34. In this manner, the parent wellbore 12 may be extended by passing drill bits, etc. through thecasing string 14, liner 68 andcasing 24, without applying any excessive fluid pressure to the lateral wellbore connection. - Referring additionally now to FIG. 5, an
apparatus 80 embodying principles of the present invention is representatively and schematically illustrated. Theapparatus 80 may be used in themethod 10 described above, and may be used in other methods as well. In many respects, theapparatus 80 is similar to the cementing shoe 16 described above, but differs in some respects also. - The
apparatus 80 includes afloat collar 82 similar to float collars of conventional design and well known to those skilled in the art. Thefloat collar 82 includes afloat valve 84, which permits flow of cement or other material downwardly through anaxial flow passage 86 formed therethrough, but prevents flow upwardly through the float collar. At least thefloat valve 84 portion of thefloat collar 82 is made of drillable material, such as aluminum, etc., and an annular area 88 between the float valve and an outertubular housing 90 may be filled with the same or another drillable material, such as cement. An upper end of thehousing 90 is configured for threaded and sealing attachment to a tubular member, such as casing of thecasing string 14 shown in FIG. 1. - Threadedly and sealingly attached below the
float collar 82 is a cementingshoe 92. Anaxial flow passage 94 formed through the cementingshoe 92 is aligned with theflow passage 86 of thefloat collar 82. When thefloat valve 84 is open, fluid or other material may flow from theflow passage 86 to theflow passage 94. - The
flow passage 94 is lined with atubular flow conductor 96, which limits erosion of afiller material 98 radially outwardly surrounding the flow passage. Thefiller material 98 may be similar to thefiller material 20 used in the cementing shoe 16 described above. Thefiller material 98 is shown in FIG. 5 as being made of cement, but it is to be understood that it may actually be a resinous material, a polymer, a fiber-reinforced material, an elastomer, or any of a variety of drillable materials. - The cementing
shoe 92 is attached to thefloat collar 82 by means of an outer tubular housing orcase 100. Thecase 100 at least partially radially outwardly surrounds thefiller material 98 and may include retaining structures, such as annular recesses 102, etc., formed internally thereon or attached thereto, for preventing movement of thefiller material 98 relative thereto. Thecase 100 is preferably made of a drillable material, such as aluminum, etc., so that an opening, such asopening 58 shown in FIG. 2, may be easily drilled laterally therethrough. - Note that the
case 100 envelopes a substantial portion of thefiller material 98, but that a lower generally hemispherical-shapedportion 104 of the filler material extends downwardly and outwardly therefrom. Thus, it is not necessary for thecase 100 to completely circumscribe thefiller material 98 in keeping with the principles of the present invention. Of course, thelower portion 104 may be otherwise shaped, and thecase 100 may otherwise envelope thefiller material 98, or be integrally formed therewith, without departing from the principles of the present invention. - The
lower portion 104 hasflow passages 106 formed therein, each of which intersects theflow passage 94. As shown in FIG. 5, theflow passages 106 are formed through thefiller material 98 and are unlined, but it is to be understood that the flow passages may be lined with protective material, and may be otherwise positioned, without departing from the principles of the present invention. - Referring additionally now to FIG. 6, another
apparatus 110 and method 112 embodying principles of the present invention are representatively and schematically illustrated. Theapparatus 110 may be used in the method 112, in any of the methods described above, or in any other method, without departing from the principles of the present invention. Additionally, the method 112 may use theapparatus 110, any of the other apparatus described above, or other apparatus, in keeping with the principles of the present invention. - The
apparatus 110 includes afloat collar 114 and a cementing shoe or float shoe 116, each of which is made of drillable material. As shown in FIG. 6, thefloat collar 114 and cementing shoe 116 are made of a molded plastic or polymer material, but it is to be understood that the float collar and cementing shoe may be made of other drillable materials, or combination of drillable materials, without departing from the principles of the present invention. - Each of the
float collar 114 and cementing shoe 116 includes a float valve 118. The float valves 118 permit flow from the interior of a casing or othertubular string 120, from which theapparatus 110 is suspended, to anannulus 122 between the casing string and awellbore 124 of the well, but prevent flow from the annulus to the interior of the casing string. - As shown in FIG. 6, initial steps of the method 112 have been performed. The well bore 124 has been drilled, at least to a point where it is desired to drill a
lateral wellbore 126 extending outwardly therefrom. Thewellbore 124 has been underreamed, that is, radially enlarged at the junction of the parent wellbore and the lateral wellbore-to-be-drilled 126. Thelateral wellbore 126 is shown in dashed lines in FIG. 6, since it has not yet been drilled. - Radially outwardly extending tunnels or
cavities 128 have been formed in the underreamed portion of thewellbore 124, so that they extend into theformation 130 surrounding the wellbore junction. Theradial cavities 128 may be formed by conventional techniques, such as jet cutting, using shaped charges, fracturing the formation during pumping ofmaterial 134 thereinto, etc. However, it is to be clearly understood that it is not necessary for thewellbore 124 to be underreamed, or for the underreamed portion to have thecavities 128 formed therein, in the method 112. - The
apparatus 110 is then conveyed into thewellbore 124 suspended from thecasing string 120. Theapparatus 110 is positioned at the wellbore junction, so that thelateral wellbore 126 may be drilled therethrough intersecting the parent wellbore 124, as described above. -
Cement 132 is then pumped downwardly through thecasing string 120, through theapparatus 110, and upwardly into theannulus 122. Anothermaterial 134 is tailed-in behind thecement 132, so that the cement is pushed upwardly into theannulus 122 above the wellbore junction and thematerial 134 fills the annulus surrounding theapparatus 110, including the underreamed portion of thewellbore 124 and thecavities 128. Of course, thematerial 134 could also be cement, or another drillable material, without departing from the principles of the present invention.Turbulence inducing structures 136, of the type well known to those skilled in the art, may be included on theapparatus 110 to aid in ensuring that the material 134 "sweeps" through theentire annulus 122 at the wellbore junction. Thecement 122 andmaterial 134 are then allowed to set and/or harden. - It will be readily appreciated that, by providing the underreamed portion of the
wellbore 124, and by filling theenlarged annulus 122 surrounding the wellbore junction with thematerial 134, the stability of the wellbore junction is significantly improved. The wellbore junction is, thus, made more resistant to collapse. Other benefits to the wellbore junction provided by the method 112 are more fully described below. - The
material 134 may be cement, it may be cement with enhanced properties, such as fiber-reinforced cement, or it may be any of a variety of other materials, such as polymers, epoxy-type materials, etc. For example, thematerial 134 may be a comparatively low viscosity material, which may be pumped into theformation 130 surrounding the wellbore junction. Dashedlines 138 in FIG. 6 indicate that thematerial 134 may be forced outwardly into theformation 130 surrounding the wellbore junction, in which case thecavities 128 may be used to present increased surface area for admitting the material into the formation. - In order to force the material 134 outwardly into the
formation 130, a conventional operation known as a "top-side squeeze" may be performed after the material has been positioned in theannulus 122 surrounding theapparatus 110. In this operation fluid pressure is applied to theannulus 122 at the earth's surface to squeeze thematerial 134 into the pores of theformation 130. Of course, theformation 130 preferably has at least a minimal degree of permeability to permit thematerial 134 to flow thereinto. - Note that, by forcing the
material 134 into theformation 130, several benefits may be achieved. The collapse resistance at the wellbore junction may be vastly improved. The tensile strength, compressive strength and ductility of theformation 130 may be improved. Theformation 130 may be made impermeable in the area surrounding the wellbore junction by, for example, filling its pores with thematerial 134. The leak-off and fracture propagation pressures of theformation 130 may be increased. Resistance of theformation 130 to chemicals may be improved. Of course, it is not necessary in the method 112 for all of these benefits to be obtained, since a choice of the material 134 to use in a particular situation may be tailored to the specific well conditions,formation 130 composition and properties, benefits desired, etc. - An example of a material which may be used for the material 134 in the method 112 is described in EP-A-0899417. This application describes a hardenable epoxy composition, such as an epoxide containing liquid selected from the group of diglycidyl ethers of 1,4-butanediol, neopentyl glycol and cyclohexane dimethanol, and a hardening agent selected from the group of aliphatic amines and carboxylic acid anhydrides. Aromatic amines may also be used as a hardening agent. Furthermore, the application describes methods of pumping the epoxy composition into subterranean stratum byway of a well bore penetrating the stratum and by way of the porosity of the stratum, and then allowing the epoxy composition to harden in the stratum.
- It will be readily appreciated that the above-described methods of stabilizing a wellbore junction may be used in other types of junctions, and may be utilized before or after drilling a wellbore at a junction. For example, the wellbore junctions representatively illustrated in FIGS. 2 & 6 may be stabilized by forcing the
material 134 into the formations surrounding the junctions either before thelateral wellbores - Once the
cement 132 and material 134 (if a separate material is utilized) have hardened in the representatively illustrated method 112, thelateral wellbore 126 is drilled in a similar manner as that described above for themethod 10. Theapparatus 110 may be drilled through and a deflection device utilized to deflect cutting tools outwardly therethrough to form thelateral wellbore 126. Thus, the method 112 does not require any time-consuming milling operations and may be performed in the course of substantially normal drilling and cementing operations. - Of course, many modifications, additions, substitutions, deletions and other changes may be made to the
methods 10, 112 and various apparatus described above.
Claims (10)
- A method of forming a wellbore junction, the method comprising the steps of: drilling a first wellbore (12) intersecting a subterranean formation; drilling a second wellbore (18) intersecting the first wellbore (12) and the formation; and forcing a stabilizing material into the formation surrounding the intersection of the first and second wellbores.
- A method according to Claim 1, wherein the forcing step is performed before the step of drilling the second wellbore (18).
- A method according to Claim 1, wherein the forcing step is performed after the step of drilling the second wellbore (18).
- A method according to Claim 1, 2 or 3, further comprising the step of preparing the stabilizing material as a hardenable epoxy composition having a viscosity at 25°C in the range of from about 10 to about 100 centipoises and having flexibility upon hardening, and comprising an epoxide containing liquid and a hardening agent, wherein the forcing step further comprises forcing the epoxy composition into the formation by way of at least one of the first and second wellbores, and further comprising the step of allowing the epoxy composition to harden in the formation.
- A method of modifying properties of a subterranean stratum surrounding a wellbore junction, the method comprising the steps of: forcing a material into the stratum surrounding the wellbore junction; and permitting the material to harden within pores of the stratum.
- A method according to Claim 5, further comprising the step of forming the junction by drilling a second wellbore intersecting a first wellbore, and wherein the forcing step is performed prior to drilling the second wellbore.
- A method according to Claim 5, further comprising the step of forming the junction by drilling a second wellbore intersecting a first wellbore, and wherein the forcing step is performed after drilling the second wellbore.
- A method of stabilizing a subterranean formation, the method comprising the steps of: drilling a first wellbore into the formation; positioning a tubular string in the first wellbore; flowing a stabilizing material into an annulus formed between the tubular string and the first wellbore; permitting the stabilizing material to harden; and drilling through a sidewall of the tubular string and the hardened stabilizing material, thereby forming a second wellbore intersecting the first wellbore.
- A method according to Claim 8, further comprising the steps of forcing the stabilizing material outwardly into the formation surrounding the first wellbore, and permitting the stabilizing material to harden within the formation.
- A method according to Claim 8 or 9, wherein the forcing step is performed before the step of drilling through the tubular string sidewall.
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US18924 | 1993-02-16 | ||
US1892498A | 1998-02-05 | 1998-02-05 |
Publications (2)
Publication Number | Publication Date |
---|---|
EP0935051A2 true EP0935051A2 (en) | 1999-08-11 |
EP0935051A3 EP0935051A3 (en) | 2001-05-16 |
Family
ID=21790449
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP99300795A Withdrawn EP0935051A3 (en) | 1998-02-05 | 1999-02-03 | Method of forming a wellbore junction |
Country Status (5)
Country | Link |
---|---|
EP (1) | EP0935051A3 (en) |
AU (1) | AU1134899A (en) |
BR (1) | BR9902419A (en) |
CA (1) | CA2260616A1 (en) |
NO (1) | NO990512L (en) |
Cited By (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2002048504A1 (en) * | 2000-12-15 | 2002-06-20 | Weatherford/Lamb, Inc. | An assembly and method for forming a seal in junction of a multilateral wellbore |
WO2005068777A2 (en) * | 2004-01-16 | 2005-07-28 | Halliburton Energy Services, Inc. | Methods of using sealants in multilateral junctions |
Citations (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
EP0899417A1 (en) | 1997-08-18 | 1999-03-03 | Halliburton Energy Services, Inc. | Method of modifying subterranean strata properties |
Family Cites Families (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US5301760C1 (en) * | 1992-09-10 | 2002-06-11 | Natural Reserve Group Inc | Completing horizontal drain holes from a vertical well |
US5423381A (en) * | 1993-10-29 | 1995-06-13 | Texaco Inc. | Quick-set formation treating methods |
DE19729809C1 (en) * | 1997-07-11 | 1998-12-17 | Flowtex Technologie Import Von | Device and method for producing borehole branches |
-
1999
- 1999-01-15 AU AU11348/99A patent/AU1134899A/en not_active Abandoned
- 1999-02-01 BR BR9902419-5A patent/BR9902419A/en not_active IP Right Cessation
- 1999-02-03 CA CA 2260616 patent/CA2260616A1/en not_active Abandoned
- 1999-02-03 EP EP99300795A patent/EP0935051A3/en not_active Withdrawn
- 1999-02-04 NO NO990512A patent/NO990512L/en not_active Application Discontinuation
Patent Citations (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
EP0899417A1 (en) | 1997-08-18 | 1999-03-03 | Halliburton Energy Services, Inc. | Method of modifying subterranean strata properties |
Cited By (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2002048504A1 (en) * | 2000-12-15 | 2002-06-20 | Weatherford/Lamb, Inc. | An assembly and method for forming a seal in junction of a multilateral wellbore |
WO2005068777A2 (en) * | 2004-01-16 | 2005-07-28 | Halliburton Energy Services, Inc. | Methods of using sealants in multilateral junctions |
WO2005068777A3 (en) * | 2004-01-16 | 2006-01-26 | Halliburton Energy Serv Inc | Methods of using sealants in multilateral junctions |
Also Published As
Publication number | Publication date |
---|---|
NO990512L (en) | 1999-08-06 |
CA2260616A1 (en) | 1999-08-05 |
NO990512D0 (en) | 1999-02-04 |
EP0935051A3 (en) | 2001-05-16 |
AU1134899A (en) | 1999-08-26 |
BR9902419A (en) | 2000-04-18 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
EP0935049B1 (en) | Wellbore apparatus and methods | |
US6935422B2 (en) | Expanding wellbore junction | |
US5884698A (en) | Whipstock assembly | |
US7575050B2 (en) | Method and apparatus for a downhole excavation in a wellbore | |
US20020056572A1 (en) | Downhole drilling apparatus and method for use of same | |
EP0945586A2 (en) | Method and apparatus for forming a wellbore junction | |
US8091246B2 (en) | Casing or work string orientation indicating apparatus and methods | |
GB2386627A (en) | Cementing system with a plug | |
EA002250B1 (en) | Method for formation of a plugin a petroleum well | |
US6454006B1 (en) | Methods and associated apparatus for drilling and completing a wellbore junction | |
US6830106B2 (en) | Multilateral well completion apparatus and methods of use | |
US20020023754A1 (en) | Method for drilling multilateral wells and related device | |
US10961818B2 (en) | Ball valve with dissolvable ball | |
US6712144B2 (en) | Method for drilling multilateral wells with reduced under-reaming and related device | |
AU746677B2 (en) | Apparatus and methods for sealing a wellbore junction | |
EP0935051A2 (en) | Method of forming a wellbore junction | |
US11111762B2 (en) | Method and device for multilateral sealed junctions | |
US11313189B2 (en) | Downhole check valve assembly with a frustoconical mandrel | |
GB2395215A (en) | Method of forming a wellbore junction | |
AU752761B2 (en) | Apparatus and methods for sealing a wellbore junction | |
GB2418443A (en) | Expandable wellbore junction |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
PUAI | Public reference made under article 153(3) epc to a published international application that has entered the european phase |
Free format text: ORIGINAL CODE: 0009012 |
|
AK | Designated contracting states |
Kind code of ref document: A2 Designated state(s): GB NL |
|
AX | Request for extension of the european patent |
Free format text: AL;LT;LV;MK;RO;SI |
|
PUAL | Search report despatched |
Free format text: ORIGINAL CODE: 0009013 |
|
AK | Designated contracting states |
Kind code of ref document: A3 Designated state(s): AT BE CH CY DE DK ES FI FR GB GR IE IT LI LU MC NL PT SE |
|
AX | Request for extension of the european patent |
Free format text: AL;LT;LV;MK;RO;SI |
|
RIC1 | Information provided on ipc code assigned before grant |
Free format text: 7E 21B 41/00 A, 7E 21B 33/138 B, 7E 21B 29/06 B |
|
17P | Request for examination filed |
Effective date: 20011106 |
|
AKX | Designation fees paid |
Free format text: GB NL |
|
REG | Reference to a national code |
Ref country code: DE Ref legal event code: 8566 |
|
STAA | Information on the status of an ep patent application or granted ep patent |
Free format text: STATUS: THE APPLICATION HAS BEEN WITHDRAWN |
|
18W | Application withdrawn |
Effective date: 20030324 |