GB2354546A

GB2354546A - A method for disengaging a support member embedded in the seabed

Info

Publication number: GB2354546A
Application number: GB0100157A
Authority: GB
Inventors: Gerald David Lynde; Greg Nazzal
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 1996-08-20
Filing date: 1997-08-20
Publication date: 2001-03-28
Anticipated expiration: 2017-08-20
Also published as: GB0100157D0; GB2354546B

Abstract

A method for disengaging a support member 310 embedded in the seabed 318 comprises positioning a cutting tool 324 at a predetermined position, adjacent the support member 310. Said cutting tool utilises a high pressure fluid jet as a cutting element, to cut though the support 310. In an embodiment of the invention the predetermined position may be below the seabed 318, the fluid jet may be used to disperse the material 320 allowing the cutting tool to move to its predetermined position. Alternatively a vibratory device may be used to urge the cutting tool through the material 320. The tool may be conveyed by a tubing, a wireline or by a robotic device. In the case of a robotic device the robot may also move the cutting tool along a predetermined path to effect cutting of the member 310.

Description

2354546 TITLE: SYSTEM FOR CUTTING MATERIALS IN WELLBORES

BACKGROUND OF THE INVENTION

1 Field of the Invention

This invention relates generally to cutting or milling tools for cutting 5 materials and more particularly to cutting tools utilizing a pressurized fluid for cutting materials in wellbores and other oilfield structures.

2. Backgroundof the Art

To produce hydrocarbons.(oil and gas) from the earth's formations, wellbores are formed to desired depths. The first. few hundred feet of the wellbore are typically -large in: diameter,:usually between 12 and 718 inches, and.are lined with a metal casing measuring about one half inch thick or more, to prevent caving in of the wellbore. The wellbore, typically between nine and twelve;inches in diameter,. is then drilled to recover hydrocarbons from the subsurface formations. After the wellbore has been. drilled to the desired depth, a metal pipe, generally referred -to in the art as the casing or pipe, is set in the wellbore with cement injected in the space (annulus) between the casing and the wellbore. Branch or lateral wellbores are frequently drilled from a main wellbore to form deviated or horizontal wellbores for improving hydrocarbon production from subsurface formations.

Several cutting and milling operations are performed to prepare a wellbore for production and also during the producing life of the wellbore. Some cutting 5 and milling examples are noted below.

In many applications, the branch or lateral wellbores-are formed after the wellbore has been cased. This requires milling or cutting a section (window) in the casing at a predetermined depth to initiate the drilling of the lateral wellbore. It is highly desirable to cut such windows -with enough precision to preserve the eventual juncture integrity. In older wellbores, the juncture between the. main wellbore and the lateral.. wellbore may have eroded and thus mc1y.-require.-the.removal':.of certain-.-.- materials'to!;:re0air,.sut-h--jundture or to perform secondary. operations., -It--is-Jesirable.toA-. remove:tha materials from the- -juncture with, precision:: imi.order,tal.Properly1 reconstruct, the, juncture;- Therefore;=-: it is desirable to have a, downhole cutting or milling tool that can selectively and relatively accurately cut windows in the casing downhole and can also remove,clesired amounts of materials around the junctions. -The-present invention provides such a downhole cutting.tool.

-various. types, -equipment, such-as After the.wellbore has been cased, Of liner hangers, permanent -packers; f luid flow -control, devices, etc.. 'are set- in the 2 wellbore and must be milled to perform secondary operations. Other devices, although designed to be retrievable without being milled, cannot be so removed from the wellbore due to malfunctions of such devices or excessive corrosion and, therefore, these devices must be milled. Additionally, sediments tend to slowly settle along the interior surfaces of production tubings, which reduces the effective flow area of such tubings. From time to time, such sediments must be reamed to maintain the desired fluid flow through the production tubings.

Vari ous types of downhole cutting and milling tools have been utilized in the oil and gas industry. These tools have,..been used for tasks such as removing materials from within wellbores including cutting existing casings, boring through permanently set packers and removing loose joints of pipes. Milling tools have been used to ream collapsed casings, to remove, burrs or oth.er imperfections from windows in the casings, to: place whipstocks; for drilling directional wellbores.and to perform other reaming operations.

Prior art cutting or milling tools typically include a tool body that is adapted to be conveyed into the wellbore. A plurality of cutting blades are

20. placed on the body at spaced intervals extending outwardly therefrom. Each Of the blades typically has a base with a leading surface relative to the direction of rotation. A suitable hard cutting material such as carbide is secured to the 3 blade's cutting edge. To perform a cutting or milling operation, the tool is placed at a desired location within the wellbore and rotated to cut the intended material. Th-e weight on the tool and the rotational speed determine the cutting speed. The tool blades are designed to cut the material in small segments so 5 that the cuttings may be transported to the surface by circulating a fluid in the wellbore or dropped to the wellbore bottom.

The cutting elements of such pr ior art must remain in hard contact with the material to be cut which erodes the cutting elements. The operating life of such cutting elements in some applications, therefore', can be relatively short.

In such cases, the cutting tool must be retrieved for changing the cutting element. This type of operation can result in -down time for the well and rig, which can:cost- several, thousand day:, The, cutting. I area:. of prior art cutting,-tools-: is -.relatively.-. large and, --thusi ill suited to cut relatively precise sections or windows in the casings. It is also difficult to orient such prior art cutting tools to perform contoured cutting of areas within- the wellbores.

The present invention addresses many of the deficiencies -of the prior art cutting.and milling tools for- downhole:use:and.-provid es cutting tools wherein the cutting element- is,relativelTsmall.-does; n6rcontact -.the %-surface- to be-cut- 4 and can cut materials relatively precisely. The small cutting element makes precise cuts possible while the lack of surface contact extends its useful life. The cutting element can be positioned and oriented in the wellbore to continuously cut Materials according to a predetermined profile or trace. The cutting too[ of the present invention can also be utilized for cutting other structures, such as nested pipes and offshore platforms.

Also, it would be advantageous to. be able to "see" (image) a particular worksite, determine what specific work needs to be performed based on the imaging information and then perform the work, preferably with tools that have been run downhole at the same time as the imaging equipment. The current technique is to run imaging equipment downhole, collect the imaging information and then pull the imaging equipment out of the borehole before running the necessary tool(s) downhole to do the work. The cutting tool of the present invention is preferably 'run with a suitable imaging device;, which enables imaging the worksite before, during and after the cutting operation. This allows the operator to determine the type of cut that needs to be made, send the proper signals to the cutting tool and. perform the cutting operation during a single trip downho(e, thus redUcing lost time.

SUMMARY OF THE INVENTION

The present invention provides a downhole cutting tool for cutting materials at a worksite in a wellbore. The cutting tool includes a cutting element that is adapted to discharge a high pressure fluid therefrom. A power unit in the tool includes a plurality of serially-arranged pressure stages, wherein each such stage increases the fluid pressure above its preceding stage until the desired high pressure has been obtained. The high pressure fluid is discharged through the cutting element as a jet stream to effect cutting of a material. A pulsar in the tool is provided to pulse the fluid before it is discharged. Pulsed jet strearrisrequire lower pressure compared non-pulsed jet streams to perform the same cutting operation. A control unit in the tool contains devices which operate, the cutting- elementi- power: unit- -and.. pulser." 'The 'operation of the devices in the control unit is controlled by a microprocessor-based downhole circuit according to programmed: instructions.-: The program may contain pTedetermined cutting pattern or profile. The downhole circuit communicates with a surface computer via a two-way telemetry system. An imaging device may be included in the downhole cutting tool -to obtain images of the worksite prior, during and after the cutting operations.

The present invention provides a, method Ior cutting a material at a worksite in a wellbore with a cutting tool which has a cutting -element thavis, 6 adapted to discharge a high pressure fluid therefrom. The method of the invention comprises: (a) conveying the cutting tool into a wellbore; (b) positioning the cutting element a predetermined distance from the material to be cut; (c) discharging the high pressure fluid from the cutting element at a predetermined pressure that is sufficient to cut the material; and (d) moving the cutting element according to a predetermined pattern to cut the material along a desired pattern.

The present invention also provides methods for deploying a cutting tool underwater and cutting structural support members embedded in a seabed to disengage an offshore structure from the seabed or for cutting portions of such underwater structures. Additionally, the present invention provides a method of cutting sections of nested pipes to facilitate the removal of suc6 pipes from a borehole.

Features of the invention have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may by appreciated. There are additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto.

7 BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present invention, references should be made to the following detailed description of the preferred embodiments, taken in conjunction with the accompanying drawings, in which like.elements have been given like numerals, and wherein:

FIG. 1 is a schematic diagram of an embodiment of a cutting system wherein the cutting element of the downhole cutting tool, is shown positioned 10 in a wellbore for performing a cutting operation.

FIG. 2A shows a manner of,positioning the cutting element in the downhole cutting tool, of FIG. 1. to cut ia..-member.. beneath ther-cuttingtool:--- FIG 213-C illustrate an alternative manner for positioning the cutting element in the downhoie cutting tool to cut materials beneath the cutting tool.

FIG 3 is a schematic diagram of an example of a predetermined profile a section of the casing to be cut that. may be stored in, a memory associated with the cutting system of FIG. 1 for later use.- FIG 4 is a schematic diagram of the;downhole-too['-of- FIG. 1,. adjacent:a- 8 juncture with a downhole imaging tool attached thereto for obtaining images of the work area.

FIG. 5 is a schematic functional block diagram relating to the operation 5 of the cutting system shown in FIGS. 1-3.

FIG. 6A-B show two different methods of disengaging an offshore structure that is supported on tubular members embedded in the seabed by utilizing the cutting tool of the present invention. 10 FIG. 6C is a partial exploded view of the cutting tool of FIG. 6A-B.

FIG. 7 illustrates a method of removing nested pipes from a"weilbore utilizing the cutting tool of the present invention. 15 9 DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

FIG. 1 is a schematic diagram of a system 10 for cutting or milling materials in a wellbore (borehole) 22. In general, the cutting system 10 includes a downhole tool that discharges high pressure jet stream through a cutting element to cut materials downhole. A downhole power unit supplies the high pressure fluid to the cutting element. The system 10 can be programmed to continuously position the jet stream to cut materials according to predefined profiles. A downhole circuit controls the operation of the downhole devices and 10 provides "two-way communication with a surface computer.

Referring to FIG. 1, the system 10 includes a downhole cutting tool (herein referred to::as.the ",cutting,tool').120: conveyed4rom a-platform 1,1:-of,a derrick 12 into a borehole 22 by a. suitable conveying: member 24, such -as a 15 coiled-tubing, jointed tubulars or wireline. The. cutting -tool 20 has.,.a housing 26, which adapted for connection with the conveying member 24 via a suitable connector 19. The housing 26 preferably contains the various elements of the cutting tool 20, which include a cutting element section 28, a power section 34 for supplying pressurized fluid to the cutting element section 28, a control unit 36 which controls the vertical and radial position of the control element section' 28 and a downhole electronic section.38. that- houses. circuitry- and memory associated with the downhole tool 20. - - The cutting element section 28 houses a cutting element 30 that terminates in a nozzle or probe 32 suitable for discharging a relatively high pressure fluid therefrom in the form of a high pressure jet stream of a relatively small cross sectional area. A majority of the downhole cutting operations require cutting or milling metaffic materials less than one inch thick, for which high pressure of sixty thousand pounds or less is usually sufficient. For thicker materials, higher pressure may be. required. The nozzle 32 can be made strong enough to withstand discharge pressures of greater than 200,000 psi. The cutting element section 28 is rotatable about a joint 31 that connects the cutting element section 28 with a fluid power section, generally denoted herein by numeral 34. The fluid can be water or wellbore fluid or any other fluid having similar properties. Abrasive material can be mixed with the fluid to improve cutting characteristics.

The power section 34 preferably includes a plurality of serial section PlPn- Each successive section increases the pressure of the fluid above the pressure of the preceding section by a predetermines amount. The last section.P. discharges the fluid into the cutting element section 28 at the desired pressure. The power section 34 also may contain a device 35 that pulses the fluid supply-through one or more of the power sections PI-Pn such that:the fluid supplied to the cutting element 30 is pulsed at the predetermined rate or frequency. High pressure pulsed jet streams are generally more effective in 1 cutting materials than non-pulsed jet streams. The cutting element 30 may be a telescopic. member, in that it moves axially (along the tool longitudinal axis) within the cutting element section 28. This movement is calculated to aflow positioning the probe 32 at the desired depth adjacent to the wellbore casing 23. The. cutting element section 28.orlthe cutting element 30 can be rotated to position the nozzle 32 at a radial locationwithin the wellbore 22. These movements of-, nozzle. provide degrees of.freedom. along the axial and radial directions of the wellbore 22, allowing accurate. positioning of the nozzle 32 at any location within the wellbore 22. Any, other. desirable movement of an element of cutting the tool 20 may be incorporated for the purpose of this invention.

A control section. 36, preferably.placed. _above,-the-.,,,power: section34;t, contains devices for orienting the nozzle 32-at.the desired -position. One or.

more. such-devices.,rotate the. outting.elementseefton!,28:.,to radially position the nozzle 32. Any suit-able hydraulically-operated devicesor electric motors are preferably utilized.. to perform such functions. Any..such suitable device, however, may be utilized for the purpose of this invention. The control section 36 also preferably includes sensors for providing information about the tool 20..inclination, nozzle.. position -relative.to.the material.to be.cut. and-.to.-one or more.known reference-points.in the. tool.,., Such sensors. ,,. however, may. be. placed. at any other desired -locations.-in.i.the. tool.20- In.the- conf iguration-shown-,in-FIG 12 1, the. cutting element 30 can cut materials along the wellbore interior, which may include the casing 23 or an area around a junction between the wellbore 22 and a branch wellbore 37, as shown in FIG. 4..

_,5 In applications where the material to be cut is below the cutting tool 20, the cutting element 30 may be configured to suit such applications. FIG. 2A shows a configuration of a cutting element 30' that is designed to cut materials below the cutting tool 20. In this configuration, the probe 32' discharges the fluid downhole along the tool axis. The cutting element 30' can be moved to any laterally within the section 28'. Arrows A-A indicate that the' cutting element 30' may be moved laterally while the arrows B-B indicate that the cutting element 30' may be moved along a circular path within the section.28'. The cutting element configuration shown in FIG. 2A is useful for p6rforming reaming operations in tubular members, such as:a production tubings. Reaming is required when the interiors of such tubings are lined with sedimeriit.

To remove:devices such as permanent packers or packers that cannot otherwise be removed because they are -stuck in the wellbore, it is desirable to cut away only the packing elements and associated anchors, if any, which typically lie between a packer body and the wellbore interior. The packers and anchors engage the casing. Prior art tools typically cut through the entire packer, which generally require excessive time. The packers can be ri6moved

13 relatively quickly by cutting only the packing elements and any associated anchors. In such applications, the cutting nozzle 30 is positioned. over the packing element alone. FIGS. 2B-C show a configuration of the cutting element 30" whose nozzle 32" may be placed at any desired location within the wellbore. Arrows C-C indicate that the probe 32" may be moved radially within the section 28" while the circular path defined by arrows D-D indicates that the cutting element may be rotated within the wellbore 22. FIG. 2C shows.the.

position of the cutting element 30" after it has been moved radially a predetermined distance. As is seen in FIG. 2C, the nozzle 32" extends beyond the section 28" which will allow the tool 20 to cut materials of larger sizes than the tool 20 diameter anywhere:in the wellbor6 22 below the tool 20.

As-shown in.:FIG., lj-electrical circuitsii ndAownholo:power-- supplies, for operating.-and controlling,- the- operation -of -the, cutting element 30.- the power.

unit 34, and the devices and -sensors 7placed',in -section 34--are preferably placed in a common electrical circuit section 38. Electrical connections between the electrical circuit section 38 and other elements are provided through suitable conductors and connectors.

A surface control unit.70--:pIaced-,at.a suitable locationon- the rig:, platform 11 preferably controls,4he- operation of---the;:: cutfing:-system-,10.- The -control, unit - includes a suitablecomputer,--asso-ciated-memory,"-a--recorder,,for recording--- 14 data and a display or monitor 72. Suitable alarms 74 are coupled to the surface control unit 70 and are selectively activated by the control unit 70 when certain predetermined operating conditions occur.

The operation of the cutting system 10 will now be described with respect to cutting a section or window in: a casing while referring to FIGS. 1 and 3. The tool'20 is conveyed downhole and positioned such that the nozzle 32 is adjacent the section to be cut. The stabilizers 40a-b are then set to ensure minimal radial movement of the tool -20 in the wellbore 22. A cutting 10 -profile 80 (FIG. 3) defining the coordinates for the outline of the section to be cut is stored in-a memory associated with the system 10. Such memory may be disposed in the electrical circuit section 36 or in the surface control unit 70.

An example of such Profile 80 is shown in FIG. 3. The arrowt 82 define prferably the vectors associated 'with the profile 80. The profile 80 is" displayed on the monitor 72 at the surface. An operator orients the nozzle tip 32 at a location within the section -of the ci s ing 23 to be out. The desired values of the fluid pressure and the pulse rate are input into the surface control unit 70 by a suitable device, such as keyboard, or are selected from a prerecorded- data, prefera6le in the form of a menu. The tool cutting 20 is then activated to generate the required pressure and the pulse rate, if any. The power section 34 causes the fluid to pulse at a predetermined rate and the fluid pressure to rise to a predetermined value. The fluid to the tool 20 is preferably provided from the surface via the tubing 24. Alternatively, the wellbore fluid may be used.

If the section to be cut is one that it will remain in position after it has been cut,. perhaps due to the presence of a cement bond, or if the cut section can be dropped to the- wellbore bottom as debris, then the system 10 may be set so that the nozzle tip 32 will follow the profile 80, either -by manual control by the operator or due to the use of a computer model or program in the system. If the section must be cut into small pieces or cuttings to be transported to the surface by a circulating fluid, the: cutting element is moved within the profile at a predetermined speed along a predetermined pattern, such as a..matrix. Such:cutting - methoft, ensure that Ahe-materialswill:be.- CUt into, pieces that are. small enough.:to, be: transported --by--. circulating fluids.: During:

operations, the.downhole circuits.. contained in-the-electrical: circuit section 38 pommunicate with the surface control unit 70 via a two-way telemetry, which is preferably contained,in a section 39.

FIG. 4 shows the downhole. too],of FIG. 1, with an imaging device 90 attached below-the cutting, section.-.28..'. Imaging - tools image a.. borehole interior have. been-.provided in.:the..art and, lltherefore:: are:; novdescribed.:in -detail, herein., The imaging -device 90 -is -utilized to corifirrn'the shape of. the section 16 of the -casing or the junction after the cutting operation has been performed. The imaging device 90 ma y also be utilized to image the arqp to be cut to generate the desired cutting profile and then to confirm the cut profile after-the cutting operation. Alternatively, the imaging device 90 may be placed in or at any suitable location above the cutting element section 28.

FIG. 5 is a functional block diagram of the control circuit 100 for the cutting system 10 (see FIG. 1). The downhole section of the control circuit 100 preferably includes a microprocessor-based downhole control circuit 110.

The downhole control circuit 110 determines the position and orientati. on of the tool as shown in box 112. The downhole control circuit 110 controls the position and orientation of the cutting element 30 (FIG. 1) as shown in box 114. During operations, the downhole control circuit 110 receives inf rmation from other downhole devices and sensors, such as a depth indicator 118 and orientation devices, such as accelerometers and gyroscopes.

The downhole control circuit 110 communicates with the surface control unit 70 via the downhole telemetry 39 and via a data or communication link 85. The downhole control- circuit 110 preferably controls the operation of the downhole devices, such as the power unit 34, stabilizers 40a-b and other desired downhole devices. The downhole control circuit 110 includes 'memory 120 for storing therein data and programmed instructions. The surface' control 17 unit 70 preferably includes a computer 130, which manipulates data, a recorder 132 for recording images and other data and an input device 134, such as a keyboard or a touch, screen for inputting instructions and for displaying information on the monitor 72. The surface control unit 70 communicates with the downhole tool via a surface telemetry 136.

TIG. 6A-613 illustrate -two- methods. of disengaging an offshore platform structure 300 from a seabed 318 utilizing cutting tools such as those described above As shown in FIG. 6A, the offshore platform structure 300 is supported on a plurality of structural members 310 that are connected to a base 312 and then extend downward.:through water.316 until they are embedded in the seabed 318 at a predetermined depth.

To disengage:the. platform 300, a cutting-tool 324:is conveyed -from.the platform base 31.2, via a.device such as. coiled. tub in g.-.326-, with a. tracking device 323 which is controlled by the.surface control unit 70 (shown in FIG. 1) or by an underwater controller 325, along the outside periphery of the structural member 310 until it reaches a desired cutting point 328 on the structural member 310. The tracking device 323 can be-tracking members (not shown) on the cutting. too[ 324. that enable the cutting tool 324 to remain,. latched onto the structural member: 310 o r a - robotics devic& tha guides 41ha cutting:: tool:324:

along the periphery-of the structural. member-310. -The, structural,!member-310 18 can.be of any shape used in the industry. Some examples include a tubular member and an I-beam type member. The cutting too] 324 als.o is adapted to travel axially and radially along the structural member 310, controlled by the surface control'unit 70 (shown in FIG. 1).

Earthen material 320 surrounding the cutting point 328 is displaced such that the cutting tool 324 can be positioned in its cutting position adjacent the structural member 310. Prior art methods typically use an underwater excavation tool (not shown) to clear an area approximately forty feet in diameter and twenty feet in depth around the area to be out.

With the present invention, however, this expensive and time-consuming method can be eliminated. by using the cutting tool 324 itself to clear a pathway- To displace the earthen material 320, the cutting tool nozzle(s) 32 can be oriented downward, as. shown - by zolid and dotted lines in FIG.-, 6C, and,-a regulated amount of pressurized fluid. released to move the earthen, material 320 out of the way of the cutting tool 324 as it progresses towards the cutting pqint32-8; The cutting. element 32 is7thOn -oriented. substantially perpendicular to the surface to.be cut (as shown in FIG. 1) to cut the support member.

Another method.of positioning the cutting -tool 324-..is to utilize a, vibratory source that can be included in the under water controller 325. The vibrations allow the cutting tool 324 to easily move through the earthen material 320 to 19 the desired cutting point 328. Once the earthen material 320 has been displaced, the cutting tool 324 continues downward along the outside surface of the structural member 310 until it reaches the predetermined cutting point.

The cutting tool- 324 then performs the required cut, such as a circumferential cut, around the outside of the structural member 310. To accomplish this cut, the cutting, tool 324is moved around the periphery of the structural member 310 while a jet of high pressure fluid is directed from the cutting tool nozzle 32 at the predetermined cutting line under control of the surface control unit 70 or the under water controller 325. If a robotics device is.used, the system can be programmed wherein the robotics device moves the cutting tool to -a desired location and thenmove the tool to cause it to cut the structure along the- predetermined. cutting--pattern.- The cutting tool 324 then is retrieved viaithe coiledlubing-'. 32& or by the robotics device-:as the case may be or the cutting tool.. 324 can be. repositioned along----the;next structural member 310. This process is continued until all structural members 310 have been cut.

Another preferred meth od of disengaging an offshore platform 300 is illustrated in FIG. 6S. In this example, the structural members 310 are hollow and have such dimensions -.that- the cutting toot.324 can be conveyed, to the desired cutting:,-position.328- through the- inside of the structural'i- nember'31 0-.' 25- The cutting tool 324 is lowered 1-from, the -base 312 of the-platform 300 through the hollow structural member 310, via a device such as coiled tubing 326, until the cutting tool 324 is at the desired cutting position 328. A suitable anchoring device (not-shown) is then engaged such that the cutting tool 324 is held at the proper level within the structural member 310 while the cutting toolnozzle 32 rotates axially around the inside diameter of the structural member 310 while performing the cut.

The cutting tool 324 -then performs the desired out (such as described above) along the inside diameter of the structural member 310 and is retrieved via the coiled tubing 326 for repositioning inside the next structural member 310. This process is repeated until all structural members 310 have been cut.

This method can be used to cur only portions of such structural members, such as a windows.

Another preferred method relating to cutting processes ata',borehole 358 and utilizing a cutting tool such as the one of the present invention is illustrated in FIG. 7. A typical borehole 358 contains nested pipes 350 which may vary in length. In this example, the nested pipes 350 contain three pipes 352, 354 and 356 and may have cement between the pipes. To remove the nested pipes 350 from the borehole 358, the nested pipes 350 are first pulled- a distance d from the borehole 358 such that the bottom of a first section- s of the nested pipes 350 is above the surface 364. This section s of the nested pipes 350 is 21 then connected together at a location 360 above the bottom of the section s.

The connection can be made by many methods known in the art such as by drilling through the nested pipes 350 and inserting a connecting rod 361. A cutting tool (not shown) is then us ed to cut through the nested pipes 350 at the point below the.connecting rod 361 near the, bottom of the section s; of the nested pipes 350. This section s then is removed and conveyed- to another location. The process is repeated,for additional sections s of the nested pipes 350 until the desired amount of nested. pipes 350 have been removed from the borehole 358'.

While the foregoing disclosure is..directed to the preferred embodiments of the invention, various -modifications will be apparent to those skilled in the art. It is.intended that all variations with-in the scopeand spirit-of the appended claims be embraced by the foregoing disclosure.

22

Claims

I CLAIMS

2 3 1 A method f or disengaging a structure supported 4 by at least one structural support member embedded in a seabed, comprising:

6 (a) positioning a cutting element of a cutting 7 tool adjacent a predetermined position on 8 an outside of the structural support 9 member, said cutting tool utilising a high -Dressure fluid jet as the cutting element; 11 and 12 (b) cutting through the structural support 13 member with the cutting element along the 14 outside of the structural support member at the predetermined position.

16 17
2. The method of claim I wherein the predetermined 18 position is below the seabed and the cutting 19 element is moved to the predetermined position by displacing the earthen material around the 21 support member by discharging the pressurised 22 fluid into the earthen material by the cutting 23 element or by utilising a vibratory source with 24 the cutting tool that enables the cutting tool to move below the seabed.

26 27
3. The method of either preceding claim, wherein 28 the cutting tool is positioned by conveying the 29 cutting tool along the outside of the tool by a device selected from a group consisting of (a) a 31 tubing, (b) a wireline, and (c) a robotics 23 I device adapted to move the tool along an outside 2 of the support member.

3 4
4. The method of claim 3, wherein the cutting tool is conveyed by the robotics device and the 6 cutting tool is moved by the robotics device 7 along a predefined path to effect cutting of the 8 support member.

9
5. A method substantially as herein before 11 described with reference to the accompanying 12 figures.

13 14
6. A cutting tool adapted to be positioned in a wellbore for cutting a material in the wellbore, 16 comprising:

17 (a) a cutting unit having:

18 (i) cutting element adapted to discharge a high 19 pressure fluid therefrom; and (ii) a power unit in the cutting tool, said 21 power unit supplying the fluid to a nozzle 22 at a pressure that is suf f icient to cut the 23 material; and 24 (b) a positioning device in the cutting tool, said positioning device positioning the nozzle at a 26 predetermined position in the wellbore for 27 effecting the cutting of the material.

24 1 2
7. The cutting tool of claim 6, wherein the 3 positioning device is adapted to move the 4 cutting element in radial and axial directions relative to the wellbore.

6 7
8. The cutting tool of claim 6, further having an 8 electrical control circuit associated therewith 9 for controlling the operation of the cutting unit.

11 12
9. The cutting tool of claim 8, wherein at least a 13 portion of the control circuit is contained in 14 the cutting tool.

16
10. The cutting tool of either one of claims 8 or 9, 17 wherein the electrical control circuit further 18 includes a surface control circuit that is in 19 data communication with the electrical control circuit in the cutting tool for controlling the 21 operation of the cutting tool.

22 1
11. The cutting tool of claim 6, wherein the power 2 unit further comprises a plurality of successive 3 stages, wherein each successive stage increases 4 the pressure of the fluid by a predetermined amount above the preceding stage.

6 7
12. The cutting tool of claim 6, wherein the power 8 unit includes a device to pulse the fluid before 9 said fluid is discharged from the cutting element.

11 12
13. The cutting tool of claim 12, wherein the pulse 13 rate and the fluid pressure define the cutting 14 rate of the material.

16
14. The cutting tool of claim 6, further having a 17 surface control unit for controlling the 18 operation of the cutting tool, said surface 19 control unit having stored therein a cutting profile defining a section of the material to be 21 cut by the cutting tool.

22 26 1
15. The cutting tool of claim 14, wherein the 2 surface control unit causes the cutting tool to 3 cut the section of a working area according to a 4 predetermined pattern within the boundaries of the cutting profile in a manner that will 6 produce cuttings of the material being cut of a 7 size that is conducive to be transported to the 8 surface by circulating a fluid through the 9 wellbore.

11
16. The cutting tool of claim 6, further having 12 stored within the cutting tool a cutting profile 13 defining a section of the working area to be cut 14 by the cutting tool.

16
17. A method for cutting a material at a worksite in' 17 a wellbore by a cutting tool having a cutting 18 element adapted to discharge fluid therefrom 19 under pressure, comprising:

(a) conveying the cutting tool near the 21 worksite; 22 (b) positioning a nozzle a predetermined 23 distance from the material to be cut; 27 1 (c) discharging the fluid from the nozzle at a 2 predetermined pressure that is sufficient 3 to effect cutting of the material; and 4 (d) moving the nozzle according. to a predetermined pattern to cut a desired 6 amount of the material at the worksite.

7 8
18. The method according to claim 17, further 9 comprising pulsing the fluid prior to discharging the fluid through the nozzle.

11 12
19. The method according to claim 17, further 13 comprising providing a control system for 14 controlling the operation of the cutting tool.

16
20. The method according to claim 19, wherein the 17 control system further comprises a control unit 18 within the cutting tool and a surface control 19 unit at the surface.

21
21. The method according to claim 17, wherein the 22 predetermined pattern is defined to cut the 23 material at the worksite into cuttings that are 28 1 transportable to the surface by circulating a 2 fluid through the wellbore.

3 4
22. A method for disengaging a structure supported by at least one hollow, support member embedded 6 in a seabed, comprising:

7 (a) positioning a cutting element of a cutting 8 tool within the support member at a 9 predetermined depth, said cutting tool utilising a high pressure pulsed fluid jet 11 as the cutting element; and 12 (b) cutting through the support member at the 13 predetermined position along the inside of 14 the support member.

16
23. A method for removing nested pipes from a 17 wellbore, comprising:

18 (a) pulling the nested pipes from the wellbore 19 a predetermined distance above the surface of the wellbore; 21 (b) connecting the nested pipes together at a 22 selected connection point above the 23 surface; and 29 I (c) cutting the nested pipes below the 2 connection point with a cutting tool 3 utilising high pressure fluid jet as a 4 cutting element.