AU761103B2 - System for cutting materials in wellbores - Google Patents

Description

P/0101o1 Regulation 3.2

AUSTRALIA

Patents Act 1990

ORIGINAL

COMPLETE SPECIFICATION STANDARD PATENT System for O i- eloe Invention Title: The- following statement is a full description of this invention, including the best method of performing it known to us: Freehills Carter Smith BeadleMELC6O1O3201.1 TITLE: METHOD FOR DISENGAGING A STRUCTURE BACKGROUND OF THE INVENTION Field of the Invention This invention relates generally to a method for disengaging a structure and more particularly to disengaging oilfield structures, by means of cutting tools utilising a pressurised fluid.

SUMMARY OF THE INVENTION The present invention provides a method for disengaging a structure supported by at least one structural support member embedded in a seabed, comprising: providing a cutting tool having a controllably aligned high pressure fluid jet as a cutting element; 1 5 controlling a first alignment of said high pressure fluid jet to displace earthen seabed material around said support member to a predetermined position below said seabed by discharging pressurised fluid into the earthen material; locating said cutting tool at a predetermined position below the seabed o 20 which position is adjacent to the exterior surface of said support member; and controlling a second alignment of the high pressure fluid jet to sever said support member by discharging pressurised fluid against the exterior surface of the support member.

Features of the invention have been summarised 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 be appreciated. There are additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS For detailed understanding of the present invention, reference should be made to the following detailed description of a preferred embodiment, 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, not I. 1 forming part of the present invention, wherein the cutting element of the downhole cutting tool is shown positioned 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 a member beneath the cutting tool.

S° o FIG. 2B-C illustrate an alternative manner for positioning the cutting element in the downhole cutting tool to cut materials beneath the cutting tool.

*element in the downhole Cutting tool to cut materials beneath the cutting tool.

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FIG. 3 is a schematic diagram of an example of;,a predetermined profile a section of the casing to be but that may be stored in a memory associated with the cutting system of FIG. 1 for later use.

s FIG. 4 is a schematic diagram of the downhole tool of FIG. 1 adjacent a 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 of the cutting system shown in FIGS. 1-3.

FIG. 6A shows a method of disengaging an offshore structure that is supported on tubular members embedded in the seabed, this method forming one embodiment of the present invention.

is FIG. 6B is a partial exploded view of the cutting tool of FIG. 6A-B.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS FIGS. 1 to 5 do not describe embodiments of the present invention, but 20 will be described to aid in understanding of the embodiment which is presented hereinafter.

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 s 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 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") 20 conveyed from a platform 11 of a derrick 12 into a borehole 22 by a suitable conveying member 24, such as a co.iled-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 _15 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 pressurised 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 20 associated with the downhole tool The cutting element section 28 houses a cutting element 30 that

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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 metallic 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 (1399 MN/m 2 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 P 1 Each successive section increases the pressure of the fluid above the pressure of the preceding section by a predetermined amount. The last section 15 Pn 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 P 1 -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 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 allow positioning the probe 32 at the desired depth adjacent to the wellbore casing 23. The cutting element section 28 or the cutting element 30 can be rotated to position the nozzle 32 at a radial location within 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 section 34, contains devices for orienting the nozzle 32 at the desired position. One or more such devices rotate the cutting element section 28 to radially position the nozzle 32. Any suitable hydraulically-operated devices or 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 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 the tool 20. In the configuration shown in FIG.

o 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.

In applications where the material to be cut is below the cutting tool 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 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 performing reaming operations in tubular members, such as a production tubings. Reaming is required when the interiors of such tubings are.lined with sediments.

*o* S. 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 removed 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 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 wellbore 22 below the tool As shown in FIG. 1, electrical circuits and downhole power supplies for operating and controlling the operation of the cutting element 30, the power unit 34, and the devices and sensors placed 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 placed at a suitable location on the rig platform 11 preferably controls the operation of the cutting system 10. The control unit 70 includes a suitable computer, associated memory, a recorder for recording S*

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0 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 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 An example of such profile 80 is shown in FIG. 3. The arrows 82 define the vectors associated with the profile 80. The profile 80 is preferably displayed on the monitor 72 at the surface. An operator orients the nozzle tip 32 at a location within the section of the casing 23 to be cut. 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, preferable 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 g* power section 34 causes the fluid to pulse at a predetermined rate and the fluid 9 a 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-methods ensure that the materials will be cut into pieces that are small enough to be transported by circulating fluids. During 1 5 operations, the downhole circuits contained in the electrical circuit section 38 communicate with the surface control unit 70 via a two-way telemetry, which is preferably contained in a section 39.

FIG. 4 shows the downhole tool of FIG. 1, with an imaging device attached below the cutting section 28. Imaging tools to image a borehole interior have been provided in the art and, therefore, are not described in detail 0.000 herein. The imaging device 90 is utilized to confirm the shape of the section oooo of the casing or the junction after the cutting operation has been performed.

-The imaging device 90 may also be utilized to image the area 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. 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 orientation 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 information from other downhole devices and sensors, such as a depth indicator 118 and 15 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 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 11 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.

FIG. 6A illustrates a method in accordance with the present invention of disengaging an offshore platform structure 300 from a seabed 318 utilising cutting tools such as those described above. As shown in FIG. 6A, the offshore 0 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.

@0 0 *0* To disengage the platform 300, a cutting tool 324 is conveyed from the 0 15 platform base 312, via a device such as coiled tubing 326 with a tracking device 00 0 0 323 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 tool 324 that enable the cutting tool 324 to remain latched onto.the structural member 310 or a robotics device that guides the cutting tool 324 along the periphery of 0 0 the structural member 310. The structural member 310 can be of any shape 00 used in the industry. Some examples include a tubular member an I-beam type member. The cutting tool 324 also 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 displace 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 cut 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 solid and dotted lines in FIG. 6C, and a o *9regulated amount of pressurised fluid released to move the earthen material 320 is 15 out of the way of the cutting tool 324 as it progresses towards the cutting point S328. The cutting element 32 is then oriented substantially perpendicular to the o surface to be cut (as shown in FIG. 1) to cut the support member. 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 R A Z4/ accomplish this cut, the cutting tool 324 is 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 then move the tool to cause it to cut the structure along the predetermined cutting pattern. The cutting tool 324 then is retrieved via the coiled tubing 326 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.

While the foregoing disclosure is directed to a preferred embodiment of the invention, various modifications will be apparent to those skilled in the art within the scope of the appended claims.

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Claims (1)

1. 2. The method of claim 1, wherein the cutting tool 26 is positioned by conveying the cutting tool 27 along the outside of the support member by a 28 device selected from a group consisting of a 0 29 tubing, a wireline, and a robotics device adapted to move the tool along the 31 outside of the support member. 1 2 3. The method of claim 2, wherein the cutting tool 3 is conveyed by the robotics device and the 4 cutting tool is moved by the robotics device along a predefined path to effect cutting of the 6 support member. 7 8 4. The method of claim 1, wherein the high-pressure 9 fluid jet is discharged from a nozzle that is positioned at a predetermined distance from the 11 exterior surface of the support member. 12 13 5. The method of claim 4, wherein the fluid jet is 14 pulsed prior to discharge from said nozzle. 16 6. The method of claim 4 or claim 5, wherein the S17 controlled alignment of said fluid jet includes 18 radial and axial movement of said nozzle e 19 relative to the length of said support member. 21 7. A method as claimed in claim 1 and substantially 22 as hereinbefore described with reference to 23 Figs. 6A and 6B of the accompanying figures. 24 Baker Hughes Incorporated S: By its Registered Patent Attorneys c* FREEHILLS CARER SMITH BEADLE 12 March 2003 *o o-