BACKGROUND OF THE INVENTION

1. Field of the Invention

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

2. Background of 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 18 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 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 may require the removal of certain materials to repair such juncture or to perform secondary operations. It is desirable to remove the materials from the juncture with precision in order to properly reconstruct the junctura 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 desired amounts of materials around the junctions. The present invention provides such a downhole cutting tool.

After the wellbore has been cased, various types of equipment, such as liner hangers, permanent packers, fluid flow control devices, etc., are set in the

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.

Various 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

other 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

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

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. The 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 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 prior 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 dollars per day.

The cutting area of prior art cutting tools is relatively large and, thus, 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 provides cutting tools wherein the cutting element is relatively small, does not contact the surface to be cut

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 tool 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 downhole, 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 streams require 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 element, 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 predetermined 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 for cutting a material at a worksite in a wellbore with a cutting tool which has a cutting element that is

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 such 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.

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 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.

FIG 2B-C illustrate an alternative manner for positioning the cutting element in the downhole 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 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-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.

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 wellbore utilizing the cutting tool of the present invention.

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 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 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 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. 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--

P _n . Each successive section increases the pressure of the fluid above the pressure of the preceding section by a predetermines amount. The last section P _n 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.,-P _n 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.

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 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 performing reaming operations in tubular members, such as a production tubings. Reaming is required when the interiors of such tubings are lined with sediments.

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 30" whose nozzle 32" may be placed at any desired location within the wellbora 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 20.

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

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 70.

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 power section 34 causes the fluid to pulse at a predetermined rate and the fluid

pressure to rise to a predetermined valua 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 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 90 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 herein. The imaging device 90 is utilized to confirm the shape of the section

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. 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 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 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

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-6B 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 312, via a device such as coiled tubing 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 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 the structural member 310. The structural member 310

can .be of any shape used in the industry. Some examples include a tubular member and 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 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 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 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 point 328. The cutting element 32 is then 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

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 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 repos ^' rtioned along the next structural member 310. This process is continued until all structural members 310 have been cut.

Another preferred method of disengaging an offshore platform 300 is illustrated in FIG. 6B. In this example, the structural members 310 are hollow and have such dimensions that the cutting tool 324 can be conveyed to the

desired cutting position 328 through the inside of the structural member 310. The cutting tool 324 is lowered 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 toot 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 tool nozzle 32

rotates axially around the inside diameter of the structural member 310 while performing the cut.

The cutting tool 324 then performs the desired cut (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 at a 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

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 used 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 within the scope and spirit of the appended claims be embraced by the foregoing disclosure.