Method for well abandonment and slot recovery

Abstract

A method of increasing fatigue life in vibratory casing recovery assemblies. In a vibratory casing recovery bottom hole assembly having a casing spear, one or more drill collars and a vibratory device, at least the coupling between the casing spear and the first drill collar is made-up with a reduced torque as compared to the API minimum recommended make-up torque for the coupling. A method of recovering casing using the vibratory casing recovery bottom hole assembly is also described.

Description

[0001] METHOD FOR WELL ABANDONMENT AND SLOT RECOVERY

[0002] FIELD

[0003] The present invention relates to methods for well abandonment and slot recovery and in particular, though not exclusively, to a method of increasing fatigue life in vibratory casing recovery assemblies.

[0004] BACKGROUND

[0005] When a well has reached the end of its commercial life, the well is abandoned according to strict regulations in order to prevent fluids escaping from the well on a permanent basis. In meeting the regulations it has become good practise to create the cement plug over a predetermined length of the well and to remove the casing. This provides a need to provide tools which can pull long lengths of cut casing from the well to reduce the number of trips required to achieve casing recovery. However, the presence of drilling fluid sediments, partial cement, sand or other settled solids in the annulus between the outside of the casing and the inside of a surrounding downhole body e.g. outer casing or formation can act as a binding material limiting the ability to free the casing when pulled. Stuck casings are now a major issue in the industry.

[0006] Traditionally, cut casing is pulled by anchoring a casing spear to its upper end and using the elevator / top drive on a drilling rig. However, some drilling rigs have limited pulling capacity, and when the casing may be stuck, there may be insufficient power at the spear to recover the stuck casing section. Consequently, further trips must be made into the well to cut the casing into shorter lengths for multi-trip recovery. As each trip into the well takes significant time and costs, techniques have been developed to reduce the number of trips into the well.

[0007] Vibration has been successfully used to assist in the removal of stuck objects in well bores. US 7,077,205, the disclosure of which is incorporated herein in its entirety by reference, describes a method of freeing stuck objects from a bore comprising running a string into the bore, the string including a flow modifier, such as a valve, for producing variations in the flow of fluid through the string, and a device for location in the string and adapted to axially extend or contract in response to variations in the flow of fluid through the string. A portion of the string engages the stuck object. Fluid is then passed through the string while applying tension to the string, whereby the tension applied to the stuck object varies in response to the operation of the flow modifier and the extending or retracting device. This arrangement is offered as the Agitator™ to National Oilwell Varco, USA to assist in freeing a cut casing section when located below the casing spear.

[0008] A hammer tool can also be used to provide the vibratory action. US 7,073,610 describes a hammer tool being a downhole tool for generating a longitudinal mechanical load. In one embodiment, a downhole hammer is disclosed which is activated by applying a load on the hammer and supplying pressurizing fluid to the hammer. The hammer includes a shuttle valve and piston that are moveable between first and further positions, seal faces of the shuttle valve and piston being released when the valve and the piston are in their respective further positions, to allow fluid flow through the tool. When the seal is releasing, the piston impacts a remainder of the tool to generate mechanical load. The mechanical load is cyclical by repeated movements of the shuttle valve and piston. This tool can also be used to impart a load on a stuck object and a pulling force to release the object.

[0009] The bottom hole assembly of such vibratory arrangements has a casing spear with an anchor mechanism to attach to the top of the cut casing section, one or more sections of drill collars to provide sufficient weight for running in the well, and a vibratory device which provides an axial vibratory loading on the anchor mechanism which is transmitted to the cut casing section. The vibratory device is operated by fluid flow through a pipe string from surface and the bottom hole assembly is mounted on the pipe string. With the anchor mechanism set to grip the casing section, the vibratory device is operated and the string pulled from the well to release and recover the casing section.

[0010] A disadvantage in using vibratory arrangements on pipe strings is in the axial mechanical vibrations placed on the string by the moving components. It is known that in a drill string made up of drill pipe and drill collars used to transfer torque generated at the topdrive on a rig to the drill-bit to perform a drilling operation, the drill string is subjected to various tensile, compressive and shear forces which create stresses in axial, torsional and lateral directions. Such stress, particularly at the connections between the drill pipes and drill collars results in fatigue and can cause failure of the drill string. Increased axial vibration can therefore lead to premature fatigue in the bottom hole assembly.

[0011] To help manage fatigue in drill strings, the threaded pin and box sections of the drill pipe and drill collar connections are standardised. API standards then provide for a desired tool joint outer diameter and inner diameter, the torsional strength, tensile strength and recommended make-up torque. API RP7G is the standard for drill collars based on connection style, inner diameter and outer diameter. As these standards are based on drilling applications, they do not consider the increased axial vibration below an anchored point on the string and thus enhanced fatigue in the connections of the bottom hole assembly can be experienced. An alternative is to provide specially designed threaded connections specific to the application. US 5,931 ,511 describes a threaded connection for enhanced fatigue resistance during cyclic loading on drill strings and risers used to accommodate fatigue resistant connections in downhole completion applications, such as deep water drilling. The thread design of this invention uses a tapered thread and reduces stress concentration points in the bottom of the thread roots by increasing the radii at the intersection between the thread roots and the sides of the thread or flanks. Specially designed thread connections means that the drill collars have to be specially designed and transported to the rig. This makes the vibratory casing recovery application expensive.

[0012] SUMMARY

[0013] Aspects of the present disclosure relate to methods for well abandonment and slot recovery and in particular, though not exclusively, to a method of increasing fatigue life in vibratory casing recovery assemblies.

[0014] According to a first aspect there is provided a method to increase fatigue life in a vibratory casing recovery assembly, comprising the steps;

[0015] (a) providing a vibratory casing recovery bottom hole assembly comprising a plurality of assembly sections, the assembly sections including: a casing spear having a gripping mechanism to anchor the spear to casing; at least one pipe member; a vibratory device, the vibratory device arranged to create periodic axial loads on the at least one pipe member; and wherein the assembly sections have threaded connections for coupling to adjacent assembly sections;

[0016] (b) making up the bottom hole assembly by coupling adjacent assembly sections via the threaded connections;

[0017] (c) using a reduced make-up torque of less than an API recommended make-up torque for at least one of the couplings.

[0018] Beneficially, the method increases fatigue life due to axial vibrations in a vibratory casing recovery assembly.

[0019] The high make-up torque recommended for drill string connections prevents separation at the coupling when high tensile and bending loads are applied. In the vibratory assembly, there are no bending loads below the anchored position and there is low axial tension as only the hanging load is contributing to this. Accordingly, in reducing the make-up torque, the compression between faces in the respective box and pin sections in the coupling is reduced and this reduction in static load gives an increased fatigue life.

[0020] The pipe member may be a drill collar. Alternatively, the pipe member may be a drill pipe and more preferably a heavy-weight drill pipe.

[0021] The threaded connections may be complimentary pin and box sections. These are as known in the art and may be API type connections. In this way the pin section may have a male threaded portion and the box section may have a female threaded portion, there being a shoulder against which one portion meets the other to provide a seal. The reduced make-up torque may be two thirds the API recommended make-up torque. Preferably, the reduced make-up torque may be half the API recommended make-up torque. In this way, the coupling may be made-up to maintain contact of the faces of the pin and box sections without the high compression experienced in the API recommended makeup torque.

[0022] The at least one coupling may be the coupling between the casing spear and a first pipe member. In this way, the coupling which would experience the greatest stress, as one side is anchored, may have a reduced make-up torque to increase its fatigue life.

[0023] All couplings to and between pipe members may have a reduced make-up torque. In this way, fatigue life may be increased for the entire vibratory casing recovery bottom hole assembly.

[0024] The method may include the steps of:

[0025] (d) running the vibratory casing recovery bottom hole assembly on a drill string into a cut section of casing;

[0026] (e) anchoring the casing spear to the cut section of casing by use of the gripping mechanism;

[0027] (f) pumping fluid from surface through the drill string to operate the vibratory device; and / or

[0028] (g) pulling the drill string and the vibratory casing recovery bottom hole assembly to recover the cut section of casing.

[0029] In this way, casing may be recovered with a reduced risk of fatigue failure in the drill string.

[0030] The method may include providing a downhole pulling tool on the drill string above the vibratory casing recovery bottom hole assembly and using the downhole pulling tool to pull the vibratory casing recovery bottom hole assembly and cut section of casing free before pulling the drill string to recover the cut section of casing. In this way, a high static load may be applied to the cut section of casing without increasing the static load on joints in the drill string above the pulling tool. The method may include the additional steps of providing a casing cutter in the vibratory casing recovery bottom hole assembly and cutting casing to provide the cut section of casing on the same trip as recovering the cut section of casing.

[0031] The invention is defined by the appended claims. However, for the purposes of the present disclosure it will be understood that any of the features defined above or described below may be utilised in isolation or in combination. For example, features described above in relation to one of the above aspects or below in relation to the detailed description may be utilised in any other aspect, or together to form a new aspect.

[0032] The drawings and descriptions are to be regarded as illustrative in nature, and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as "including," "comprising," "having," "containing," or "involving," and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. Likewise, the term "comprising" is considered synonymous with the terms "including" or "containing" for applicable legal purposes.

[0033] All numerical values in this disclosure are understood as being modified by "about". All singular forms of elements, or any other components described herein including (without limitations) components of the apparatus are understood to include plural forms thereof.

[0034] It is also realised that terms such as ‘above’ and below’ are relative and while the description assumes a perfectly vertical wellbore, the invention can be used on deviated wellbores.

[0035] BRIEF DESCRIPTION OF THE DRAWINGS

[0036] Embodiments of the present disclosure will now be described, by way of example only, with reference to the accompanying drawings of which:

[0037] Figures 1(a) to 1(f) illustrate apparatus and method for recovery of a cut section of casing in a well, using a vibratory casing recovery assembly with an increased fatigue life according to an embodiment of the present invention;

[0038] Figure 2 is a cross-sectional view through a coupling with API threaded connections; and

[0039] Figure 3 is a table of recommended make-up torque for an API threaded connection from API RP7G.

[0040] DETAILED DESCRIPTION OF THE DRAWINGS

[0041] Reference is initially made to Figure 1 of the drawings which illustrates a method of recovering casing from a well using a vibratory casing recovery assembly with increased fatigue life, according to an embodiment of the present invention. In Figure 1(a) there is shown a cased well bore, generally indicated by reference numeral 10, in which a length of casing 12 requires to be recovered. A tool string 16 including a vibratory casing recovery assembly 11 is run in the well bore 10. The assembly 11 includes a casing spear 20, a number of drill collars 21 (one shown) and a vibratory device 22 arranged in order on the bottom of the tool string 16.

[0042] The tool string 16 is a drill string typically run from a rig (not shown) via a top drive / elevator system which can raise and lower the tool string 16 in the well bore 10. The well bore 10 has a second casing 14. The second casing 14 has a greater diameter than casing 12. In an embodiment, length of casing 12 is 9 5 / 8" (24.4 cm) diameter while the second casing 14 is 13 3 / 8" (34.0 cm) diameter.

[0043] Casing 12 will have been cut to separate it from the remaining casing string. In an embodiment the vibratory casing recovery assembly 11 includes a casing cutter and the casing 12 is cut on the same trip into the well bore 10 as that to recover it. The cut section of casing 12 may be over 100m in length. It may also be over 200m or up to 300m. Behind the casing 12 there may be drilling fluid sediments, partial cement, sand or other settled solids, herein referred to as material 26, in the annulus between the outside of the casing 12 and the inside of a surrounding downhole body, in this case second casing 14 but it may be the formation of the well bore 10. This material 26 can prevent the casing 12 from being free to be pulled from the well bore 10. It is assumed that this is the position for use of the present invention. Casing spear 20 operates to grip the inner surface 62 of the length of casing 12. The casing spear 20 anchors via a gripping mechanism being slips 66 designed to ride up a wedge and by virtue of wickers or teeth on its outer surface grips and anchors to the inner surface 62 of the casing 12. The casing spear 20 includes a switch which allows the casing spear 20 to be inserted into the casing 12 and hold the slips 66 in a disengaged position until such time as the grip is required. At this time, the casing spear 20 is withdrawn from the upper end 64 of the casing 12 and, as the switch exits the casing 12, it automatically operates the slips 66 which are still within the casing 12 at the upper end 64 thereof. This provides the ideal setting position of the casing spear 20. In a preferred embodiment the casing spear 20 is the Typhoon® Spear as provided by Ardyne AS. The Typhoon® Spear is described in WO2017 / 059345, the disclosure of which is incorporated herein in its entirety by reference.

[0044] The vibratory device 22 is a circulation sub which creates fluid pulses in the flow passing through the device. This can be achieved by a rotating member or a rotating valve. The vibratory device 22 also includes a shock sub arranged above the circulation device to provide axial movement. In a preferred embodiment the vibratory device 22 is the Agitator™ System available from National Oilwell Varco. It is described in US6279670, the disclosure of which is incorporated herein in its entirety by reference.

[0045] As shown in Figure 1(a) the casing spear 20 is anchored to the cut casing section 12 by slips 66. The vibratory device 22 is mounted below the casing spear 20 being separated from the casing spear 20 by one or more drill collars 21. As the tool string 16 is raised, flow through the tool string 16 and assembly 11 via a throughbore 68 will operate the vibratory device 22 and due to the fixed point between the assembly 11 and the casing 12 at the slips 66, vibrations in the shock sub of the vibratory device 22 will be transmitted through the drill collars 21 and casing spear 20 to the casing 12. Vibrating the casing 12 is known to assist in dislodging the stuck material 26 and so aid recovery of the casing 12. However, the vibration acting on the coupling 23 between the casing spear 20 and the first drill collar 21 reduces the fatigue life of the joint at the coupling 23 and so risks failure of the vibratory casing recovery assembly 11.

[0046] The casing spear 20, drill collars 21 and vibratory device 22 are joined together by box and pin sections as is known in the art and shown in Figure 2. Each assembly 11 section will have a box section 13 and a pin section 15 at respective ends, with the box section 13 typically at the upper end. The box section 13 has a female tapered screw thread 17 on an inner surface while the pin section 15 has mating male tapered screw thread 19 on an outer surface. When coupled together, as shown in Figure 2, the coupling 23 has an end face 25 of the box section 13 meeting an end face 27 of the pin section 15. For a type of connector, such as that used for drill collars, the assembly 11 designer will specify the inner diameter (ID) 29 and outer diameter (OD) 31 of each of the couplings. API standards then provide look-up tables to provide the torsional strength, tensile strength, and recommended make-up torque for the coupling 23 or tool joint. The make-up torque is provided as a minimum make-up torque value and is typically based on the lower of 60% of the tool joint torsional yield strength. Figure 3 shows a table for one type of connector or joint, 5 H90. Thus the designer selects the desired tool joint OD at the top of the table and the desired tool joint ID from the left-hand side of the table. The torsional strength (ft-lb), tensile strength (lb), and recommended make-up torque (ft-lb) are listed in the table for each combination of tool joint geometries.

[0047] In the present invention, the make-up torque in the coupling 23 is reduced and is lower than the recommended make-up torque found in the API standards for the particular connector, ID 29 and OD 31.

[0048] API RP7G recommends a make-up torque for drill collars based on connection style, OD and ID. The recommended torque is designed to apply a ‘general stress’ of 62,500 psi (431 MPa) in the weakest of either the box or pin section 13,15. However due to stress concentrations, the stress in the thread roots is much higher to the extent that it is likely to have entered the plastic region i.e. it has exceeded yield. In the pin thread root the stress is tensile and it is highest in the first engaged thread 33 which is closest to the pin / box shoulder 35 where the end faces 25,27 meet.

[0049] A critical consideration in deciding the make-up torque is that there must be sufficient contact force between the pin and box end faces 25,27 at the pin / box shoulder 35, so that they do not separate when tensile and bending loads are applied to the string which the joints form part of. If separation occurs then not only does the joint leak, but the stresses and strains in the critical thread roots increases dramatically and if subjected to cyclic loading (rotating bend) then there is a danger of fatigue failure. Cyclic loading occurs on drill strings having a drill bit and rotated to extend the length of a bore hole forming a well.

[0050] It is important to understand how the stresses and strains behave when a made-up joint or coupling is put under tension. Assume that the pin / box shoulder 35 has a pre-load of say, 100 units of force. This 100 units is reacted by 100 units in the thread contact faces. If 50 units of tension is then applied to the string, the force in the thread contact faces does not increase by 50 units. What actually happens is that the thread force increases by part of 50 units and the shoulder contact force decreases by the remainder of the 50 units. How the threads and pin / box shoulder 35 share the load depends on the relative stiffness of the pin and box sections 13,15. So if the box section 13 is a little stiffer than the pin section 15, which is normally the case, then the shoulder force decreases from 100 to 70 units (-30 units) and the thread force increases from 100 units to 120 units (+20 units).

[0051] The vibratory casing recovery assembly 11 of the present invention experiences low axial tension from the hanging load below the anchor point at the casing spear 20, this being a static load, combined with a high axial period or cyclic load from the vibration. This means that the risk of end face 25,27 separation at the pin / box shoulder 35 arises from the vibration loading and not from a potential high static load. Even though expected vibration loads are high in the assembly 11 , they do not come close to normally acceptable static tensile loads experienced on a typical drill string performing a drilling operation.

[0052] In analysing the coupling 23 in the present invention for full make-up torque it is realised that the combination of 100 units of static load (from the make-up) plus a superimposed 20 units of cyclic load gives a low fatigue life and there is thus a risk in parting the string at the assembly 11 during a casing recovery operation. However, note that, even at the peak of the cycle, there is still 70 units of compression at the pin / box shoulder 35 in the make-up face.

[0053] It is known by those skilled in the art that if the static load is reduced for a given cyclic load, the fatigue life increases. In the present invention example, because there are 70 units to spare, there is capacity to reduce the make-up torque. If, for example, half of the recommended make-up torque is applied, there will now be 50 units of compression in the pin / box shoulder 35 and 50 units of tension in the threads. When the same cyclic load of + / - 50 units is applied, this load gets shared as before, so the minimum face load at the pin / box shoulder 35 drops to 20 units and the max thread load is 70 units. The result is a large increase in fatigue life.

[0054] Accordingly, when the coupling 23 and optionally any other couplings in the assembly 11 are made up, only half the recommended make-up torque is applied to increase the fatigue life in the assembly 11. Although a value of one half or 50% is given, the minimum torque which can be applied must be sufficient to bring the end faces 25,27 into contact at the pin / box shoulder 35. This ensures a seal at the coupling 23. Thus a make-up torque of two-thirds of the recommended make-up torque could be applied. The recommended make-up torque is that specified for the type of connector / coupling and the inner and outer diameter 29, 31 as provided in the API standard tables.

[0055] Modelling of fatigue life is extensively carried out on drill strings for drilling operations. This may be done using finite element modelling or other known modelling techniques. Modelling of a string were the bottom hole assembly is the vibratory casing recovery assembly 11 has shown a factor of 10x and 100x improvement of the fatigue life compared with couplings 23 torqued to the recommended make-up values.

[0056] Returning to Figure 1(a), the coupling 23 between the casing spear 20 and the drill collar 21 is made-up to a reduced torque value as compared to the minimum recommended API make-up torque value.

[0057] In the embodiment shown the tool string 16 also comprises a hydraulic jack 18 and a pressure drop sub 24. The hydraulic jack 18 is located above the casing spear 20 and the pressure drop sub 24 is below the vibratory device 22 and may form part of the vibratory casing recovery assembly 11.

[0058] The hydraulic jack 18 has an anchor 28 and an actuator system which pulls an inner mandrel 30 up into a housing 32 of the hydraulic jack 18. In a preferred embodiment the hydraulic jack 18 is the DHPT available from Ardyne AS. It is described in US 8,365,826, the disclosure of which is incorporated herein in its entirety by reference.

[0059] The anchor 28 of the hydraulic jack 18, like the casing spear 20, has a number of slips 52 which are toothed to grip an inner surface 60 of the second casing 14.

[0060] The pressure drop sub 24 has a housing located in the string and apertures through a wall of the housing to provide multiple narrow fluid flow paths from the throughbore to an outer surface of the housing. Nozzles are located in the apertures. The cross-sectional area of the nozzles is significantly less than the cross-sectional area of the throughbore 68 so that a build-up of fluid pressure occurs when fluid is pumped down the tool string 16. This is used to create pressure at the hydraulic jack 18 for operating the hydraulic jack 18.

[0061] In a casing recovery operation, the tool string 16 is run into the well bore 10 with the pressure drop sub 24, vibratory device 22, drill collars 21 and casing spear 20 being run-in the casing 12. The tool string 16 is raised to a position to operate the switch on the casing spear 20 and the slips 66 automatically engage the inner surface 62 of the casing 12 at the upper end 64 thereof. At this stage the tool string 16 can be pulled via the top drive / elevator to see if the casing 12 is stuck.

[0062] Referring now to Figure 1(b), slips 52 on the anchor 28 of the hydraulic jack 18 are operated to engage the inner surface 60 of the second casing 14. As with the casing spear 20, an overpull on the tool string 16 will force the teeth on the slips 52 into the inner surface 60 to provide anchoring.

[0063] With fluid flowing down a throughbore 68 of the tool string 16, the pressure of the fluid will build up by virtue of the restrictions at the nozzles of the pressure drop sub 24. At the same time, the fluid flow through the vibratory device 22 will create pressure pulses seen as a cyclic variation of pressure and consequently applied load via the shock sub. The vibratory device 22 provides an oscillation at a frequency of less than 20Hz. The shock sub in the vibratory device 22, will oscillate at this frequency and cause periodic or cyclical loading on the casing 12 via the slips 66 of the casing spear 20. The amplitude of the cyclic variations can be selected via the spring load in the shock sub to determine the axial extent of the oscillatory movement on the assembly 11 and casing 12.

[0064] Build up of fluid pressure at the hydraulic jack 18 creates a fluid pressure sufficient to move inner pistons within the hydraulic jack 18, so forcing the inner mandrel 30 upwards into the housing 32. As the inner mandrel 30 is connected to the casing spear 20 which is in turn anchored to the length of casing 12, the force on the length of casing 12 will match the applied load of the pressure. This force is a large static load used to raise the assembly 11 and cut section of casing 12 and should be sufficient to release the casing 12 and allow it to move. At the same time, the casing 12 will vibrate or axially oscillate at the frequency created by the vibratory device 22. Such vibration has been shown to assist in releasing stuck casing and thus this action can assist during the pulling of the casing 12 by the hydraulic jack 18. Note that the high static load applied by the hydraulic jack 18 is not transferred to the couplings 23 by virtue of the casing spear 20 being anchored to casing 12. It is hoped that the hydraulic jack 18 can make a full stroke to give maximum lift to the casing 12. This is illustrated in Figure 1(c). If the casing 12 is still stuck only a partial stroke will be achieved. In either case, the anchor 28 is unset, by setting down weight, as shown in Figure 1(d).

[0065] Raising the tool string 16 will now lift the housing 32 with respect to the inner mandrel

[0066] 30, to re-set the hydraulic jack 18 in the operating position as illustrated in Figure 1(a). This is now shown in Figure 1(e) with the casing 12 now raised in the second casing 14. As the tool string 16 is raised, the casing 12 may be free and then the entire apparatus 11 and the length of casing 12 can be recovered to surface and the job complete.

[0067] If the casing 12 remains stuck, the anchor 28 is re-engaged as illustrated in Figure 1(f) and the steps repeated as described and shown with reference to Figures 1(b) to 1(e). The steps can be repeated any number of times until the length of casing 12 is free and can be pulled to surface by raising the tool string 16 using the top drive / elevator on the rig.

[0068] As long as fluid is pumped down the throughbore 68, the vibratory device 22 will operate and axial movement is induced in the assembly 11 to aid casing removal. Since the couplings 23 are made up to a reduced recommended torque, the vibratory device 22 can be operated continuously throughout the casing recovery operation without risking string failure as the fatigue life of the vibratory casing recovery assembly 11 has been extended.

[0069] It will be appreciated by those skilled in the art that the use of the hydraulic jack 18 and pressure drop sub 24 is optional and the casing 12 may be recovered using only the casing spear 20 with the drill collars 21 and vibratory device 22 in the assembly 11. Additionally, any device which causes periodic axial loading on the anchor point can be used as the vibratory device 22. The drill collars 21 may be any length of connecting pipe. The drill collars 21 may be lengths of drill pipe which may be heavy weight drill pipe.

[0070] A particular advantage of one or more embodiments of the present invention is that it provides a method of increasing the fatigue life of a vibratory casing recovery assembly.

[0071] A further advantage of one or more embodiments of the present invention is that it provides a method of vibratory enhanced casing recovery with a reduced risk of failure in the bottom hole assembly.

[0072] The foregoing description of the invention has been presented for the purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed. The described embodiments were chosen and described in order to best explain the principles of the invention and its practical application to thereby enable others skilled in the art to best utilise the invention in various embodiments and with various modifications as are suited to the particular use contemplated. Therefore, further modifications or improvements may be incorporated without departing from the scope of the invention herein intended with the invention being defined within the scope of the claims.

Claims

CLAIMS1. A method to increase fatigue life in a vibratory casing recovery assembly, comprising the steps:(a) providing a vibratory casing recovery bottom hole assembly comprising a plurality of assembly sections, the assembly sections including: a casing spear having a gripping mechanism to anchor the spear to casing; at least one pipe member; a vibratory device, the vibratory device arranged to create periodic axial loads on the at least one pipe member; and wherein the assembly sections have threaded connections for coupling to adjacent assembly sections;(b) making up the bottom hole assembly by coupling adjacent assembly sections via the threaded connections; and(c) using a reduced make-up torque of less than an API recommended make-up torque for at least one of the couplings.

2. The method according to claim 1, wherein the reduced make-up torque is two thirds the API recommended make-up torque.

3. The method according to claim 1 , wherein the reduced make-up torque is half the API recommended make-up torque.

4. The method according to any preceding claim, wherein the pipe member is a drill collar.

5. The method according to any one of claims 1 to 3, wherein the pipe member is a drill Pipe.

6. The method according to any preceding claim, wherein the at least one coupling is the coupling between the casing spear and a first pipe member.

7. The method according to claim 6, wherein all couplings to and between pipe members have a reduced make-up torque.

8. The method according to any preceding claim, wherein the method includes the steps of:(d) running the vibratory casing recovery bottom hole assembly on a drill string into a cut section of casing;(e) anchoring the casing spear to the cut section of casing by use of the gripping mechanism;(f) pumping fluid from surface through the drill string to operate the vibratory device; and / or(g) pulling the drill string and the vibratory casing recovery bottom hole assembly to recover the cut section of casing.

9. The method according to claim 6, wherein the method includes providing a downhole pulling tool on the drill string above the vibratory casing recovery bottom hole assembly and using the downhole pulling tool to pull the vibratory casing recovery bottom hole assembly and cut section of casing free before pulling the drill string to recover the cut section of casing.

10. The method according to claim 6 or claim 7, wherein the method includes the additional steps of providing a casing cutter in the vibratory casing recovery bottom hole assembly and cutting casing to provide the cut section of casing on the same trip as recovering the cut section of casing.

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