US20120048621A1

US20120048621A1 - Method and apparatus for applying vibrations during borehole operations

Info

Publication number: US20120048621A1
Application number: US13/318,166
Authority: US
Inventors: Bruce Stewart; Bob Worrall; Ivo Stulemeijer
Original assignee: Dynamic Dinosaurs BV
Current assignee: Misc BV
Priority date: 2009-01-05
Filing date: 2010-04-30
Publication date: 2012-03-01
Also published as: GB0907538D0; GB2469866B; CA2760262A1; GB2469866A; WO2010125405A3; WO2010125405A2; EP2425084A2

Abstract

A method of conducting borehole operations using a system including an elongate tubular conveyance that is moved through the borehole, the method comprising imposing a torsional vibration at a predetermined frequency on the tubular conveyance as it is moved through the borehole:

wherein the predetermined frequency is obtained by determining the frequency-dependent mobility of the system based on the relationship between rotational velocity and torque for the system; and imposing torsional vibrations at a frequency where the relationship is optimised.

Description

TECHNICAL FIELD

This invention relates to methods and apparatus for applying vibrations to downhole tools in borehole operations. In particular, the invention relates to such methods and apparatus that are applicable to operations such as those conducted in the oils and gas industry, for example in drilling operations or well interventions. These, and other uses, are called ‘borehole interventions’ in this document.

BACKGROUND ART

Wells in the oil and gas industry comprise boreholes that are drilled to great depths from the surface. Where wells are vertical, moving equipment in and out of the well is relatively straightforward, gravity providing the pull down the well, and a suitable conveyance (cable, pipe, etc.) allowing withdrawal from the well. However, where the borehole deviates from vertical, particularly where it becomes close to horizontal, gravity no longer assists and it can become necessary to push a tool into the borehole if it is to reach the bottom and, apply weight on bit in the case of drilling.
Conventional drill pipe comprises steel pipes joined in an end-to-end fashion to extend to the bottom of the well. Such pipes (drill strings) are relatively stiff and heavy and so can be used to push on equipment located at the lower end of the string. In conventional rotary drilling, the drill pipe is rotated at surface and the rotation is transmitted to a drill bit at the bottom where it provides the drilling action in associated with weight on bit (WOB). Consequently, drill pipe has been used for both drilling and other well interventions where access can be difficult.
If it is desired to deviate the course of the borehole, directional drilling tools and techniques must be used. One commonly used technique involves the use of a downhole motor or hammer close to the bit (typically driven by the flow of drilling fluid), and a bent sub in the bottom hole assembly which has the effect of moving the drill bit face (tool face) away from the normal axis of the drill string. When it is desired to deviate the path of the well, rotation of the drill string is stopped with the bend pointing the drill bit in the desired direction. The downhole motor is used to rotate the bit and the drill string is slid into the wellbore as the bit drills ahead. This is often known as ‘sliding drilling’ to differentiate it from rotary drilling. Once the deviation of the well trajectory has been achieved, rotary drilling can be resumed.
There are a number of problems associated with sliding drilling using a bent sub, in particular, sliding drilling encounters greater axial friction (drag) with the borehole wall, leading to reduced effectiveness of weight transfer to the bit, and a greater propensity for differential sticking of the drill sting components in regions of permeable formation in the well.
These, and other problems, have lead to the development of downhole adjustable rotary steerable systems, which allow deviation of the well trajectory while rotating the drill string.
Drilling with drill pipe requires the use of large surface equipment. In recent years, continuous coiled tubing (CT) has been used for well interventions. In this, a continuous steel tube, typically around 50 mm in diameter is fed into a well from a reel at the surface. While such tubing has a degree of rigidity, its desirable flexibility can lead to certain problems. To feed the CT into the well, it is necessary to push from the surface. If a long length of CT is fed into a well and encounters some resistance, for example due to axial friction from contact with the borehole wall, pushing from the surface can lead to buckling of the CT. This buckling can increase the contact of the tubing with the borehole wall, impeding effective weight transfer to the bottom of the CT. In its most extreme, the CT can helically lock in the borehole such that further pushing from the surface just serves to lock the CT more securely to the borehole wall and no weight is transferred to the bottom. Friction between the CT and the borehole wall can initiate this problem, since the CT must slide over the borehole wall when it is introduced into the well. This problem is well-known in the oil and gas industry with regard to CT operations.
Despite these problems, CT is considered particularly useful in many cases. It is even used for drilling applications. However, the problem discussed above limits its use at great depths or with high deviation from vertical. The limitations on the operating envelope of CT mean that it can be difficult to obtain full benefit of the reduction in cost and environmental impact in many wells.
There have been a number of proposals to vibrate the drill string or CT to try to overcome drilling problems. Examples can be found in U.S. Pat. No. 4,667,742, US2005/0230101. To date, none of these have been particularly effective. There have also been proposals to oscillate or rock the drill string to try to offset the effect of stick-slip motion at the drill bit and/or to maintain the tool face in the correct direction. Examples can be found in U.S. Pat. No. 6,918,453, WO2004/061258, WO2004/101944, WO2006/044737, U.S. Pat. No. 6,050,348, US2009/0090555, US2009/0078462, and WO2009/039453. GB2454997 discloses the use of a step up motor and a slippable clutch to decouple the effects of drill string rotation from the drill bit when driven by the motor.
This invention is based on the recognition that an effective vibration system must have two effects: to move the friction domain from static mode to dynamic mode, and to move the friction vector from an axial direction to a tangential direction. Effective application allows the operating envelope of a borehole intervention system to be extended. This application provides methods and apparatus to increase the effective use of vibrations with regard to the operating envelope of the borehole intervention system.

DISCLOSURE OF THE INVENTION

A first aspect of this invention provides a method of conducting borehole operations using a system including an elongate tubular conveyance that is moved through the borehole, the method comprising imposing a torsional vibration at a predetermined frequency on the tubular conveyance as it is moved through the borehole:
wherein the predetermined frequency is obtained by determining the frequency-dependent mobility of the system based on the relationship between rotational velocity and torque for the system; and imposing torsional vibrations at a frequency where the relationship is optimised.
The method can comprise determining the variation in the frequency-dependent amplitude of torque for torsional vibrations in the system, the value of the amplitude being used to determine the predetermined frequency. The predetermined frequency can be selected from a frequency range in which the amplitude is at or near a local minimum.
The mobility can be derived by modelling the system in the borehole taking into account spring, gravitational, inertial, and frictional forces, and hydraulic drag. This can comprise deriving a static model of the system and modifying it using a dynamic model of the system when the torsional vibrations are applied. Non-linear forces can be applied to the dynamic model. The model can be periodically updated to account for changes in the system and/or borehole as the operation progresses.
The borehole operation can be periodically ceased and the operational parameters of the system varied to provide inputs to the model.
The torsional vibration can be controlled so as to excite torsional vibrations along a predetermined length of the drill string, such as along substantially its whole length. The predetermined length of the drill string can be in a part of the borehole that is deviated from vertical.
The torsional vibrations can be imposed at or near the end of the drill string and/or at locations in the drill string that are determined to be susceptible to frictional contact with the borehole at one or more locations intermediate its ends.
One embodiment comprises a drilling operation using a drilling assembly at the end of the drill string, for example a drilling operation using a bent sub near a drill bit at the end of the drill string, the method further comprising:

- orienting the bent sub to define a tool face direction; and
- controlling the swing amplitude of the torsional vibration so as to control the amount of deviation in drilling trajectory in the tool face direction arising from the bent sub. This can include controlling swing amplitude to include swing amplitudes comprising partial rotations of the drill string.

Prior to orienting the bent sub, torsion vibrations can be applied at the predetermined frequency to the system to ease any torsion forces in the system.
The step of orienting the bent sub can comprise applying weight on bit to deviate the tool face direction due to the torque reaction when drilling.
The steps of applying vibrations at the predetermined frequency to the system to ease any torsion forces in the system, orienting the bent sub by applying weight on bit to deviate the tool face direction due to the torque reaction when drilling and controlling the swing amplitude of the torsional vibration so as to control the amount of deviation in drilling trajectory in the tool face direction arising from the bent sub can be periodically repeated.
Borehole operations within the scope of this aspect include a pipe expansion process including vibrating an unexpanded part of the pipe during the expansion process, an expansion tool, or both.
A second aspect of the invention provides an apparatus for conducting borehole operations in accordance with the method of any preceding claim, comprising:

- a drill string that can be moved through the borehole during the operation; and
- a vibration system engaged with the drill string and operable to impose a torsional vibration on the drill string at the predetermined frequency.

The apparatus can further comprise a downhole tool positioned on the drill string so as to be positionable in the borehole at a predetermined position. The downhole tool can comprises a drilling assembly including a drilling motor and a drill bit connected to the motor, located at the end of the drill string.
The vibration system can comprise a vibrator positioned on the drill string so as to be located in the borehole in use. This can include an in-line clutch between the drilling assembly and the drill string and operable periodically to release reactive torque during drilling into the drill string. Other embodiments include a stabiliser that rotates on the drilling motor axis and is configured to engage the borehole wall in use; a rotational mass system in the drill string or downhole tool powered by a motor, wherein the mass can be mounted on a spring, and a centrifugal clutch to periodically couple the rotating mass to the drill string.
In one embodiment, the vibrator comprises a motor. This can be an electric motor, such as a switched reluctance motor. The motor can also comprise a number of motor sub-units operable independently or together.
The apparatus can further comprise a supply of drilling fluid that can be pumped through the drill string to a fluid-powered motor in a downhole tool, wherein the vibrator comprises a dump valve in the drill string that operates periodically to dump fluid flow to the motor, or from a pulsed mud pump at the surface.
The apparatus can further comprise a system for monitoring the vibration imposed on the drill string and generating a feedback signal therefrom, and using the feedback signal to control the frequency of vibrations provided by the vibrator.
Further aspects of the invention will be apparent from the following description.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a schematic view of a CT drilling operation to which the invention is applicable;

FIGS. 2-5 show plots of well depth vs weight on bit for different axial friction values;

FIG. 6 shows the geometry of an exemplary well in which the invention is used;

FIG. 7 shows a cross-plot of torque and vibration frequency for an embodiment of the invention;

FIG. 8 shows a diagram of the measurement and control steps in a method according to the invention;

FIG. 9 shows a plot of steering % vs swing amplitude for a directional drilling system; and

FIGS. 10-14 show embodiments of vibration systems for use in the invention.

MODE(S) FOR CARRYING OUT THE INVENTION

The invention will be described in relation to a coiled tubing drilling operation. However, it will be apparent that it can apply to other forms of drilling or well operations. For example, the benefit of the invention can be obtained in drilling with conventional drill pipe, especially when it is operating in sliding mode such as in directional drilling applications. Also, a similar benefit can be obtained with other operations where it is necessary to advance a downhole tool into the well using CT or drill pipe. Other applications involve running in casing, production or completion tubing, expandable tubulars, fishing operations, and wireline logging and drilling operations.
In order to avoid the problems of axial friction (drag) associated with the prior art systems discussed above, torsional vibrations are applied to the drill string (or tool string) in order to move the friction from the static domain to dynamic domain, and to change the friction vector from axial to tangential. In order to optimise this process, the mobility of the system is considered. Mobility is the ratio of rotational velocity to applied torque, reflecting the ease with which a rotational moment is expressed as motion. The mobility of a system is dependent on a number of factors, including the physical structure of the system, the materials from which it is made, the shape and condition of the borehole, and the frequency of the applied vibration. For any given instant of a system in operation (i.e. any given physical structure and borehole), changing the frequency of the applied vibration changes the mobility. By optimising the mobility of the system by selection of an appropriate frequency, the amount of power needed to excite the vibrations can be managed, with the aim of obtaining the maximum reduction in axial drag in the system for the minimum energy.
One embodiment of the invention shown in FIG. 1, and comprises a coiled tubing drilling system comprising a CT string 10 extending from conventional surface equipment (not shown). The CT string extends through a borehole 12 extending into an underground formation 14 and terminates in a bottom hole assembly (BHA) 16 which provides the drilling, sensing a vibration functions described in more detail below. A cable can extend through (or alongside) the CT string 12 from the surface to the BHA 16 to provide power and control and data signals. Electromagnetic and mud pulse systems can also be used for data communication. Drilling fluid can also be pumped through the CT string in the usual manner. The BHA 16 comprises a drill bit, mud motor and vibrator module, together with various sensors for monitoring the drilling operation. Although FIG. 1 shows the CT string 12 clear of the borehole wall in a stylised representation, it will be appreciated that there will be significant contact between the string and the borehole wall, especially where the borehole deviates from vertical. This contact will also vary according to buckling of the CT string 12 as it is fed into the borehole to provide the WOB for the BHA 16 to drill ahead.
The BHA 12 includes a vibrator that can be operated to impose a torsional vibration on the CT string 12 and BHA 16. The vibrator operates at relatively low frequencies. In the case of a conventional system based on steel coiled tubing, this can be less than 5 Hz and in certain cases in the region of 1-1.5 Hz (for drill strings made of other materials, this frequency may be different). The exact frequency of operation will be selected according to requirements as will be discussed below. Such vibrations can be provided by a number of different systems, some of which are described below.
As is discussed above, the operating envelope of CT drilling systems is limited by the ability to transfer weight to the drill bit. In CT drilling, weight is applied to the drill bit by feeding the CT into the borehole at the surface, essentially pushing from the surface (a similar effect can also be found in conventional drill pipe in deviate boreholes, where the weight of the drill string in the vertical section of the borehole pushes the lower part of the drill string in the horizontal section). Frictional contact of the CT with the borehole wall both limits the transfer of weight to the bit from the surface, and exposes the upper part of the drill string to increased buckling stresses. Such problems typically limit the operating envelope of CT drilling systems, particularly in the context of maximum achievable depth and deviation. This invention provides techniques that can extend this operating envelope by addressing these issues. In addition, vibrating the drill string, the frictional engagement with the borehole wall is dynamic rather than static and consequently lower. By translating the friction vector from an axial direction in simple sliding or axial vibration, to a tangential direction by imposing torsional vibration, the friction vector no longer resists sliding the drill string into the borehole. Thus it can be possible to drill deeper and with greater deviation with CT systems that would otherwise lock up or lose drilling efficiency.
Because the torsional vibrations allow improved weight transfer, the overall efficiency of the system can be improved as less energy is wasted overcoming friction.
The effect of torsional vibrations on a CT drilling operation can be considered in relation to a plot of hook load, weight on bit (WOB) and axial friction coefficient (μ).
Hook load is the ‘weight’ of the drill string seen at the surface as it enters the well. The highest hook load is seen when the full weight of the drill string is supported at the surface, i.e. there is no contact a the bottom or against the borehole walls. The hook load drops progressively as the weight is supported by the bottom of the borehole (through the drill bit) and contact with the borehole wall. The hook load reaching zero is an indication that lock up has occurred. Hook load in drilling systems can be readily calculated when designing the well and drilling system configuration using conventional torque and drag models such as WELLPLAN torque and drag analysis software of Halliburton and Schlumberger's Drilling Office software suite.
WOB is an indication of the force applied to the drill bit during drilling. Where WOB is zero, there is no support of the drill string by the bottom of the borehole, reduction in hook load being due to friction with the borehole wall. Thus, zero WOB is the situation in which the greatest length of well can be contemplated. As WOB increases, the onset of lock up occurs earlier as part of the hook load is supported on the bottom of the borehole. Clearly a positive WOB is necessary to drill ahead, and higher WOB may be needed to drill through certain types of formation.
The axial friction coefficient (μ) is indicative of the type of contact between the drill string and the borehole wall. Normal sliding axial friction has a μ value of 0.3 or above. No axial friction (no contact or all friction being tangential) has a μ value of 0.0.
These parameters are considered for four well shapes A-D as summarised in table 1 below. The well profiles are defined in terms of the kick off point: the vertical depth at which deviation of the trajectory starts (m), the rate of build (deg/m), the length of the build section (m), the length at the start of a horizontal section (m), and a total vertical depth of the end of the well: Tvd (m). The data in the table considers three WOB situations: 0 klbs—the maximum reach without any interference from the bottom of the well; 5 klbs and 10 klbs. In each case, the length of the horizontal section until hook load goes to zero is determined for a μ value of 0.3 (axial friction) and 0.0 (no axial friction, possible tangential friction). The maximum benefit is the extra length of horizontal section that can be achieved at each WOB by removing the effect of axial friction.
In all cases, removing the effect of axial friction provides a significantly enhanced operating envelope. Without this improvement, it would have been necessary to use a standard rotary drilling system to reach these extra depths, involving significantly more cost and a higher environmental impact. As can be seen, in the case of WOB=10 klbs, where axial friction is present, the benefit is a negative number, indicating that the end of the build section cannot be reached.
In most of the cases, the shape of the well does not have a major impact on the benefit achievable (apart from well D which has an extreme shape). As can be seen, Tvd has a major impact on the results achieved.


	Case A	Case B	Case C	Case D
	3 deg/30 m	1 deg/30 m	9 deg/30 m	9 deg/30 m
Wellshape	2000 m Tvd	2000 m Tvd	2000 m Tvd	2000 m Tvd

Kick off point	1427	281	1809	809
Length of build section	900	2700	300	300
Start of horizontal section	2327	2981	2109	1109
WOB = 0 klbs
Maximum horizontal section @ μ = 0.3	773	319	791	691
Maximum horizontal section @ μ = 0.0	4373	3719	4391	2291
MAXIMUM BENEFIT (extra length hor. Section)	3600	9400	3600	1600
WOB = 5 klbs
Maximum horizontal section @ μ = 0.3	273	19	391	−9
Maximum horizontal section @ μ = 0.0	3473	2819	3591	1291
MAXIMUM BENEFIT (extra length hor. Section)	3200	2800	3200	1300
WOB = 10 klbs
Maximum horizontal section @ μ = 0.3	−127	−681	−109	−309
Maximum horizontal section @ μ = 0.0	2423	1819	2691	191
MAXIMUM BENEFIT (extra length hor. Section)	2550	2500	2800	500

It will be appreciated that the table gives an ideal results where all axial friction is removed. FIGS. 2-5 show plots of well depth (total length of the vertical and build section, the start of horizontal section and maximum horizontal section) for each well shape for different values of μ. Even a partial reduction of the value due to torsional vibration gives significantly improved operating envelopes.
To illustrate the effect of imposing torsional vibrations in accordance with the invention, a specific example will now be discussed. The well in question has a 2000 m total vertical depth with about 1000 m horizontal extent at its lower portion, a 3°/30 m build section starting at about 1450 m vertical depth. The vertical part of the well is cased with 7.625 inch (194 mm) casing; the deviated section is uncased. A coiled tubing drilling system of the type described above is deployed with a 6.5 inch (165 mm) bit mounted on a 4.75 inch (121 mm) mud motor operating at 100-150 rpm according to mud flow. The vibrator is disposed in the BHA above the motor. FIG. 6 shows the vertical and horizontal extent of the well.
FIG. 7 comprises a cross-plot of vibration peak to peak torque amplitude vs vibration frequency. The four lines A, B, C and D correspond to the length of CT string above the vibrator that is placed into a torsional vibration mode. For line A, the whole length of the CT string is excited, torsional vibrations being excited all the way to the surface. As can be seen, this takes place at frequencies below 2 Hz. From this frequency, the torque required to excite the whole CT string drops to a minimum at around 1 Hz. Line B indicates the case for which the lower 2500 m of CT string is excited (i.e. the top 500 m does not vibrate). This occurs at frequencies below 2.5 Hz and the torque required drops progressively to a minimum around 0.5 Hz. Line C corresponds to excitation of the lower 1500 m (approximately the lower half of the CT string). This is the portion below the cased vertical part of the well that extends into the open hole. Finally, Line D indicates the lowest 1000 m if the CT string which corresponds to the horizontal section of the well.
From FIG. 7, it is clear that the torque requirement to excite torsional vibrations in the CT string increases dramatically as the frequency of excitation increases. Above 5 Hz, the torque required to excite a substantial length of CT string becomes impractical. However, it may be necessary to excite only the part of the string in the horizontal section of the borehole to obtain a large part of the benefit of the invention.
While placing the whole length of the CT string in torsion mode vibration is desirable, the benefit of the invention may be obtained where less than the whole length is excited. As is clear from the example given above in relation to FIG. 6, exciting the portion of the CT string in the open-hole horizontal section (the section starting at 600 m departure) will still have a major impact on weight transfer from the surface to the BHA. By placing the system in this section in a torsionally vibrating state, the effect of drag in the build section (0-600 m departure) is also affected in a beneficial manner. Therefore, one embodiment of the invention comprises designing the system to keep at least the part in the horizontal section in a vibrating mode. In other cases, it may be necessary or desirable to try to vibrate all the way to the surface (e.g. slant drilling).
As operations progress, the drill string length will change as it is run in or pulled out of the borehole. This is one of the factors that will change the optimal frequency of vibrations. For example, in the case described above the CT string length will increase as drilling progresses. It is therefore possible that the frequency and torque initially selected to vibrate the whole drill string may not be sufficient to continue to excite the whole length as the operation progresses. Provided that the section of the drill string in the critical part of the well is vibrated, the benefit of the invention can be seen. As will be discussed below, it may also be desirable to modify the frequency of vibration to accommodate such changes to optimise the operation.
As can be seen from the previous description, varying elements of the method can make significant differences to the behaviour of the drilling system and the benefits that can be obtained. One embodiment of the invention that allows these variations to be evaluated is based on modelling of the drilling system and elements of the method combined with feedback and adjustment during operations. FIG. 8 shows this approach schematically: a model 100 is developed which is used to establish the control of the vibration system 102; variables of the drilling process are measured 104 which is fed back into the control loop 106 to adapt the current conditions to obtain the desired result.
A model 100 can be developed to predict the vibration behaviour of a vibrating drill string. One approach is to derive a finite element model of the drill string as a discrete number of mass-spring systems whose vibration energy is dissipated by internal damping, borehole friction and viscous damping of fluids. Such a model is non-linear and can describe drill string behaviour that allows the estimation of vibration frequencies and amplitudes (torque) suitable to increase the effective operating envelope of the drilling system in an energy efficient way. One approach is to derive a static model from the torque and drag programs discussed previously and then to impose on this model dynamic factors. Once this model has been obtained, the frequency dependent mobility of the system can be modelled and torque vs frequency relationships developed for exciting various lengths of the drill string (corresponding to FIG. 7). These allow the frequency of vibration to be selected. By selecting a frequency that lies at or near a local minimum of a given line, and is within the operating range of the vibration system, effective use of the available power can be achieved. From this model, control parameters for the vibration system 102 can be established and applied.
A number of techniques are available for measuring variables of the drilling process 104, such as surface toque and axial displacement (feed rate), hook load, downhole torque (TOR), weight on bit (WOB) and rate of penetration (ROP) at the BHA, etc. Sensors can be provided at a number of locations on the drill string to monitor such behaviour.
The measurements 104 are used update the model 100 to modify the control parameters 102 in a feedback loop 106 so that the desired vibrational behaviour is obtained. For example, the frequency can be modified to take into account the change in length of the drill string as the drilling operation progresses, changes in the condition of the borehole due to drill string interactions, changing fluids or pumping conditions, and any other effects that can change the frictional interaction of borehole and system.
Updating the model and changing the control parameters can be done periodically at the surface, taking into account surface and downhole measurements. Alternatively, or in addition, a downhole process can operate to update the model based on downhole measurements only. Sensors, such as magnetic sensors and strain gauges can be installed in a BHA or other downhole tool to measure the operational parameters that can then be fed into the model and update the control parameters in a closed loop fashion.
In the case of a drilling operation, it can be useful to periodically cease feeding the drill string into the borehole and measure the change in parameters as the system drills to zero WOB (drill off). The frequency of the vibrations can be scanned over a range during this process to update the frequency dependence of mobility and allow the frequency of the vibrations applied during the operation to be updated accordingly.
In one aspect of the invention, the vibration is applied such that the whole length of the drill string is vibrated. Vibrating less than this is also possible although optimum benefit might not be obtained. Where less than the whole length of the drill string is vibrated, one approach is to apply the vibrations at high friction points since these will have a significant impact on the operating envelope of the drilling system. As will be clear from above WOB will have a significant impact on the extension of the operating envelope of a vibrating system. High WOB can be realised if there is a low tendency to buckling (and lock up). Low WOB can give a greater extension of operating envelope.
While the invention is described above in relation to drilling, similar benefits can be obtained in other borehole operations. For example, where the drill string is being used to accurately position a tool in a deviated borehole, or where casing, expandable tubular or other such pipes are being installed in boreholes, etc. In each case, applying torsional vibrations in accordance with the method of the invention can improve the operating envelope where otherwise axial friction could provide a limitation.
One situation that can also be addressed by application of vibrations in accordance with the invention is in cases where differential sticking can be an issue. In certain cases, reciprocation and rotation of a tubular such as casing has been used to try to avoid differential sticking. However, where this is not possible, such as when CT is being used or where the tubular is fixed at the surface, this invention provides an alternative approach.
Other borehole operations that can benefit from the invention include fishing operations in which the fishing tool includes a vibrator and vibrations are applied once the tool is connected to the fish.
In other cases, the drill string may not extend completely to the surface, such as in a wireline drilling operation. In this case, the vibration may be applied only to the drilling tool part of the system.
Application of vibrations in accordance with the invention can also be used to assist in steering the drill bit so as to direct drilling in a predetermined direction. In a typical directional drilling system, a bent sub is interposed between the drill string that the drill bit. In use, the bend is rotated to point in the desired direction so as to set the tool face direction. Drilling ahead causes the trajectory to deviate in the direction of the bend. When there are no torsional vibrations applied to the drill string, the bit continues to drill in the direction of the tool face. However, applying torsional vibrations to the drill string will mean that the bit oscillates either side of the mean tool face, leading to a diminution of the degree of deviation. As the swing amplitude of the vibration increases from zero, the bit spends progressively less time on the tool face direction. When the swing amplitude reaches about 0.4 turns (i.e. each oscillation includes +/−0.4 of about the tool face, the time spent by the bit in all rotational positions is approximately equal and the system drills ahead. By the time the swing amplitude equals about 0.5, the bit is spending more time on the opposite side of the hole to the tool face and the steering direction is reversed. As the amplitude continues to increase, the steering direction returns toward the original tool face although the amount of deviation is less than the case with no turns as the drill bit is spending progressively more time away from the tool face. FIG. 9 shows a plot of steering % vs swing amplitude (steering % is the amount of deviation in the tool face direction relative to the non-vibrating case). Applying torsional vibrations to a bent-sub steering setup means that it is also possible to drill straight ahead without changing the BHA or tool face.
One embodiment of the invention involving such a steering approach comprises initially torsionally vibrating the system at a frequency that optimises mobility. This will have the effect of easing torsional forces in the system. Once this has been done, the direction of the tool face can be checked. Drilling can then commence and weight on bit applied to deviate the tool face (due to the torque reaction). The vibration frequency can then be modulated at a frequency that gives the desired steering effect discussed above. Iterations of this process can be used to either maintain or change the steering direction.
There are a number of mechanisms that can be used to impose the torsional vibrations in accordance with the invention, depending on the amount of power, frequency, size and source of energy available. FIGS. 10-14 illustrate examples of these that can be used as part of a CTD drilling system. In each case, the system comprises a CT drill string 120 connected to a supply of drilling fluid including a mud pump 122 at the surface. A BHA 124 including a drilling motor driven by mud flow is located at the end of the drill string 120 and a drill bit 126 is mounted on the BHA 124 so as to be rotated by the motor.
In FIG. 10, the BHA 124 is connected to the drill string 120 by means of a rotary joint including a clutch 128. When the clutch is engaged, reaction torque during drilling is coupled into the drill string 120 in the normal manner. Disengaging the clutch, either fully or partially, releases some or all of the reaction torque so that the BHA 124 rotates in reaction to the drilling action of the bit 126. Periodically engaging and disengaging the clutch excites torsional vibrations into the drill string and control of this activity can bring these vibrations into the domain of the invention. This embodiment operates well when there is good drilling contact between the bit and the formation 130. With such an arrangement, there should be sufficient power available at the bit due to reactive torque in a typical CTD drilling system. While the system is relatively simple, it does impact drilling performance so this must be taken into consideration when planning a drilling operation. Control of the clutch is necessary to allow release of torque and rebuild of power at the desirable frequencies.
Variations on this idea include limiting the rotation or slip angle so that only part of the torque is released. Active control of the clutch can be based on parameters such as drill string velocity, displacement or torque.
Controlled release of the clutch also allows the BHA to rotate in a controlled manner. If the BHA includes a bent-sub, this in turn allows the tool face to be set in any direction.
FIG. 11 shows another embodiment in which a stabiliser 132 is disposed between the BHA 124 and drill bit 126, and is mounted to rotate with the drive shaft from the motor and engages the walls 134 of the borehole adjacent the BHA 124 in a stick-slip motion. This in turn induces the torsional vibrations in the BHA 124 and hence the drill string 120. Unlike the previous embodiment, as the reaction does not need engagement of the bit 126 with the formation, this technique can be used either when the bit is not drilling ahead, or in a non-drilling application. (e.g. workover). The control system in this case must control the speed of the motor in the BHA in order to operate above or below the stick-slip threshold as appropriate. The available power is similar to the previous embodiment.
Both of the previous two embodiments are powered by reactive torque. FIG. 12 shows an embodiment that is self powered and comprises a motor 136 driving a reaction mass 138 mounted on a spring 140. Rotation of the mass 138 by the motor 136 couples into the drill string 120 through the spring 140. The motor can be powered either electrically or hydraulically, so as to deliver the appropriate power at the desired frequencies. To obtain the necessary performance, the diameter of the vibrator can be 0.13 m so as to fit in a 0.19 m casing, with a mass length of the order of 10 m and a spring length of the order of 10 m.
While the resonator is shown as a single unit in FIG. 12, it can also be provided as smaller sub-units, either at the end of the drill string 120, or positioned at various locations along the drill string. These can clamp on the outside of the drill string in one embodiment. As with the embodiment of FIG. 11, this embodiment can be used in both drilling and other operations.
An alternative source of power can be found in the flow of mud from the pumps at the surface. Modulating this downhole can be used to provide the torsional vibrations. In FIG. 13, a dump valve 142 is provided above the BHA motor. By periodically operating the dump valve 142, the motor speed can be pulsed and the deceleration and acceleration of the motor around the axis creates torque in the drill string 120 that excites the vibrations. The power available will depend on the fluid flow rate and the mass of the motor will affect how much torque can be exerted on the drill string. This embodiment may be used in conjunction with one of the other embodiments to provide the correct power and frequency input to the drill string.
Another variant that uses mud flow is shown in FIG. 14, in which the mud pumps 122 at the surface are pulsed around a fixed value which in turn produces motor speed pulse in the BHA 124. In this case, the dynamics of the mud column should be taken into account. The mud system can include structures and controls to modify the dynamic behaviour of the mud column at the surface and/or downhole, for example by incorporating water hammers or the like.
Where a downhole electric motor is used, such as in the example of FIG. 12, a low speed, high torque electric motor, such as a switched reluctance motor, can be used. In this case, the motor vibrator includes an outer stator that is fixed to the BHA or CT string and an inner rotor. By selecting the mass of the rotor, the electrical design of the windings, and the electrical power supplied to the motor, the torque that can be created by operation of the motor can be determined. Operation of the motor in a stepwise rotation or with alternating reversal of direction can be used to provide the desired torsional vibration. A three-phase switched reluctance motor (SRM) of the type described in WO2008/148613 (incorporated herein by reference). Is one such example.
Various switching techniques can be used for SRMs. As the torque generated is independent of the direction of current, a simple technique can be used, an asymmetrical half-bridge converter being preferred. WO2008/148613 discloses further details of control and power electronics suitable for operation of such a motor.
With appropriate power electronics and a suitable cable providing electric power to the BHA, motor powers necessary to vibrate drill strings can be achieved. In the event that higher power is needed (to generate higher torque) multiple motors can be ganged together and operated either as a single unit or as individual sub-units.
In a particular embodiment of the invention, the vibrator can be configured as a resonator. In this case, sensors are provided for detecting the magnitude of torsional vibration excited in the CT string and generating a feedback signal that can be used to adjust the frequency of the vibrator to optimise excitation of the vibrations.
Where the torque from a rotational mass is to be coupled into the drill string, this can be achieved using a clutch, such as a centrifugal clutch that is configured to operate at a certain rotational speed.
While the BHA is one location of the vibrator, it is not restricted to this location and may be positioned in other places on the string. The position can be selected so that the appropriate part of the string can be excited. The operations parameters of the vibrator can be selected to target a predetermined part of the string if full excitation cannot be achieved. In certain cases, it may be appropriate to position the vibrator at or near the surface of the well. However, if vibration to the bottom is required, the power and torque must be controlled so as not to compromise CT integrity. Multiple vibrators can also be used, in which case, their operation needs to be synchronised in some way to avoid destructive interference cancelling out the desired benefits of the system.
Various changes can be made within the scope of the invention. While the vibrator described above comprises a coaxial motor in the BHA, other configurations can be used. For example, suitable gearing arrangements may allow alignment of the motor axis other than coaxial with the drill string. Suitable vibrators can also be mounted around the BHA or drill string. Vibrators other than electric motors are also possible. In certain cases, it may not be possible to provide a supply of power from the surface, for example where expansion of tubular would destroy electric cables and no flow of drilling fluid is possible. In these cases, some form or energy storage can be used, such as a battery to drive an electric motor.
In some embodiments of the invention, the CT string is used for purposes other than drilling, such as well interventions for placing fluids or evaluation tools. In others, the drill string is a traditional segmented drill string or other tubular, such as a casing, production tubular, expandable screen, etc.
These and other changes are within the scope of the invention. For example, axial oscillations or vibrations can also be used in addition to the torsional vibrations. Also, while the embodiments descried above are mostly in the sliding domain, the invention can equally be applied in the rotary domain.
While the invention is described above in relation to operations in underground boreholes, it can similarly be applied to drains, pipes and tubes, whether underground of on the surface or in other inaccessible locations.

Claims

1. A method of conducting borehole operations using a system including an elongate tubular conveyance that is moved through the borehole, the method comprising imposing a torsional vibration at a predetermined frequency on the tubular conveyance as it is moved through the borehole:

2. A method as claimed in claim 1, comprising determining the variation in the frequency-dependent amplitude of torque for torsional vibrations in the system, the value of the amplitude being used to determine the predetermined frequency.

3. A method as claimed in claim 2, wherein the predetermined frequency is selected from a frequency range in which the amplitude is at or near a local minimum.

4. A method as claimed in claim 1, wherein the mobility is derived by modelling the system in the borehole taking into account spring, gravitational, inertial, and frictional forces, and hydraulic drag.

5. A method as claimed in claim 4, comprising deriving a static model of the system and modifying it using a dynamic model of the system when the torsional vibrations are applied.

6. A method as claimed in claim 5, wherein non-linear forces are applied to the dynamic model.

7. A method as claimed in claim 4, comprising periodically updating the model to account for changes in the system and/or borehole as the operation progresses.

8. A method as claimed in claim 4, comprising periodically ceasing the borehole operation and varying the operational parameters of the system to provide inputs to the model.

9. A method as claimed in claim 1, wherein the torsional vibration is controlled so as to excite torsional vibrations along a predetermined length of the drill string.

10. A method as claimed in claim 8, wherein the torsional vibration is controlled so as to excite torsional vibrations along substantially its whole length.

11. A method as claimed in claim 8, wherein the predetermined length of the drill string is in a part of the borehole that is deviated from vertical.

12. A method as claimed in claim 1, wherein torsional vibrations are imposed at or near the end of the drill string.

13. A method as claimed in claim 1, wherein torsional vibrations are imposed at locations in the drill string that are determined to be susceptible to frictional contact with the borehole at one or more locations intermediate its ends.

14. A method as claimed in claim 1, comprising a drilling operation using a drilling assembly at the end of the drill string.

15. A method as claimed in any preceding claim, comprising a drilling operation using a bent sub near a drill bit at the end of the drill string, the method further comprising:

orienting the bent sub to define a tool face direction; and

controlling the swing amplitude of the torsional vibration so as to control the amount of deviation in drilling trajectory in the tool face direction arising from the bent sub.

16. A method as claimed in claim 15, further comprising controlling swing amplitude to include swing amplitudes comprising partial rotations of the drill string.

17. A method as claimed in claim 15, comprising, prior to orienting the bent sub, applying torsion vibrations at the predetermined frequency to the system to ease any torsion forces in the system.

18. A method as claimed in claim 15, wherein the step of orienting the bent sub comprises applying weight on bit to deviate the tool face direction due to the torque reaction when drilling.

19. A method as claimed in claim 17, comprising periodically repeating the steps of applying vibrations at the predetermined frequency to the system to ease any torsion forces in the system, orienting the bent sub by applying weight on bit to deviate the tool face direction due to the torque reaction when drilling and controlling the swing amplitude of the torsional vibration so as to control the amount of deviation in drilling trajectory in the tool face direction arising from the bent sub.

20. A method as claimed in claim 15, comprising a pipe expansion process including vibrating an unexpanded part of the pipe during the expansion process, an expansion tool, or both.

21. An apparatus for conducting borehole operations in accordance with the method of any preceding claim, comprising:

a drill string that can be moved through the borehole during the operation; and

a vibration system engaged with the drill string and operable to impose a torsional vibration on the drill string at the predetermined frequency.

22. An apparatus as claimed in claim 21, further comprising a downhole tool positioned on the drill string so as to be positionable in the borehole at a predetermined position.

23. An apparatus as claimed in claim 22, wherein the downhole tool comprises a drilling assembly including a drilling motor and a drill bit connected to the motor, located at the end of the drill string.

24. An apparatus as claimed in claim 21, wherein the vibration system comprises a vibrator positioned on the drill string so as to be located in the borehole in use.

25. An apparatus as claimed in claim 24, wherein the vibrator comprises an in-line clutch between the drilling assembly and the drill string and operable periodically to release reactive torque during drilling into the drill string.

26. An apparatus as claimed in claim 24, wherein the vibrator comprises a stabiliser that rotates on the drilling motor axis and is configured to engage the borehole wall in use.

27. An apparatus as claimed in claim 24, wherein the vibrator comprises a rotational mass system in the drill string or downhole tool powered by a motor.

28. An apparatus as claimed in claim 27, wherein the mass is mounted on a spring.

29. An apparatus as claimed in claim 27, further comprising a centrifugal clutch to periodically couple the rotating mass to the drill string.

30. An apparatus as claimed in claim 24, wherein the vibrator comprises a motor.

31. An apparatus as claimed in claim 30, wherein the motor is an electric motor.

32. An apparatus as claimed in claim 31, wherein the electric motor is a switched reluctance motor.

33. An apparatus as claimed in claim 30, wherein the motor comprises a number of motor sub-units operable independently or together.

34. An apparatus as claimed in claim 21, further comprising a supply of drilling fluid that can be pumped through the drill string to a fluid-powered motor in a downhole tool, wherein the vibrator comprises a dump valve in the drill string that operates periodically to dump fluid flow to the motor.

35. An apparatus as claimed in claim 21, further comprising a supply of drilling fluid that can be pumped through the drill string to a fluid-powered motor in the downhole tool, wherein the vibrator comprises a pulsed mud pump at the surface.

36. An apparatus as claimed in claim 21, further comprising a system for monitoring the vibration imposed on the drill string and generating a feedback signal therefrom, and using the feedback signal to control the frequency of vibrations provided by the vibrator.