Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B7/00—Special methods or apparatus for drilling
  • E21B7/24—Drilling using vibrating or oscillating means, e.g. out-of-balance masses
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B28/00—Vibration generating arrangements for boreholes or wells, e.g. for stimulating production
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B31/00—Fishing for or freeing objects in boreholes or wells
  • E21B31/005—Fishing for or freeing objects in boreholes or wells using vibrating or oscillating means
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B7/00—Special methods or apparatus for drilling
  • E21B7/04—Directional drilling
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B7/00—Special methods or apparatus for drilling
  • E21B7/04—Directional drilling
  • E21B7/06—Deflecting the direction of boreholes
  • E21B7/068—Deflecting the direction of boreholes drilled by a down-hole drilling motor

Definitions

• This invention relates to methods and apparatus for applying vibrations to downhole tools in borehole operations.
• 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.
• 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 are relatively stiff and heavy and so can be used to push on equipment located at the lower end of the string.
• 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.
• WOB weight on bit
• 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.
• 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.
• CT continuous coiled tubing
• a continuous steel tube typically around 50mm 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.
• 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.
• CT is considered particularly useful in many cases. It is even used for drilling applications.
• 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.
• 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.
• 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 :
• torsion vibrations 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.
• Borehole operations within thet 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 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.
• 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.
• Figure 1 shows a schematic view of a CT drilling operation to which the invention is applicable
• Figures 2-5 show plots of well depth vs weight on bit for different axial friction values
• Figure 6 shows the geometry of an exemplary well in which the invention is used
• Figure 7 shows a cross-plot of torque and vibration frequency for an embodiment of the invention
• Figure 8 shows a diagram of the measurement and control steps in a method according to the invention.
• Figure 9 shows a plot of steering % vs swing amplitude for a directional drilling system.
• Figures 10-14 show embodiments of vibration systems for use in the invention. Mode(s) for carrying out the invention [0030]
• 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.
• 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.
• 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.
• 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.
• 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.
• 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.
• FIG. 1 One embodiment of the invention shown in Figure 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.
• Figure 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.
• the operating envelope of CT drilling systems is limited by the ability to transfer weight to the drill bit.
• 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.
• 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 ( ⁇ ) is indicative of the type of contact between the drill string and the borehole wall. Normal sliding axial friction has a ⁇ value of 0.3 or above. No axial friction (no contact or all friction being tangential) has a ⁇ value of 0.0.
• the well in question has a 2000m total vertical depth with about 1000m horizontal extent at its lower portion, a 3°/30m build section starting at about 1450m vertical depth.
• the vertical part of the well is cased with 7.625 inch (194mm) casing; the deviated section is uncased.
• a coiled tubing drilling system of the type described above is deployed with a 6.5 inch(165mm) bit mounted on a 4.75 inch (121mm) mud motor operating at 100-150 rpm according to mud flow.
• the vibrator is disposed in the BHA above the motor.
• Figure 6 shows the vertical and horizontal extent of the well.
• Figure 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.
• 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 2500m of CT string is excited (i.e. the top 500m 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 1500m (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 1000m if the CT string which corresponds to the horizontal section of the well.
• 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 ne necessary or desirable to try to vibrate all the way to the surface (e.g. slant drilling).
• 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.
• 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.
• the frequency dependent mobility of the system can be modelled and torque vs frequency relationships developed for exciting various lengths of the drill strind (corresponding to Figure 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.
• 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.
• 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.
• 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. [0056] While the invention is described above in relation to drilling, similar benefits can be obtained in other borehole operations.
• 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.
• the drill string may not extend completely to the surface, such as in a wireline drilling operation.
• the vibration may be applied only to the drilling tool part of the system.
• 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.
• a bent sub is interposed between the drill string that the drill bit.
• 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.
• the bit continues to drill in the direction of the tool face.
• 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.
• the bit spends progressively less time on the tool face direction.
• 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.
• 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.
• 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.
• Figure 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).
• 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.
• FIG. 10-14 illustrate examples of these that can be used as part of a CTD drilling system.
• 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.
• the BHA 124 is connected to the drill string 120 by means of a rotary joint including a clutch 128.
• 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.
• Figure 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.
• 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.
• Figure 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.
• the diameter of the vibrator can be 0.13m so as to fit in a 0.19m casing, with a mass length of the order of 10m and a spring length of the order of 10m.
• the resonator is shown as a single unit in Figure 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 Figure 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.
• 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.
• FIG. 14 Another variant that uses mud flow is shown in Figure 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.
• 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.
• a low speed, high torque electric motor such as a switched reluctance motor
• the motor vibrator includes an outer stator that is fixed to the BHA or CT string and an inner rotor.
• 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.
• motor powers necessary to vibrate drill strings can be achieved.
• multiple motors can be ganged together and operated either as a single unit or as individual sub-units.
• the vibrator can be configured as a resonator.
• 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.
• a clutch such as a centrifugal clutch that is configured to operate at a certain rotational speed.
• 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.
• the vibrator described above comprises a coaxial motor in the BHA
• 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.
• the CT string is used for purposes other than drilling, such as well interventions for placing fluids or evaluation tools.
• the drill string is a traditional segmented drill string or other tubular, such as a casing, production tubular, expandable screen, etc.

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• 2009
  • 2009-05-01 GB GB0907538.3A patent/GB2469866B/en not_active Expired - Fee Related
• 2010
  • 2010-04-30 WO PCT/GB2010/050729 patent/WO2010125405A2/en not_active Ceased
  • 2010-04-30 CA CA2760262A patent/CA2760262A1/en not_active Abandoned
  • 2010-04-30 US US13/318,166 patent/US20120048621A1/en not_active Abandoned
  • 2010-04-30 EP EP10718679A patent/EP2425084A2/de not_active Withdrawn

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