Directional drilling apparatus and method

CA 02002135 1998-11-OS 1 1 Directional Drilling Apparatus and Method 2 3 This invention relates to a directional drilling 4 apparatus and method.

6 When drilling oil and gas wells for the exploration and 7 production of hydrocarbons, it is very often necessary 8 to deviate the well off vertical and in a particular 9 direction.

Such deviation may be required, for example, when drilling from land to explore formations 11 beneath the sea or below a lake, or in the case of oil 12 and gas production offshore, when drilling 20 or 30 13 wells from the same platform, each going in a different 14 direction to gain the widest coverage of the hydrocarbon bearing structure.

The latter can result 16 in wells being as much as 3 to 4 miles apart at the 17 point where they pass through the production zone.

18 19 Procedures for deviating wells have improved greatly over recent years with the introduction of powerful and 21 reliable downhole motors and downhole turbines, and the 22 introduction of Measurement While Drilling (MWD) 23 techniques.

24 Use of a downhole motor or turbine.allows the hole to CA 02002135 1998-11-OS 2 1 deviated by the introduction of a fixed offset or bend 2 just above the drill bit and this offset or bend can be 3 oriented by means of the MWD system which is capable of 4 giving toolface (direction of fixed offset or bend) hole angle and azimuth, all in real time.

6 7 Consequently, it is possible to rotate the drill string 8 slowly until the toolface is in the desired direction 9 of deviation, stop rotating the drill string with the toolface pointing in the desired direction, then start 11 the motor or turbine to extend the hole ir~ the desired 12 deviated direction.

13 14 There are however a number of inherent problems in this approach to directional drilling, namely:

16 17 (a) the drill string cannot be rotated while hole 18 deviation is taking place, giving rise to the 19 disadvantages of greater likelihood of getting stuck due to differential sticking, and difficulty in 21 transferring weight to the bit due to drag on the 22 static drill string:

23 24 (b) Surveys from the MWD System are taken at predetermined intervals, normally every 30 feet at the 26 singles change (the addition of a new length of drill 27 pipe), giving rise to the disadvantages that shift of 28 tool face due to reactive torque of motor or turbine 29 can only be identified after the shift has occurred, and correction of undesired hole angle change can only 31 take place every 30 feet at the least.

32 33 In order to obviate or mitigate these problems which 34 currently cost oil companies millions of dollars per year, it is an object of the invention to provide CA 02002135 1998-11-OS 3 1 directional drilling apparatus and method whereby the 2 offset or bend (toolface) can be created dynamically 3 such that the drill string may be rotated whilst 4 maintaining the toolface in a set direction.

There is preferably also an ability to change the toolface 6 direction whilst the drill string is rotating, in order 7 to correct any deviation of hole caused by external 8 influences e.g. formation change, or dip angle etc.

9 According to a first aspect of the present invention 11 there is provided directional drilling apparatus for 12 deviating a drill bit on the lower end of a drill 13 string substantially in a selected direction, said 14 apparatus comprising upper end coupling means for coupling the upper end of said apparatus to the lower 16 end of the drill string, lower end coupling means for 17 coupling of the drill bit to the lower end of said 18 apparatus, force coupling means linking said upper and 19 lower end coupling means for transmission of torsional and axial forces therebetween such that torque applied 21 to said drill string in use of said apparatus is 22 transmitted to the drill bit coupled to said lower end 23 coupling means in use of said apparatus while axial 24 downthrust or uplift applied to said drill string is transmitted to the coupled drill bit, said force 26 coupling means further allowing the rotational axis of 27 said lower end coupling means to be omni-directionally 28 deviated with respect to the rotational axis of said 29 upper end coupling means and the rotational axis of said drill string in use of said apparatus, rotatable 31 deviation direction control means for deviating the 32 rotational axis of said lower end coupling means with 33 respect to the rotational axis of said upper end 34 coupling means in a direction according with rotation of said rotatable deviation direction control means, CA 02002135 1998-11-OS 4 1 and rotational drive means coupled to said rotatable 2 deviation direction control means to contra-nutate said 3 rotatable deviation direction control means with 4 respect to rotation of the drillstring in use of said apparatus at a substantially equal and opposite 6 rotational speed whereby to deviate the axis of said 7 lower end coupling means in a direction which is 8 spatially substantially invariant.

9 Thereby the directional drilling apparatus in 11 accordance with the invention enables an angular 12 deviation to be provided in the bottom hole assembly at 13 the lower end of a rotating drill string, while holding 14 the spatial direction of the deviation substantially invariant by contra-nutating the deviation forming 16 arrangement with respect to the drill string at a 17 substantially equal and opposite rotational speed to 18 that of the drill string that substantially cancels out 19 rotation-induced changes in deviation direction that would otherwise occur.

21 22 Said rotatable deviation direction control means 23 preferably comprises an eccentric drive rotationally 24 coupled to an upward extension of said lower end coupling means such that rotation of said eccentric 26 drive nutates the rotational axis of said lower end 27 coupling means with respect to the rotational axis of 28 said upper end coupling means.

29 Said rotational drive means coupled to the eccentric 31 drive or other form of rotatable deviation direction 32 control means preferably comprises a hydraulic or 33 electric servo motor coupled to be controlled by 34 azimuth sensing means such that the rotational speed and rotational direction of the servo motor are equal CA 02002135 1998-11-OS 1 and opposite to those of the drill string in use of 2 said apparatus, and maintain a rotational phase 3 relationship thereto that produces said substantial 4 invariance in spatial direction of the deviated axis of 5 said lower end coupling means.

6 7 The eccentric drive and hydraulic servo motor may be 8 combined in the form of a Moineaux motor, with the 9 eccentrically rotating motor of the Moineaux motor constituting the eccentric drive.

11 12 Said force coupling means may comprise a Hooke joint, 13 or a constant velocity joint incorporating 14 bi~directionally effective end thrust transmitting means.

16 17 As an alternative to said eccentric drive, said 18 rotatable deviation direction control means may 19 comprise a rotatable cam means rotatably linking said upper and lower end coupling means.

21 , 22 Where said servo motor is an electric servo motor, 23 electric power therefore may be derived from an 24 adjacent battery or from a mud-driven turbo-alternator.

26 Where said servo motor is a hydraulic servo motor, 27 hydraulic power therefor may be derived from drilling 28 mud pumped down the drill string, preferably supplied 29 to the motor through a controllable valve.

31 Said azimuth sensing means may be comprised within an 32 MWD (Measurement While Drilling) system incorporated in 33 the lower end of drill string and operable during use 34 of the apparatus to measure the azimuth of the lower end of the drill string, or said azimuth sensing means CA 02002135 1998-11-OS 6 1 may be independent of the MWD system (if any).

2 3 According to a second aspect of the present invention 4 there is provided a method of deviating a drill bit on the lower end of a drill string substantially in a 6 selected direction, said method comprising the steps of 7 coupling the drill bit to the lower end of the drill 8 string through force coupling means transmitting 9 torsional and axial forces between the lower end of said drill string and the drill bit while allowing the 11 rotational axis of the drill bit to be 12 omni-directionally deviated with respect to the 13 rotational axis of the lower end of the drill string, 14 and contra-nutating the drill bit with respect to the lower end of the drill string at a substantially equal 16 and opposite rotational speed whereby to deviate the 17 rotational axis of said drill bit in a direction which 18 is spatially substantially invariant.

19 Embodiments of the invention will now be described by 21 way of example with reference to the accompanying 22 drawings wherein:23 24 Fig. 1 schematically illustrates a directionally deviated drill string being operated in accordance with 26 the directional drilling method of the present 27 invention;

28 Fig. 2 schematically illustrates a first configuration 29 of drill string incorporating directional drilling apparatus in accordance with the present invention;

31 Fig. 3 schematically illustrates a second configuration 32 of drill string incorporating directional drilling 33 apparatus in accordance with the present invention;

34 Fig. 4 is an elevation of a first embodiment of directional drilling apparatus in accordance with the CA 02002135 1998-11-OS 7 1 present invention:

2 Fig. 5 is an elevation of a second embodiment of 3 directional drilling apparatus in accordance with the 4 present invention Fig. 6A and 6B are longitudinal sections of 6 (respectively) lower and upper sections of a third 7 embodiment of directional drilling apparatus in 8 accordance with the present invention:

9 Fig. 7 is a transverse section of the third embodiment, taken on the line VII-VII in Fig. 6A:

11 Fig. 8 is a part-sectioned elevation of the third 12 embodiment in use for drilling an undeviated well bore:

13 and 14 Fig. 9 is a part-sectioned elevation of the third embodiment in use for drilling a deviated well bore.

16 17 Referring to the drawings, the basic principle of the 18 directional drilling method is schematically depicted 19 in Fig. 1. A universal joint 20 is fitted between the upper and lower parts 22, 24 of a drill string so that 21 the lower part 24 of the drill string is arranged at a 22 slight angle to the upper part 22 of the drill string 23 while transmitting torque and end thrust between them.

24 The joint 20 is provided with drive means which impart 26 an anticlockwise nutation or orbital rotation to the 27 lower part 24 of the drill string, which thus orbits 28 around the central rotational axis of the upper part 22 29 of the drill string.

This orbital movement is countered by clockwise rotation of the drill string 31 from a rotary table or top,drive (not shown in Fig. 1).

32 When the two rates of rotation, one clockwise and one 33 anticlockwise, are made equal, the lower part 24 of the 34 drill string effectively remains at a constant angle and a fixed or spatially invariant drilling direction CA 02002135 1998-11-OS 8 1 is established.

In a typical arrangement a constant 2 counter-clockwise nutation or orbital rotation of the 3 lower end 24 of the drill string is established at 4 approximately 60 RPM. A clockwise rotation of the upper part 22 of the drill string at 60 RPM establishes 6 directional drilling, whereas a rotation of the upper 7 part of the drill string at a greater speed, say 100 8 150 RPM, creates a relatively high speed wobble on the 9 lower part 24 of the drill string for effectively straight drilling.

It is thus possible to produce both 11 oriented and non-oriented drilling by variation of the 12 rotary speed of the drill string under control from the 13 rig floor.

14 The arrangement can be made to adjust the direction of 16 drilling by virtue of sensors within the assembly which 17 operate in conjunction with directional information 18 transmitted by the MWD (Measurement While Drilling) 19 system and the control means for the rotary drive of the drill string.

21 22 Referring now to Figs. 2 and 3, two alternative 23 configurations of directional drilling apparatus are 24 illustrated.

Fig. 2 shows the configuration for directional drilling when deviation angles of 0.5 26 degrees or greater are required.

In Fig. 2 27 configuration a directional drilling apparatus 1 is 28 positioned above a drill bit 2 and a stabilizer 3.

29 Fig. 3 shows the configuration for directional drilling when deviation angles of up to 0.5 degrees are 31 required.

In the Fig. 3 configuration the directional 32 drilling apparatus 1 is positioned between the drill 33 bit 2 and the stabilizer 3.

34 There are a number of possible embodiments of CA 02002135 1998-11-OS 9 1 directional drilling apparatus operable as described 2 above and a first of these is illustrated in Fig. 4.

3 The apparatus 1 comprises a knuckle or Hooke joint 4 assembly including an upper section 4 and a lower section 5 pivotally connected at 6. A gear arrangement 6 7 allows adjustment of the angle between the upper 7 section 4 and lower section 5.

The apparatus 1 fits 8 between an upper part 8 of a drill string and a lower 9 drill string part 9. A square drive 10 transmits torque to the lower part 9 of the drill string and 11 hence to the drill bit.

The gear arrangement 7 12 controls the angular bend of the device and can be set 13 to provide a 0.5 degrees, 0.75 degrees or 1 degree bend 14 in the bottom hole apparatus.

Control over the rotation of the appratus 1, and hence the orbital 16 movement of the assembly, is achieved by electric drive 17 means for the device which it is envisaged will be 18 provided by power generated by fluid flow through a 19 downhole generator similar to those used to power MWD systems.

21 22 A second possible embodiment of directional drilling 23 apparatus is illustrated in Fig. 5.

In this embodiment 24 the appratus 1 essentially consists of a counter-rotating cam 11 which fits between the upper 26 part 8 of the drill string and the lower part 9 of the 27 drill string.

The angle of the cam ll determines the 28 offset of the bottom hole assembly.

Suitable drive 29 means, not illustrated, are provided to rotate the cam 11 at the same speed as and in a direction opposite to 31 that of the drill string.

32 33 Other arrangements are possible, for example, a 34 Moineaux motor could be employed to provide orbital rotation of the lower end of the drill string and CA 02002135 1998-11-OS 1 attached drill bit, with the eccentric Moineaux rotor 2 being coupled to the lower end of the drill string to 3 cause it to nutate.

It is also envisaged that a 4 constant velocity type joint similar to that used in 5 many front wheel drive motor vehicles might be used in 6 place of the Hooke joint 4, 5.

In this case the the 7 anti-clockwise rotary action of a servo motor drives a 8 very slightly (0.5 degrees-1 degree) offset axis 9 thereby creating the orbital motion required from the 10 device.

11 12 Essentially, whichever arrangement is used, the 13 directional drilling apparatus creates a known bend in 14 a known direction of the lower portion of the drill string during rotary drilling when the anti-clockwise 16 nutatory and clockwise drill string rotary speeds are 17 equal.

This has the advantage over conventional 18 methods that drill string rotation can be maintained 19 whilst drilling in the deviated mode.

This alleviates the problem of hang up of stabilisers in the bore hole 21 and lower penetration rates in non-rotational modes of 22 deviated drilling employing downhole motors or 23 turbines.

24 In many drilling applications it is difficult to 26 maintain a uniform rotation speed for the drill string 27 and such speed fluctuations would degrade the effective 28 operation of the directional drilling apparatus of the 29 invention.

This problem can be overcome by including in the apparatus a control and monitoring device which 31 monitors the instantaneous rotary speed of the drill 32 string and controls variations of the operating speed 33 of the apparatus such as to cancel out the upsetting 34 effect of the drill string speed fluctuations.

CA 02002135 1998-11-OS 11 1 The necessary monitoring is preferably achieved using 2 accelerometers and magnetometers and a number of servo 3 motors may be used to provide the necessary rapid 4 response to rotary speed fluctuations of the drill string.

The use of such motors downhole requires some 6 modifications to ensure correct operation under 7 pressure or the provision of a sealed pressure chamber 8 to allow operation at normal atmospheric pressure.

9 The above is only one possible solution to the problem 11 and it is envisaged that a number of alternative 12 systems might be utilised.

Essentially the apparatus 13 used must achieve the basic requirement of using 14 dynamic information from the drill string, relating to speed and torque, to control and counter-rotate a 16 rotatable deviation direction control means which is 17 dynamically positioned so as effectively to remain 18 spatially invariant or stationary with respect to a 19 fixed direction of the borehole.

21 A similar result to that achieved with the above can be 22 obtained using an alternative type of apparatus which 23 will now be described.

In this alternative form of 24 apparatus which is a variation of the Fig. 5 apparatus, a slightly different approach is taken in that the 26 outer casing of the cam 11 is held stationary by an 27 arrangement of blades (not illustrated in Fig. 5) which 28 slide down the wellbore.

These blades are shaped and 29 sized such that they slide down the wellbore but are unable to rotate and so rotationally lock against the 31 wellbore.

The blades may be fixed, or the blades may 32 be variably extendable and held retracted until at 33 operating depth when they are fully extended, either by 34 a fixed amount or by the force of springs.

CA 02002135 1998-11-OS 12 1 Referring now to Figs. 6A and 6B these show a third 2 embodiment of directional drilling apparatus 30 in 3 accordance with the invention.

The apparatus 30 4 comprises a two-part cylindrical casing consisting of an upper casing section 32 and a lower casing section 6 34 joined to the upper casing section 32 by a 7 screw-threaded joint 36.

8 9 The upper end of the upper casing section 32 incorporates an API box connection 38 by which the 11 apparatus 30 is coupled in use to the lower end of a 12 drill string.

13 14 The lower end of the lower casing section 34 is formed as an articulated bearing or constant-velocity joint 40 16 (detailed subsequently) supporting a lower end 17 sub-section 42 of the apparatus 30, which incorporates 18 a further API box connection 44 to which a drill bit 19 (or a bit-mounting sub) is coupled in use of the apparatus 30 (see Figs. 8 and 9).

21 22 The joint 40 (transversely sectioned in Fig. 7) 23 comprises three circumferential rings of bearing balls 24 46 running in longitudinal grooves inside a part-spherical hollow lower end of the lower casing 26 section 34, and in longitudinal grooves on the outside 27 of a part-spherical upper end 48 of the lower end 28 sub-section 42. A cage 50 constrains the balls 46 to 29 maintain correct mutual alignment within the joint 40.

The joint 40 thus somewhat resembles a known form of 31 constant velocity joint as typically employed in 32 front-wheel-drive road vehicles, and the central row of 33 balls 46 do perform a torque-transmitting function in 34 known manner; however, the other two rows of balls 46 serve to give the joint 40 a bi-directionally effective CA 02002135 1998-11-OS 13 1 thrust-transmitting capacity absent from conventional 2 single-row constant velocity joints.

Thus the joint 40 3 couples torsional and end forces between the two 4 connections 38 and 44 while permitting the rotational axis of the lower end sub-section 42 to deviate 6 omni-directionally from the rotational axis of the 7 casing sections 32 and 34.

Therefore in use of the 8 apparatus 30 drilling torque can be transmitted from 9 the drill string through the joint 40 to the drill bit, as can downthrust or uplift, without the drill string 11 and drill bit necessarily turning co-axially.

12 13 The actual alignment of the rotational axis of the 14 lower end sub-section 42 with respect to the rotational axis of the casing sections 32 and 34 is controlled by 16 a rotational deviation direction control means which 17 will now be described in detail.

18 19 The upper end 48 of the lower end sub-section 42 is upwardly extended within and clear of the lower casing 21 section 34 by a hollow extension 52 terminated at its 22 upper end by a concentric journal spigot 54.

An 23 eccentric 56 is secured to the end of a drive shaft 58 24 rotatably mounted within the lower casing section 34.

The eccentric 56 is coupled to the journal spigot 54 on 26 the extension 52 through a rotary bearing 60.

Rotation 27 of the drive shaft 58 nutates the extension 52 and 28 causes it to orbit within the casing section 34, 29 pivoting a small angular amount about the kinematic centre of the joint 40 which allows such relative 31 pivotal movement; however, the extension 52 does not 32 rotate about its longitudinal axis relative to the 33 casing section 34 while being nutated by the eccentric 34 56 since the joint 40 does not allow such relative rotational movement.

CA 02002135 1998-11-OS 14 1 2 The speed and direction of rotation of the drive shaft 3 58 and hence of the eccentric 56 are determined by an 4 electric servo motor 60 controllably powered through a cable 62 from a servo control unit 64 deriving control 6 and motive power through a cable 66 from a battery pack 7 68 also containing position sensors.

8 9 The servo motor 60, the control unit 64, and the battery pack 68 are securely mounted within the hollow 11 interior of the casing sections 32 and 34, and are 12 dimensioned to leave fluid passages around them.

13 Apertures 70 in the upper end of the hollow extension 14 52 complete the ability of the apparatus 30 to pass fluid (eg. drilling mud) internally through its length 16 from the connection 38 to the connection 44, and hence 17 hydraulically link the drill string to the drill bit in 18 use of the apparatus 30.

19 The position sensors housed in the battery pack 68 may 21 comprise magnetometers and/or accelerometers or any 22 other suitable arrangements for sensing the 23 instantaneous azimuth or direction of a predetermined 24 hypothetical reference radius of the apparatus 30.

From the direction measurements, the servo control unit 26 64 powers the servo motor 60 to turn the drive shaft 58 27 and hence the eccentric 56 in a direction and at a 28 rotational speed that is substantially exactly equal 29 and opposite to the drill-string-induced rotation of the apparatus 30, while moreover maintaining a phase 31 relationship between these equal and opposite rotations 32 that causes the eccentric 56 to maintain an offset 33 position that is spatially substantially invariant and 34 in the chosen direction of deviation. (As an alternative to using special-purpose position sensors CA 02002135 1998-11-OS 1 in the pack 68, the control unit 64 may derive position 2 signals from an MWD system).

3 4 The net result is a contra-nutation of the extension 52 5 that cancels out rotation of the drill string to keep 6 the lower end sub-section 42 axially aligned in the 7 selected direction of deviation of the well bore.

8 Simultaneously, the joint 40 is transmitting the 9 bit-turning rotation of the drill string to the bit to 10 cause the well bore to be extended and deepened in the 11 intended direction of deviation.

12 13 Since the eccentric 56 has a fixed eccentricity, the 14 easiest procedure for converting the apparatus 30 to 15 cause undeviated drilling, is to nutate the extension 16 52 at a rate which is unrelated to the precisely 17 speed-controlled and phase-controlled rate required for 18 directional drilling: this is preferably achieved 19 simply by stopping the servo motor 60.

Thereupon the drill bit will undergo an indeterminate wobble or 21 eccentric motion that effectively drills on an 22 undeviated straight axis, possibly producing a slightly 23 greater bore diameter than the true bit diameter.

24 Instead of nutating by orbiting at a fixed radius, the 26 nutatory mechanism (whether an eccentric drive or any 27 other form) could be adjustable so as to enable 28 controllably variable angular deviations from zero up 29 to the mechanism-limited maximum deviation angle to give deviation angle control as well as the deviation 31 direction control previously described.

32 33 Fig. 8 shows the third embodiment of Figs. 6A, 6B and 7 34 in use for drilling a deviated well.

The directional drilling apparatus 30 has its upper and lower casing CA 02002135 1998-11-OS 16 1 sections 32 and 34 formed as or secured within upper 2 and lower stabilisers 80 and 82.

The upper stabiliser 3 80 is a full gauge stabiliser with a maximum outside 4 diameter substantially equal to the nominal bore diameter of the well being drilled, and the lower 6 stabiliser 82 may have the same or a slightly lesser 7 diameter.

8 9 The drill string to which the apparatus 30 is connected in use (via the API connection 38) is not shown in 11 Fig. 8 or Fig. 9, but a drill bit 84 is shown connected 12 to the lower end of the apparatus 30 (via the API 13 connection 44).

14 In the Fig. 8 configuration, the servo motor 60 is 16 controlled by the control unit 64 (drawing power from 17 the battery pack 68) to contra-nutate the lower end 18 sub-assembly 42 relative to the drill string rotation, 19 at an equal rotational speed and in the opposite rotational direction, and with rotational phase 21 relationship such that the rotational axis 86 of the 22 drill bit 84 is deviated downwards (as viewed in 23 Fig. 8) by a small angle relative to the rotational 24 axis 88 of the remainder of the apparatus 30 and of the neighbouring section of the drill string.

This results 26 in the well bore 90 being extended and deepened along a 27 line deviated from the line of the already-bored well, 28 as the drill string rotates the drill bit 84 to bore 29 through the surrounding geological formation.

31 In Fig. 9, the directional drilling apparatus 30 is set 32 for undeviated boring, either by stopping the servo 33 motor 60, or by reducing the nutatory orbital radius 34 substantially to zero (in the case of an eccentric drive, as in Fig 6A, by reducing the eccentricity to CA 02002135 1998-11-OS 17 1 zero by suitable adaptation of the Fig. 6A eccentric 2 drive).

3 4 In all the above described embodiments of the invention, rotation of the drill string is assumed to 6 be induced over its whole length (for example, by a 7 surface-level rotary drive).

However, some of the 8 advantages of the invention, principally those of 9 keeping the string rotating in a curved section of bore, can be obtained by fitting a motor or turbine 11 part way down the drill, below the surface and above 12 the directional drilling apparatus of the invention.

13 The drill string down to the motor or turbine can then 14 be stationary, and only the string below the motor or turbine will rotate during drilling, with the direction 16 drilling apparatus of the invention enabling deviation 17 direction control of the rotating lower end of the 18 string.

19 While certain modifications and variations have been 21 described above, the invention is not restricted 22 thereto, and other modifications and variations can be 23 adapted without departing from the scope of the 24 invention as defined in the appended claims.

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