Downhole ratchet mechanism and method

Abstract

A downhole ratchet is utilized between tubulars in the drill string to reduce torsion energy in the drill string. The downhole ratchet is constructed to release when the tubular below the ratchet spins faster than the tubular above the ratchet. When the tubular below spins more slowly or at the same speed then the ratchet mechanism locks the upper and lower tubulars together to rotate the bit. The effect is to release torsional energy in the drill string to reduce and eliminate slip stick oscillations.

Claims

1. A downhole ratchet connectable in a drilling string to release torsional energy from said drilling string when drilling a wellbore, said drilling string extending from the surface to a drill bit, said downhole ratchet being connectable between a first tubular and a second tubular in said drilling string, said downhole ratchet comprising: a first component, a first threaded connection on said first component, said first threaded connection being threadably connectable with said first tubular; a second component mounted for rotation with respect to said first component, a second threaded connection on said second component, said second threaded connection being threadably connectable with said second tubular; and said first component and said second component comprising a mechanical arrangement that locks said first tubular and said second tubular together when said second tubular rotates at a velocity less than said first tubular, and permits further relative rotation between said first tubular and said second tubular when said second tubular rotates at a velocity greater than said first tubular to thereby release torsional energy from said drilling string.

2. The downhole ratchet of claim 1, further comprising a biased member that is urged to engage a gear tooth.

3. The downhole ratchet of claim 2, wherein said biased member is mounted for pivotal or axially movement.

4. The downhole ratchet of claim 1, wherein second tubular is mounted below said first tubular and whereby said second tubular is released for rotation by said mechanical arrangement when said second tubular rotates at a speed greater than said first tubular.

5. A downhole ratchet connectable in a drilling string to release torsional energy from said drilling string when drilling a wellbore, said drilling string extending from the surface to a drill bit, said downhole ratchet being connectable between an upper tubular and a lower tubular in said drilling string, said downhole ratchet comprising: a first member and a biased member mounted between said upper tubular and said lower tubular, said biased member being urged into contact with said first member; said first member and said biased member being connected to transfer torque from said upper tubular to said lower tubular when said lower tubular rotates at less than a rotational velocity of said upper tubular, wherein responsive to said lower tubular rotating faster than said upper tubular, said biased member is moveable with respect to said first member and permits further relative rotation between said upper tubular and said lower tubular.

6. The downhole ratchet of claim 5, wherein said first member comprises a gear tooth and said biased member is urged into contact with said gear tooth.

7. The downhole ratchet of claim 6, wherein said biased member is mounted for pivotal or axially movement.

8. The downhole ratchet of claim 5, wherein said first member comprises a first gear and said biased member comprising a second gear, said first gear and said second gear engaging each other to drive said drilling string, said first gear and said second gear being moveable away from each other when said lower tubular rotates faster than said upper tubular.

9. A method for controlling torsional oscillations in a drill string, said drill string extending from the surface to a drill bit, said method comprising the steps of: mounting a ratchet at a downhole position within said drill string, said ratchet transferring torque to said drill string below said ratchet when said drill string below said ratchet rotates at less than a velocity of said drill string above said ratchet, said ratchet permitting said drilling string below said ratchet to further rotate with respect to said drill string above said ratchet when said drill string below said ratchet rotates faster than a velocity of said drill string above said ratchet.

10. The method of claim 9, further comprising said drill string comprises a BHA (bottom hole assembly) and a drill pipe portion; said BHA being at a lowermost position in said drill string, said BHA comprising a bit and components comprising one or more of a bit sub, drill collar, heavyweight drill collar, heavy weight drill pipe, stabilizer, reamer, shock, hole opener, downhole motor, rotary steerable system, directional equipment, drilling while measurement equipment, steering unit, near bit inclination or a non-magnetic drill collar, said BHA being connected to said drill pipe portion of said drill string; and said drill pipe portion comprising one or more of a drill pipe, coiled tubing, heavyweight drill pipe, or a stabilizer.

11. The method of claim 9, further comprising said ratchet comprises a gear tooth and a biased member that is urged into contact with said gear tooth.

12. The method of claim 11, further comprising mounting said biased member to be pivotal or axially moveable.

13. The method of claim 9, further comprising providing that said ratchet comprises a first gear and a biased member wherein said biased member comprises a second gear, providing that said first gear and said second gear engage each other to drive said drill string, and providing that said first gear and said second gear are moveable with respect to each other when said drill string below said ratchet rotates faster than a velocity of said drill string above said downhole position.

Description

BRIEF DESCRIPTION OF THE FIGURES

(1) FIG. 1 discloses a drill string and one or more slip mechanisms located at selected positions in the drill string in accord with one possible embodiment of the invention;

(2) FIG. 2 discloses a ratchet mounted in the drill string between a first tubular, which may be an upper tubular, and a second tubular, which may be a lower tubular in the drill string in accord with one possible embodiment of the invention;

(3) FIG. 3 is an elevational view, partially in cross-section, of a downhole ratchet showing a vertical extent thereof in accord with one possible embodiment of the present invention; and

(4) FIG. 4 shows damping of torsional oscillations resulting from placement of a slip mechanism at a first position in a drill string.

DETAILED DESCRIPTION

(5) FIG. 1 shows a drill string 16 in which ratchet 10 could be mounted as shown in FIG. 2. Slip mechanisms may also be referred to herein as ratchet mechanisms or the like. The drill string 16 extends from an earth surface 18 to the drill bit 22. Surface drive 20 applies torque to rotate the drill sting to rotate the bit. Alternatively, the bit 22 may be driven by a downhole motor.

(6) The drill string 16 comprises a bottom hole assembly (BHA) 24 and a pipe string 26. The pipe string may also be referred to as a drill pipe portion or other related terminology. The BHA 24 is at a lowermost position in the drill string 16. The BHA 24 comprises a bit and components such as a bit sub, drill collar, heavyweight drill collar, heavy weight drill pipe, stabilizer, reamer, shock, hole opener, downhole motor, rotary steerable system, directional equipment, drilling while measurement equipment, steering unit, near bit inclination, and/or non-magnetic drill collar. While in FIG. 1 a top drive or rotary table drive on the surface is utilized to rotate the drill string, many wells are drilled with a downhole motor.

(7) The BHA is connected to the drill pipe portion 26 of the drillstring. The drill pipe portion 26 comprises additional components such as drill pipe, coiled tubing, heavyweight drill pipe, and/or stabilizer. The drill pipe portion 26 of the drill string is typically much longer than the BHA. Where the BHA may typically be in the range of 100 to 400 feet, the drill pipe portion 26 of the drill string may be several miles long.

(8) During normal drilling, the slip mechanism 10 operates the same as other tubulars in the drill string to convey power from the top drive to the drill bit. When Slip-stick occurs so that the drill bit sticks and then comes loose, the bit accelerates to a higher rotation velocity than the drill string velocity driven by the top drive, rotary table or downhole motor. At this time, the slip mechanism 10 allows the tubulars below to rotate independently with respect to the tubular above.

(9) FIG. 3 shows slip mechanism 10, a type of ratchet, that comprises slidably mounted upper gear 102, 103 and lower gear 104 that grip upper tubular 30 (FIG. 2) and lower tubular 32 (FIG. 2) and allow/prevent rotation. As explained previously, slippage depends on the relative velocity of outer body 34 and inner body 36 and lower portion 62 thereof as indicated by rotational arrows 50, 52. A flow path 38 is provided that extends through 10. Ball type bearings 51 are utilized to connect upper tubular to outer body 34 to inner body 36. Thrust bearing 69 provides a bearing for downward weight. When the velocity of lower tubular 32 (secured to threaded connection 64) is faster than upper tubular (secured to threaded connection 60) then upper gear 102 is pushed upwardly as indicated by arrow 108 against the bias provided by springs 110. Springs 110 are mounted in pockets such as pocket 112 in outer body 34 and in pocket 114 in moveable gear 103. Note that connectors 60 and 64 may be male or female and more typically connector 60 is female and connector 64 is male. When the velocity of lower tubular 32 is less than or equal to upper tubular 30 then upper gear 102 moves downward due to the bias as indicated by arrow 109. Upper gear 102 cannot rotate with respect to outer body 34 due to splines 116 that engage corresponding grooves 118 shown in dash.

(10) It will be appreciated for the claims that the terms first component and second component are for convenience and that either of the inner or outer body could be called a first component or second component. The inner body or outer body may also be referred to as an inner tubular or outer tubular.

(11) One advantage of downhole ratchet 10 is that very few moving parts are required. The drive force to rotate the bit is transmitted by teeth 106 on the two opposing gears.

(12) Accordingly, the upper gear 102 moves up and down in the pocket 119. However upper gear 102 is biased downwardly. It will be appreciated that many types of springs may be utilized instead of coil springs as shown. Outer body 34 is secured to the upper tubular 30 via threaded connection 60. The upper gear 102 has to rotate with the outer body 34 because the pocket 119 comprises splines 116. Because outer body 34 is threadably secured to the upper tubular 30, upper gear 102 is constrained to rotate with the upper tubular 30.

(13) The lower gear 104 connects to the lower tubular 32 through threaded connection 64. The lower gear 104 cannot move axially up and down. During normal drilling, the upper gear 102 drives the lower gear 104, which drives the drill string below the slip mechanism 10.

(14) If due to slip stick, lower gear 104 rotates faster than the upper gear 102 then the spring loaded upper gear 102 is pushed up and slipping occurs between upper gear 102 and lower gear 104 until the velocity of lower gear 104 drops to the driving speed of outer body 34.

(15) This releases torque energy in the drill string to dampen out torque oscillations.

(16) In other words, two saw-toothed gears 102, 104 with at least one gear 103 being spring loaded to press against each other with the toothed sides together. Rotating in one direction, the saw teeth of the drive disc lock with the teeth of the driven disc, making it rotate at the same speed. If the drive disc slows down or stops rotating, the teeth of the driven disc slip over the drive disc teeth and continue rotating.

(17) FIG. 4 shows the effect of damping of torsional vibrations in bit speed 174 (which may be closely related to the speed measured at lower tubular 32 or speed of inner body 36). Drilling speed 172 may be in the range of 120 RPM or so. The speed at which damage occurs in the drill string is shown at 170, which may be in the range of 240 RPM. Speed indicted at 176 could be in the range of zero RPM if full blown slip-stick is occurring.

(18) As discussed, a type of slip system utilized herein is purely mechanical and may be referred to herein as purely mechanical slip systems, ratchet, or the like. This slip apparatus is connectable between an upper tubular and a lower tubular in the drilling string. This slip system utilizes components that are mechanically linked to lock upper and lower tubulars together when said lower tubular rotates at a velocity equal to or less than said upper tubular, and permit relative rotation between said upper and lower tubulars when said lower tubular rotates at a velocity greater than said upper tubular to thereby release torsional energy from said drilling string.

(19) Many additional changes in the details, components, steps, and organization of the system, herein described and illustrated to explain the nature of the invention, may be made by those skilled in the art within the principle and scope of the invention. It is therefore understood that within the scope of the appended claims, the invention may be practiced otherwise than as specifically described.