TORQUE REDUCING TUBING COMPONENT

Abstract: A torque reducing tubing component for insertion in a tubing string to be used in a bore hole. Upsets (22,30,24,26,28) are mounted on the outer surface of the component which reduce the contact between the tubing string and the bore hole wall thereby reducing friction between the tubing string and the bore wall. Grooves (46) on the upsets act to channel fluid around the upsets creating a fluid bearing film between the contact points of the tubing string and the bore wall. A pressure differential is also created around the upsets serving to attract fluid away from the bore wall so improving the efficiency of the circulation of fluid to the surface. Particular reference is made to a torque reducing tubing component for use in a drill string which improves the efficiency of cuttings removal.

Description: TORQUE REDUCING TUBING COMPONENT The present invention relates to a component for insertion in a tubing string to reduce torque when the tubing string is inserted in to a bore hole. In particular the component is for use within the oil, gas and mining industries especially, but not exclusively, for drilling of high angle, horizontal and extended reach wells. In order to drill a well, a drill string is assembled by connecting lengths of drill pipe above a drill bit. The drill string is used to transfer rotary motion from the surface equipment to the drill bit, thereby causing the drill bit to rotate and penetrate formation. The torque required at surface to cause rotation of the drill bit is substantial due to the friction caused by contact between the drill string and the wall of the bore. An inherent part of this drilling process also involves the pumping of drilling fluid (mud) down the bore through the inside diameter of the drill string. This process is carried out to improve the drilling performance of the bit, to assist with cooling and lubrication of the bit as well as to provide a means for the transfer of the drill cuttings to surface. It is known to those skilled in the art that the conveyance of the drill cuttings is a function of well depth, well profile, shape and size of drill cuttings, mechanical properties of the drilling fluid and the capacity of surface mud pumps. Accumulation of drill cuttings in the well bore, resulting in the formation of a cuttings bed, is a major obstacle in any drilling operation. Such an accumulation of cuttings results in an increased down hole torque and in some instances can lead to a drill string getting stuck in the bore hole. Therefore, an efficient drilling fluid circulation process for the removal of such cuttings is essential for an efficient drilling operation. It is an object of at least one embodiment of the present invention to provide a method of hydra-mechanically agitating a cuttings bed in order to improve the efficiency of a circulating drilling fluid. A further object of at least one embodiment of the present invention is to provide a tubing component which reduces the rotational friction surface area of the drill string, therefore reducing torque. A yet further object of at least one embodiment of the present invention is to provide a robust, fail safe mechanical, stand-off within the drill string so as to m imise the rotational contact between the drill string and the bore wall. According to a first aspect of the present invention there is provided a torque reducing tubing component for insertion in a tubing string, the component comprising a generally tubular body having an inner bore on a longitudinal axis therethrough, first and second ends for connecting the component in the tubing string, and an outer surface including one or more upsets, the one or more upsets being located longitudinally along the body and extending circumferentially around the body. Preferably the upsets are integral with the tubular body. Thus the component may be of unitary construction. Preferably the component is made of steel. Alternatively the component may be made of titanium, aluminium or the like. Advantageously the component is made of the same material as the tubing string to which it is attached. The one or more upsets may be stand-off upsets. Preferably the stand-off upsets have an outer diameter greater than those of the connections on the first and second ends. In this way the outer surface of the stand-off upsets are the only points of the tubing string in contact with the bore hole wall. Preferably upon the outer surface of each stand-off upset are located a plurality of longitudinally extending arc grooves. More preferably the arc grooves spiral around the tubular body in a helical pattern. The arc grooves may provide 360 degree coverage on the outer surface of the stand-off upset. Preferably each arc groove comprises, in the direction of rotation of the tubing string, a first leading edge, an arc or cylindrical bed of the groove and a first trailing edge, wherein each edge connects the cylindrical bed to the outer surface of the standoff upset at an edge angle. More preferably the first leading edge includes a positive leading edge angle. Preferably the positive leading edge angle is greater than ninety degrees. More preferably the first trailing edge includes a positive leading edge angle also. Alternatively the one or more upsets may be agitator upsets. Preferably the agitator upsets have an outer diameter smaller than the outer diameter of the stand-off upsets. Thus the agitator upsets do not contact the wall of the bore hole when in use. Preferably upon the outer surface of each agitator upset are located a plurality of longitudinally extending notch grooves. More preferably the notch grooves spiral around the tubular body in a helical pattern. The notch grooves may provide 360 degree coverage on the outer surface of the agitator upset. Preferably each notch groove comprises, in the direction of rotation of the tubing string, a second leading edge, a notch or 'V bed of the groove and a second trailing edge, wherein each edge connects the notch to the outer surface of the agitator upset at an edge angle. More preferably the second leading edge includes a negative leading edge angle. Preferably the negative leading edge angle is less than or equal to ninety degrees. More preferably the second trailing edge includes a positive leading edge angle. More preferably the one or more upsets are a combination of stand-off upsets and agitator upsets. Preferably each stand-off upset is bounded longitudinally by one or more agitator upsets. Preferably the first and second ends comprise threaded pin and box connections respectively as are known in the art. Preferably also the connections include joint standoff upsets. The joint stand-off upsets may have a smaller outer diameter than the standoff upsets. Advantageously the joint stand-off upsets are integral with the component. Alternatively the joint stand-off upsets are made of chromium carbide or tungsten carbide in mild steel or equivalent matrix or like material. In the preferred embodiment of the present invention there are five upsets; two joint stand-off upsets located at the first and second ends of the component respectively and three combination upsets located equidistantly along the tubular body between the first and second ends. More preferably the combination upsets comprise a stand-off upset and two agitator upsets, one positioned on either side of the stand-off upset. The component may be a short collar, a short drill pipe and/or a short sub. Alternatively the component may be a casing or liner. In the preferred embodiment the component is a drill pipe, having a length approximately equal to the length of a single joint of drill pipe as is known in the art. According to a second aspect of the present invention there is provided a method of circulating fluid in a bore hole, the method comprising the steps of: (a) inserting a tubing string into the bore hole, the tubing string including a torque reducing tubing component; (b) pumping fluid down at least the inner bore of the torque reducing tubing component; (c) running the tubing string to cause the torque reducing tubing component to hydra-mechanically agitate the fluid; and (d) retorting at least a portion of the fluid to the surface via a path over the outer surface of the torque reducing tubing component. Preferably the torque reducing tubing component is according to the first aspect. In a preferred embodiment of the present invention, the tubing string is a drill string, the fluid is drilling mud and the portion of fluid returned to the surface includes drill cuttings. In a further embodiment of the present invention, the tubing string is a casing and the fluid is cement as would occur when cementing a casing. In step (c) of the method the tubing string may be reciprocated within the bore when run. Preferably the tubing string is rotated in the bore when run. In order to provide a better understanding of the invention, embodiments of the invention will now be described by way of example only with reference to the accompanying figures in which: Figure 1 a side view of a torque reducing tubing component in accordance with a first embodiment of the present invention; Figures 2 (a), (b) and (c) are consecutive longitudinal side views of a torque reducing tubing component according to a preferred embodiment of the present invention; Figure 3 a cross sectional view taken through section AA of the component of Figure 2; and Figure 4 a cross sectional view taken through section BB of the component of Figure 2. Referring initially to Figure 1, there is illustrated a torque reducing tubing component, generally indicated by reference numeral 10, according to a first embodiment of the present invention. The component 10 comprises a generally tubular or cylindrical body 12 having an inner bore (not shown) on a longitudinal axis extending through the length of the component 10. At a first end 14 of the component 10 is located a conical threaded pin 16 as is known in the art. At a second end 18 of the component 10 is located a box section 20 as is known in the art. Pin 16 and box section 20 are used to attach the component 10 to adjacent sections of a tubing string (not shown). Also shown in Figure 1 are raised portions or upsets 22-30. The upsets 22-30 are located on the outer surface 32 of the component 10. Each upset 22-30 is located longitudinally on the tubular body 12 and each upset 22-30 is arranged circumferentially around the body 12. The component 10 is of unitary construction being machined from a single piece of steel, as is known in the art for tubing. At the first end 14 and the second end 18 over the conical threaded pin 16 and box section 20, there are located upsets 22, 30. Upsets 22, 30 are joint stand-off upsets. The joint stand-off upsets 22, 30, provide a contact bearing surface at each end 14, 18 of the component 10. Such a contact surface provides a support at the joint between the end 14, 18 of the component 10 and adjacent tubing components in the tubing string. Located equidistantly between the first 14 and second 18 ends of the component 10 are three upsets 24, 26, 28. Each of the upsets 24, 26, 28 are equivalent. Each upset 24, 26, 28 comprises a stand-off upset 34 centrally located the stand-off upset 34 being bounded on each side by an agitator upset 36, 38. These upsets 24, 26, 28 will be described with reference to a single upset, 24 say. The stand-off upset 34 has an outside diameter which is greater than any other diameter on the component 10. Thus, in operation the stand-off upsets 34 located on each of the upsets 24, 26, 28 will provide the only contact points between the tubing string and bore wall. The reduced contact surface area between the tubing string and the bore wall reduces the friction between the tubing string and the bore wall, and consequently reduced torque is required to rotate the tubing string or to reciprocate the tubing string within the bore. Agitator upsets 36, 38 bounding the stand-off upset 34 provide a profile on the component 10 which assists in directing fluid around the outside surface 32 of the component 10. As shown in Figure 1, the stand-off upsets 34 and agitator upsets 36, 38 comprise a smooth outer surface which is parallel to the longitudinal axis of the component 10 and taper to the diameter of the component 10, thus there are no significant ledges within the tubing component to increase friction between the tubing string and the bore hole wall. Reference is now made to Figures 2(a), (b) and (c) of the drawings in which is shown a preferred embodiment of the present invention. The tubing component in the preferred invention is based on a length of drill pipe, this drill pipe component being generally indicated by reference numeral 40. Like parts to those of the embodiment of Figure 1 have been given the same reference numeral but are now suffixed "a". The drill pipe 40 comprises a tubular body 42 onto which is mounted a number of upsets. Reference is first made to Figure 2(a) which shows an upper section of the drill pipe component 40. Starting at the second end 18a of the drill pipe component 40 there is illustrated a box section 20a onto which is mounted a joint stand-off upset 22a, as described hereinbefore with reference to Figure 1. The joint stand-off upset 22a tapers to the tubular body 12a. The tubular body 12a between the box section 20a and an upset 24a is length of a drill pipe 42. Upset 24a comprises from the upper side an agitator upset 36a, a stand-off upset 34a and a further agitator upset 38 a. The outer diameter of the stand-off upset 34a is greater than both the outside diameter of agitator upsets 36a, 38a and the joint stand-off upset 22a. Therefore, when the drill pipe 40 component is installed on the drill string, only the outer surfaces of the stand-off upset 34a will be in contact with the bore hole wall for this section of the drill pipe component 40. In this embodiment, stand-off upset 34a includes on its outer surface 44 five longitudinally extending arc grooves 46. The arc grooves 46 spiral around the tubular body 12a in a helical pattern. The arc grooves 46 provide 360° coverage on the outer surface 44 of the stand-off upset 34a. Each arc groove 46 comprises a first leading edge 48, an arc or cylindrical bed 50 and a first trailing edge 52. Each edge 48, 52 connects the cylindrical bed 50 to the outer surface 44 of the stand-off upset 34a at an edge angle 54, 56 respectively. This is shown more clearly in Figure 3, which shows a section through Line A-A of Figure 2, which is a section through the stand-off upset 34a. In Figure 3 there is seen the tubular body 12a, outer surface 44 and a central inner bore 58. On the outer surface 44 are five arc grooves 46. Each arc groove comprises a cylindrical bed 50 with a first leading edge 48 and first trailing edge 52, bounding the bed 50 and connecting the bed 50 to the outer surface 44. Also illustrated are edge angles 54, 56. As is seen in the diagram, edge angles 54, 56 are positive edge angles, being acute. That is edge angles 54, 56 are both less than 90°. In use, the depth, shape and angle of the arc grooves 46 on the outer surface 44 of the stand-off upset 34 relative to the longitudinal axis direct the flow of the drilling fluid around the stand-off upset 34 at a relatively high velocity in such a way so as to create a film of fluid between the stand-off upset 34 and the bore wall. This has the effect of creating a marine bearing film between the two surfaces, resulting in the reduction of torque and drag co-efficient friction, as well as reduction in wear on the bore wall, when the bore wall is cased. Referring again to Figure 2(a), the stand-off upset 34a is bounded by agitator upsets 36a, 38a. Each agitator upset 36a, 38a has a smaller outer diameter than the stand-off upset 34a, and therefore the agitator upsets 36a, 38a do not contact the wall of the bore hole when in use. A description of a single agitator upset, 36a say will now be given, although it will be appreciated that this description is relevant to all agitator upsets within the preferred embodiment shown in Figure 2. Agitator upset 36a has an outer surface 60 upon which is located five longitudinally extending arc grooves 62. Each of the arc grooves 62 spiral around the tubular body 12a to provide 360° coverage on the outer surface 60 of the agitator upset 36a. Each arc groove 62 comprises, in the direction of rotation of the drill string, a second leading edge 64, a notch 66 which is a v-bed of the groove 62 and a second trailing edge 68. Each edge 64,68 connects the notch 66 to the outer surface 60 of the agitator upset 36 at an edge angle 70, 72 respectively (as will be described hereinafter with reference to Figure 4). Further, in a longitudinal direction each of the notch grooves 62 taper in width as they spiral upwards towards the second end 18a of the drill pipe component 40. In order to have a clearer understanding of the notch groove 62, we refer to Figure 4 which illustrates a sectional view through Line B-B of Figure 2. This cross sectional view of agitator upset 36a includes the inner bore 58 of the tubular body 12a with the outer surface 60. Each notch groove 62 has a second leading edge 64 and a second trailing edge 68. Between the edges 64,68 is located a notch or v-groove 66. The v-groove 66 is created by the edge angles 70, 72. Edge angle 70 is a positive or acute angle, being less than 90°, while edge angle 72 is an obtuse angle, being greater than or equal to 90°. In use during a rotary drilling operation, the relationship between the leading edge 64 and the trailing edge 68 of the notch grooves 62 of the agitator upsets 36 causes the creation of differential pressure zones. These differential pressure zones serve to attract drill cuttings away from the well bore wall and into the mainstream flow of the drilling fluid, therefore resulting in a more effective conveyance of the drill cuttings to the surface. This is achieved as the drill pipe component 40 is rotated within a well bore, in conjunction with the drill string, it forms a hydra-mechanical agitation means to move fluid within the well bore. It will be appreciated that the upsets 26a and 28a shown in Figures 2(b) and 2(c) are substantially identical to the upset 24a shown in Figure 2(a) and described hereinbefore. Referring to Figure 2(c), it is seen that at the lower or first end 14a of the drill pipe component 40 there is a conical threaded pin 16a for connecting the drill pipe component 40 to adjacent drill pipe lengths within the drill string. Located at the end 14a of the drill pipe component 40 is a joint stand-off upset 30a, which is similar in description to the joint stand-off 22a, discussed previously. Joint stand-offs 22a, 30a are manufactured by machining small spiral grooves around the outer surface, so as, in use, they reduce interference with the annulus flow cross sectional area at the ends 14a, 18a of the drill pipe component 40. In the preferred embodiment, joint stand-offs 22a and 30a are formed integrally with the drill pipe component 40. Alternatively, they could be made of chromium carbide or the like laid over the outer circumference of the ends 14a, 18a. The drill pipe component 40 of the preferred embodiment has a length approximately equal to the length of a single joint of drill pipe. Thus, the present invention differs from conventional arrangements of upset tubular designs in so far as it incorporates hydra-mechanical spirally profiled agitator zones on both ends of each stand-off upset, therefore resulting in a longer agitator zone(s) compared with conventional arrangements, yet ensuring zero contact between the agitator zones and the well bore wall. This unique feature makes the present invention a very effective tool for cuttings bed agitation at low circulation pressure drilling environment, whether in rotary or sliding (reciprocating) drilling modes. A principal advantage of the present invention is therefore that it provides a tubing component which provides a hydra-mechanical means of agitating the cuttings bed in a well bore, and so inherently has the effect of improving the drilling fluid circulation when drilling a bore hole. A further advantage of the present invention is that it reduces the rotational friction surface area of a tubing string, therefore reducing the torque required to rotate the tubing string. The present invention also has the advantage that it is a robust, fail safe, mechanical, stand-off element that forms part of a tubing string, thereby minimising the rotational contact between the tubing string and the bore wall, such a stand-off reduces the downhole torque and drag and also prevents damage or wear to a drill string and a cased section of a well bore if in place. Further modifications and improvements may be incorporated to the invention hereinbefore described without departing from the scope thereof. For example, the preferred embodiment described is with reference to a drill pipe in a drill string, however the tubing component may equally be formed from a section of casing, thus the stand-off upsets would reduce friction as the casing is run into the bore hole, while the agitator upsets would provide efficient mixing and agitation of the cement during cementing of the casing. It will also be appreciated that the features of the tubing component could be adapted onto a short collar, a short drill pipe and/or a short sub.

Claims: CLAIMS: 1. A torque reducing tubing component for insertion in a tubing string, the component comprising a generally tubular body having an inner bore on a longitudinal axis therethrough, first and second ends for connecting the component in the tubing string, and an outer surface including one or more upsets, the one or more upsets being located longitudinally along the body and extending circumferentially around the body. 2. A component as claimed in Claim 1 wherein the one or more upsets are standoff upsets. 3. A component as claimed in Claim 2 wherein the stand-off upsets have an outer diameter greater than an outer diameter of the connections on the first and second ends. 4. A component as claimed in Claim 2 or Claim 3 wherein a plurality of longitudinally extending arc grooves are located on an outer surface of each stand-off upset. 5. A component as claimed in Claim 4 wherein the arc grooves spiral around the tubular body in a helical pattern. 6. A component as claimed in Claim 4 or Claim 5 wherein each arc groove comprises, in the direction of rotation of the tubing string, a first leading edge, a cylindrical bed of the groove and a first trailing edge, wherein each edge connects the cylindrical bed to the outer surface of the stand-off upset at an edge angle. 7. A component as claimed in Claim 6 wherein the first leading edge includes a positive leading edge angle. 8. A component as claimed in Claim 6 or Claim 7 wherein the first trailing edge includes a positive leading edge angle. 9. A component as claimed in Claim 7 or Claim 8 wherein the positive leading edge angle is greater than ninety degrees. 10. A component as claimed in any preceding Claim wherein the one or more upsets are agitator upsets. 11. A component as claimed in Claim 2 wherein the agitator upsets have an outer diameter smaller than the outer diameter of the stand-off upsets. 12. A component as claimed in Claim 10 or Claim 11 wherein a plurality of longitudinally extending notch grooves are located on an outer surface of each agitator upset. 13. A component as claimed in Claim 12 wherein the notch grooves spiral around the tubular body in a helical pattern. 14. A component as claimed in Claim 12 or Claim 13 wherein each notch groove comprises, in the direction of rotation of the tubing string, a second leading edge, a notch or 'N' bed of the groove and a second trailing edge, wherein each edge connects the notch to the outer surface of the agitator upset at an edge angle. 15. A component as claimed in Claim 14 wherein the second leading edge includes a negative leading edge angle. 16. A component as claimed in Claim 14 or Claim 15 wherein the second trailing edge includes a positive leading edge angle. 17. A component as claimed in Claim 15 wherein the negative leading edge angle is less than or equal to ninety degrees. 18. A component as claimed in any preceding Claim wherein the one or more upsets are a combination of stand-off upsets and agitator upsets. 19. A component as claimed in Claim 18 wherein each stand-off upset is bounded longitudinally by one or more agitator upsets. 20. A component as claimed in any preceding Claim wherein the first and second ends comprise threaded pin and box connections respectively. 21. A component as claimed in Claim 22 wherein the connections include joint stand-off upsets. 22. A component as claimed in Claim 23 wherein the joint stand-off upsets have a smaller outer diameter than the stand-off upsets. 23. A component as claimed in any preceding Claim wherein the upsets are integral with the tubular body. 24. A component as claimed in any one of Claims 21 to 23 wherein there are five upsets; two joint stand-off upsets located at the first and second ends of the component respectively and three combination upsets located equidistantly along the tubular body between the first and second ends. 25. A component as claimed in Claim 24 wherein the combination upsets comprise a stand-off upset and two agitator upsets, one positioned on either side of the stand-off upset. 26. A component as claimed in any preceding Claim wherein the component is drill pipe. 27. A component as claimed in any preceding Claim wherein the component is a length of casing. 28. A method of circulating fluid in a bore hole, the method comprising the steps of: (a) inserting a tubing string into the bore hole, the tubing string including a torque reducing tubing component; (b) pumping fluid down at least the inner bore of the torque reducing tubing component; (c) πinning the tubing string to cause the torque reducing tubing component to hydra-mechanically agitate the fluid; and (d) returning at least a portion of the fluid to the surface via a path over the outer surface of the torque reducing tubing component. 29. A method as claimed in Claim 28 wherein the torque reducing tubing component is according to any one of Claims 1 to 27. 30. A method as claimed in Claim 28 or Claim 29 wherein the tubing string is a drill string, the fluid is drilling mud and the portion of fluid returned to the surface includes drill cuttings. 31. A method as claimed in Claim 28 or Claim 29 wherein the tubing string is a casing string and the fluid is cement as would occur when cementing a casing. 32. A method as claimed in any one of Claims 28 to 31 wherein at step (c) of the method the tubing string is reciprocated within the bore when run. 33. A method as claimed in any one of Claims 28 to 31 wherein at step (c) of the method the tubing string is rotated in the bore when run.

Inventors: RASTEGAR GHOLAM, RASTEGAR, GHOLAM
Applicants: RASTEGAR GHOLAM, WEATHERFORD LAMB, RASTEGAR, GHOLAM, WEATHERFORD/LAMB, INC.
Application year: 2001
Main classification: E21B17
IPC codes: E21B17