WO2012069795A2

WO2012069795A2 - Downhole traction

Info

Publication number: WO2012069795A2
Application number: PCT/GB2011/001655
Authority: WO
Inventors: Neil Andrew Abercrombie Simpson
Original assignee: Neil Andrew Abercrombie Simpson
Priority date: 2010-11-26
Filing date: 2011-11-28
Publication date: 2012-05-31
Also published as: CA2818971A1; WO2012069795A3; EP2643540A2; GB201020129D0; US20130333949A1

Abstract

An apparatus for use in drilling a high angle or horizontal borehole has a body for coupling to a drill string and one or more traction members mounted for rotation on the body. The apparatus defines a first, passive, configuration and a second, active, configuration in which the traction member urges the apparatus along the inner wall of the borehole.

Description

Downhole Traction

Field of the Invention

This invention relates to downhole traction and more particularly, but not exclusively, to the provision of traction, the reduction of downward drag and of rotational torque in rotary drilling assemblies used to drill high angle or horizontal wellbores.

Background to the Invention

Within the oil and gas industry, the continuing search for and exploitation of oil and gas reservoirs has resulted in the development of directionally drilled exploration and production well boreholes, that is boreholes which extend away from vertical and which permit the borehole to extend into the reservoir to a greater extent.

Directionally drilled boreholes are now being drilled deeper, longer and higher in angle (from vertical) than previously, with boreholes now being drilled horizontally for considerable distances. Indeed, in some cases the horizontal step out from the position of the surface location of the drilling site may be as much as 11 kilometres.

In order to create any borehole, it is necessary to exert sufficient force on the drill bit to enable the drill bit to drive through rock, known as weight on bit. In today's horizontal and high angle borehole drilling, the current method using rotary drilling equipment is for the weight on bit to be provided by the downward gravitational force of the portion of the drill string situated in the upper, vertical or lower angle (nearer to vertical) section of the borehole. This downward gravitational force, which is generally provided by heavy weight drilling tubulars, such as heavy weight drill pipe, is

transmitted in the form of compression through the rotating drilling tubulars to the portion of the drill string situated in the lower, high angle or horizontal section of the borehole in order to apply the necessary weight on bit.

Although the current system of drilling high angle and horizontal boreholes is effective, it suffers from a number of performance reducing factors.

For example, it will be recognized that for boreholes having a significant non- vertical section, a major percentage of the drilling tubulars forming the lower portion of the drill string, which would normally contribute to the weight on bit in a vertical borehole, are unable to contribute to the weight on bit.

Also, the high angle or horizontal portion of the drill string will typically lie on the low side of the bore wall, resulting in increased wear and the need for greater weight on bit to overcome frictional forces.

Also, compression applied to a long string of rotating drilling tubulars in a borehole tends to cause a degree of buckling and pipe whirl, forcing the rotating tubulars against the bore wall and again creating increased longitudinal friction, rotational friction and wear to the drilling tubulars.

Some of these factors can be mitigated by the provision of spacers known as stabilisers situated at strategic positions and in sufficient numbers along the drill string. However, the stabilisers themselves introduce a number of negative factors when applied in high angle and horizontal drilling.

Drilling stabilisers typically fall into two main categories: fixed blade stabilisers and non-rotating stabilisers. Fixed blade stabilisers have a body for coupling to the drill string and, as their name implies, one or more blades either fixed to the body or formed as an integral part of the body. The blades, which are typically formed in a spiral to increase borehole wall contact, rotate with the drill string to which they are attached. By centralising the tubulars in the borehole and reducing wellbore wall contact, fixed blade stabilisers may address or mitigate the buckling or whirling effects of applied compressive loads. However, because the stabiliser blades by design remain in contact with the wellbore wall and because friction is independent of area, fixed blade stabilisers do little to reduce the effect of rotational friction in the high angle or horizontal sections of the wellbore where most of the weight of the drilling tubulars are now being supported by the stabiliser blades on the low side of the borehole.

It may be argued that by reducing the contact between the drill string and the borehole wall, stabilisers assist in keeping the drill string moving and, by virtue of the fact that dynamic friction of the stabiliser blade rotating against the borehole wall is lower than static friction, thus reduce longitudinal friction. However, the dynamic friction component remains and must also be overcome by the compressive forces applied through the drilling tubulars from higher up the borehole. This residual longitudinal dynamic friction component has to be considered as an unavoidable but detrimental factor associated with the use of fixed blade stabilisation in high angle and horizontal boreholes.

As in the case of fixed blade stabilisers, non-rotating stabilisers have a body for coupling to the drill string. However, in non-rotating stabilisers the stabiliser blades are attached to or are integral with a sleeve provided around the body. A bearing is provided between the outside of the body and the inside of the sleeve so that, in use, the sleeve and body are relatively rotatable (the sleeve is non-rotating relative to the rotating body and drill string). The main benefit of this type of stabiliser, besides centralising the rotating drilling tubulars, is to substantially reduce the rotational friction effect experienced by conventional fixed blade stabilisers. This is achieved by the bearing between the rotating tool body and the non-rotating sleeve being very much more efficient than the fixed blade stabiliser blades rotating against the inside diameter of the bore. However, the fact that the non-rotating stabiliser sleeve is effectively static with respect to the wall of the bore and given that static friction is higher than dynamic friction, this introduces a secondary negative factor that has a detrimental effect known as stick slip.

Stick slip is caused by the forces required to overcome the longitudinal static friction component of the non-rotating stabiliser blades in contact with the borehole wall when moving the drilling tubulars forward or down to apply more weight to the drill bit. These forces put the drilling tubulars, between the drill bit and the drilling tubulars higher up the bore that provide the applied force, into further compression like a compression spring so that when the lower section of drilling tubulars start to move to overcome the longitudinal static friction component, and because static friction is higher than dynamic friction, they do so in a "stick slip" fashion. For example, the drilling tubulars that form the lower part of the drill string and drilling assembly which are being supported and centralised by these non-rotating stabilisers stick initially, as the drilling tubulars are lowered or moved forward in order to apply further weight to the drill bit, and then slip driven by the compressed tubulars above them, once the static friction component is overcome, applying weight on bit in an uncontrollable manner.

Both rotational and longitudinal friction are major detrimental factors which reduce rotational input power and the ability to control applied weight on bit in high angle and horizontal rotary drilling applications, reducing the rate at which the borehole can be progressed and substantially increasing the cost to complete the bore, as well as the possibility of causing damage, and reduced life, to the drill bit.

In addition to the issues described above when drilling the borehole, if it is ever desired to move the drill string in a reverse direction, that is out of hole, similar issues with friction may arise. Pulling the drill string out of a borehole having a high angle or horizontal section may suffer from a further problem in that the vertical pull force exerted on the drill string causes the curved portion of the drill string situated around the heel of the borehole to contact the upper wall of the borehole, known as the capstan effect. This may make it difficult or even impossible to pull the drill string out of the borehole.

Summary of the Invention According to a first aspect of the present invention, there is provided an apparatus for use in drilling a high angle or horizontal borehole, the apparatus comprising:

a body for coupling to a drill string; and

a traction member mounted for rotation on the body, the apparatus having a first, passive configuration and a second, active, configuration in which the traction member urges the apparatus along the inner wall of the borehole.

The apparatus may be configured to be urged along the inner wall of the borehole in a selected direction. In particular embodiments, the apparatus may be configured to be urged in a reverse direction. For example, the apparatus may be configured to drive the apparatus, and any connected components or assemblies such as the drill string, in an out of hole direction. Alternatively, the apparatus may be configured to be urged in a forward direction. For example, the apparatus may be configured to drive or tractor the apparatus, and any connected components or assemblies such as the drill string, in a downhole direction.

Embodiments of the present invention beneficially provide a transport mechanism for moving a drill string along a high angle or horizontal borehole and may eliminate or reduce the need to transmit longitudinal forces from surface.

When configured to urge the apparatus in a reverse direction, embodiments of the invention may permit controlled movement of the drill string in a reverse direction without the risk of the drill string becoming stuck due to the capstan effect.

Also, when configured to urge the apparatus in a forward direction, embodiments of the invention may reduce the requirement for compressive forces transmitted through the drilling tubulars from higher up in the borehole or from surface, eliminating or reducing the detrimental effects of "stick slip" to provide effective controllable weight on bit when drilling in a high angle and horizontal borehole.

Embodiments of the present invention also substantially improve on the existing prior art by combining the beneficial aspects of both fixed blade and non-rotating stabilisers whilst eliminating the negative aspects of both.

The apparatus may be configured to be urged along the inner wall of the borehole in response to rotation of the apparatus and/or the drill string.

In preferred embodiments, the traction member may be adapted for mounting on the body at a skew angle relative to a longitudinal axis of the body. The provision of a skew angle introduces a longitudinal force component to the interaction between the traction member and the bore wall which acts to urge the apparatus along the bore wall. Accordingly, the traction member may roll in helical rather than circumferential path around the inside of the borehole when the body is rotated, this rolling helical path having the effect of transporting the apparatus together with the attached drill string along the borehole wall.

The direction of skew angle of the traction member may be selected to urge the apparatus in the selected direction along the inner wall of the borehole. For example, the direction of skew angle may be selected to urge the apparatus in the reverse or out of hole direction. Alternatively, the direction of skew angle may be selected to urge the apparatus in the forward or downhole direction.

The angle of skew of the traction member may be selected to urge the apparatus along the inner wall of the borehole at a selected rate. As the rotational speed of rotary drilling assemblies is normally limited between 100 and 200 rpm and the borehole diameter of the section drilled through the reservoir is generally but not always 8.5" (about 216 mm) or less, and the drilling rate of penetration generally below 100 ft. per minute (about 0.51 metres per second), then the skew angle required to provide efficient forward traction and transport system is relatively small, for example 1 degree or less. In particular embodiments, the skew angle may be 0.5 degrees. In other embodiments, the skew angle may be between 1 degree and 5 degrees. In other embodiments, the skew angle exceeds 5 degrees. However, in some circumstances it may be desirable for the skew angle to be higher. In order to provide efficient reverse traction, it is envisaged that a reverse skew angle in the range of about 3 degrees to 5 degrees may be selected.

In particular embodiments, the selected skew angle may be set at surface.

However, the apparatus may alternatively be configured so that activation of the traction member from the passive configuration to the active configuration provides the skew angle. For example, the traction member may be positioned coaxially (that is, without a skew angle) relative to the longitudinal axis of the body at surface, activation of the apparatus from the passive configuration to the active configuration providing a skew angle.

The apparatus may be configured so that the traction member is offset from the borehole wall in the passive configuration. The traction member may be mounted on the body so that the traction member does not contact the inner wall of the borehole in the passive configuration, the traction member only contacting the borehole wall when in the second, active, configuration.

Alternatively, the apparatus may be configured so that the traction member contacts the borehole wall in both the passive and active configurations. The traction member may thus assist in reducing or mitigating rotational friction forces in both the passive and active configurations.

The apparatus may further comprise an activation arrangement for moving the traction member from the passive configuration to the active configuration. The apparatus may be configured so that the traction member moves radially, for example by 3 to 5 mm, when moving from the passive configuration to the active configuration. The activation arrangement may be configured to urge the traction member into contact with the borehole wall. Alternatively, where the apparatus is configured so that the traction member contacts the borehole wall in the passive configuration, the activation arrangement may urge the traction member further into contact with the borehole wall.

The activation arrangement may be of any suitable form. The apparatus may comprise at least one of a hydraulic activation arrangement, a pneumatic activation arrangement, and/or mechanical activation arrangement.

The activation arrangement may be configured to selectively expose the traction member to a differential pressure. The differential pressure may comprise the difference between the internal pressure of the apparatus, which may be applied from surface, and the annulus pressure, that is the pressure between the outside of the apparatus and the borehole wall. The apparatus may be configured so that the differential pressure acts on a selected area of the traction member or apparatus, the applied differential pressure multiplied by the selected area providing an activation force acting to urge the traction member from the passive configuration to the active configuration. The longitudinal component of the activation force may form a traction force for urging the apparatus along the borehole wall.

The differential pressure may be of any suitable magnitude. For example, the differential pressure may be selected to be 1000 psi. The selected area may be of any suitable area. For example, the selected area may be around 5 square inches. Thus, for a differential pressure of 1000 psi and a selected area of 5 square inches, the activation force would be 5000 lbs force. Taking frictional forces into account, a activation force of 5000 lbs force may be converted into a traction force in the region of 3000 to 4000 lbs force. The apparatus may be configured so as not to exceed the force at which expansion of any surrounding tubulars, such as a section of casing, will occur.

In particular embodiments, the activation arrangement may comprise a sleeve adapted for location within the body throughbore. In use, the sleeve may be configured for axial/longitudinal movement relative the body to permit fluid access to urge the traction member from the passive configuration to the active configuration. In some instances, this may involve urging the traction member radially outwards to contact the bore wall. Alternatively, or additionally, this may involve urging the traction member from a position in which the traction member is coaxial with the longitudinal axis of the body to a skewed position relative to the longitudinal axis.

The sleeve may be of any suitable form. For example, the sleeve may comprise a collet sleeve having a number of collet fingers. One or more of the collet finger may comprise a tab for engaging a groove provided in the body throughbore. Alternatively, or additionally, the sleeve may comprise a ball retent sleeve or the like.

The activation arrangement may further comprise a shear pin or other suitable device for holding the sleeve within the body. In use, the sleeve may be released by sending a control element, such as an activation dart or ball, down through the drill string to seat on the sleeve. The activation arrangement may further comprise a rupture disk or the like, for coupling to the control element. In use, the rupture disk may permit the control element, such as the dart or ball, to be run into the sleeve. In use, applying fluid pressure above the control element, dart or ball may shear the shear pin and release the sleeve. The sleeve may be caught by a catcher or shoulder provided in the body throughbore. Movement of the sleeve may permit the pressure differential to act on the traction member from the passive configuration to the active configuration. Further application of fluid pressure may rupture the rupture disk and permit fluid access below the apparatus, for example to another apparatus according to the present invention or another tool in the drill string.

The traction member may be of any suitable form and construction. In particular embodiments, the traction member may comprise a roller or journal. The roller may be adapted for rotation relative to the body on a roller bearing shaft. The traction member may be of sufficient diameter that the central longitudinal axis of the body lies within the diameter of the traction member. The axis of the skewed traction member may lie within less than half its diameter from the central longitudinal axis of the body. The traction member may be constructed at least in part from an elastomeric or polymeric material, although any suitable material may be used where appropriate.

The traction member may be of a split or un-split design.

The apparatus may comprise one traction member. However, in particular embodiments, the apparatus may comprise a plurality of traction members arranged around the body. In preferred embodiments, the apparatus may comprise three traction members circumferentially arranged around the body at 120 degrees, although any other suitable arrangement may be used where appropriate.

The body may be of any suitable form and construction. In particular

embodiments, the body comprises a cylindrical mandrel having a throughbore for passage of fluid therethrough. The body may comprise a thick wall tubular. The body may further comprise attachment means provided at one or both ends for coupling the body to another element, such as drill tubulars or other components of a drill string. The attachment means may be of any suitable form. For example, the attachment means may comprise a threaded connection, in particular but not exclusively a threaded box and pin connection. Alternatively, the attachment means may comprise or further comprise an adhesive bond, quick connect attachment or other suitable connector.

The body may comprise an upset diameter portion, that is a portion having greater radial extent that the remainder of the body. The upset diameter body portion may extend substantially axially or may extend at least partially circumferentially around the body. In particular embodiments, the upset diameter body portion may extend in a helical arrangement. The upset diameter body portion may define or provide mounting for a stabiliser blade of the apparatus.

Longitudinal cut out portions may be provided in the upset diameter portion of the body to provide fluid and/or debris bypass when the apparatus is in operation.

A recess or pocket may be provided in the body, in particular but not exclusively, the upset diameter portion of the body. The recess may be adapted to receive the traction member.

The traction member may be adapted for mounting in the body directly.

Alternatively, and in preferred embodiments, the apparatus may further comprise a carrier into which the traction member is rotatably mounted. Where a carrier is provided, the apparatus may be configured so that the differential pressure acts on a selected area of the carrier to urge the traction member from the passive configuration to the active configuration.

A seal element may be provided between the carrier and the body. The seal element may be of any suitable form. The seal element may be provided between the carrier and the body so as to permit movement of the carrier in a radial direction. The seal element may comprise at least one of a urethane rubber material, hydrogenated nitrile material or swelling elastomer material.

The traction member may be mounted in the body by any suitable means.

For example, the traction member may be secured by means of one or more tapered retention block. The taper of the retention block or blocks may be sufficient to secure the blocks to the body. In particular embodiments, the retention blocks may be secured by a latch lock. The retention blocks may be further secured in place by a fastener such as at least one cap bolt, although any suitable means may be used where appropriate.

The bearing shaft and retention blocks may form a roller assembly of which there may be a number, circumferentially spaced around the upset section of the cylindrical tool body.

The traction member, for example the roller mounted on the roller bearing shaft, may be provided with one or more pressure-compensated radial bearings. Lubricant, for example pressure-compensated lubricant, may be held within a reservoir in the retention block, or one or more of the retention blocks where more than one block is provided. The reservoir may comprise a pressure-compensated, modular, positive pressure reservoir contained within the centre portion of the retention block.

Beneficially, the internal volume of the retention block may provide the facility to contain substantially more lubricant than is currently provided in rolling element tools of equivalent size, thereby increasing the life of the radial bearings in operation.

The lubricant may be directed to the bearing by any suitable means. For example, the lubricant held within the positive pressured reservoirs may be fed into a drilled central bore at either end of the bearing shaft and fed to the bearing by means of one or more cross-drilled hole communicating between the drilled central bore and lubrication grooves machined on the external diameter of the bearing shaft.

The lubricant may be retained within the bearing section of the traction member by at least one rotary seal. In particular embodiments, the lubricant may be retained within the bearing section of the traction member by a number of rotary seals located at either end of the traction member between an external diameter of the bearing shaft and an internal diameter of the traction member.

The end thrust loads experienced by the traction member or members due to the traction forces may be supported by a bearing. The bearing may, for example, comprise one or more internal thrust bearings. The internal thrust bearing or bearings may be contained within the pressure compensated area of the traction member.

Alternatively, the bearing may comprise one or more mud lubricated thrust bearing situated at an, or either, end of the traction member and outwith the sealed pressure compensated area of the traction member, that is between the traction member and the bearing faces on the retention blocks.

The apparatus may further comprise at least one further traction member. The further traction member may comprise a fixed traction member, that is, a traction member not having passive and active configurations. It is envisioned that the further traction member may have either no skew or a forwardly-directed skew angle so that the further traction member or members assist in urging the apparatus downhole. Accordingly, the apparatus may comprise one or more fixed, forwardly urging traction member in addition to one or more traction member capable of moving from a passive configuration to either increase forward thrust or provide reverse thrust. Since the skew angle of the reverse-directed traction member or members may be selected to be greater than the angle of the forward-directed traction member or members, then reverse thrust may still be achieved in the presence of forward-directed traction members.

The apparatus may form, or form part of, a downhole stabiliser.

The apparatus may be configured for use in a cased hole or open hole borehole section.

According to a further aspect of the present invention, there is provided an downhole assembly for use in a high angle or horizontal borehole, the assembly comprising a drill string and one or more apparatus according to the first aspect of the invention.

The assembly may further comprise a drilling assembly for drilling a borehole.

By providing a number of apparatus in combination, the assembly may be configured to provide increased thrust in a selected direction. Alternatively, one or more of the apparatus' may be configured to urge the assembly in a reverse or out of hole direction and one or more of the apparatus' may be configured to urge the assembly in a downhole direction, the apparatus' selectively activated to either drive the asssembly in a forward or reverse direction as required.

At least one of the apparatus' may be arranged at selected downhole locations, so as to provide a traction force at a selected location of the borehole. For example, one or more apparatus may be located at or near a heel section of a high angle or horizontal borehole in order to overcome the capstan effect. Alternatively, one or more apparatus may be provided adjacent a distal leading end of the assembly.

Other aspects of the invention relate to methods of providing traction, the reduction of downward drag and of rotational torque in rotary drilling assemblies used to drill high angle or horizontal wellbores.

According to a further aspect of the present invention, there is provided an apparatus for use in high angle or horizontal drilling applications, the apparatus comprising:

a body for coupling to a drill string; and

a traction member mounted for rotation on the body, the traction member mounted on the body by means of at least one latch locked retention block. The latch locked retention block or blocks of this further aspect may comprise the retention blocks described above in relation to the first aspect of the invention.

It should be understood that the features defined above in accordance with any aspect of the present invention or below in relation to any specific embodiment of the invention may be utilised, either alone or in combination, with any other defined feature, in any other aspect of the invention.

Brief Description of the Drawings

These and other aspects of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

Figure 1 is a longitudinal section view of an apparatus according to an embodiment of the present invention;

Figure 2 is a perspective view of the apparatus of Figure 1 , showing the main body, collet sleeve and activation dart assemblies separately;

Figure 3a - 3c are diagrammatic views showing the mechanism of the present invention;

Figure 4 is an isometric view of an apparatus according to another embodiment of the present invention;

Figure 5 is a plan view of the apparatus shown in Figure 4;

Figure 6 is a longitudinal sectional view of the apparatus shown in Figures 4 and 5 along section A - A;

Figure 7 is an enlarged perspective view of a roller assembly according to the present invention;

Figure 8 is a plan view of the roller assembly of Figure 7;

Figure 9a shows an exploded view of part of the roller assembly shown in Figures 7 and 8;

Figure 9b shows an exploded view of part of a roller assembly and body showing an alternative construction; and

Figure 10 shows a longitudinal section view of a ball retent sleeve and activation dart according to an alternative embodiment of the present invention.

Detailed Description of the Drawings

Referring first to Figure 1, there is shown a longitudinal sectional view of an apparatus 10 according to an embodiment of the present invention.

The apparatus 10 has a generally cylindrical body 12 having a throughbore 14 for passage of fluid or tools therethrough. The body 12 is provided with threaded box 16 and threaded pin 18 connections at upper and lower ends for connecting the body 12 to drill tubulars (shown schematically as 20, 22). The apparatus 10 and drill tubulars 20, 22 form part of a drill string for use in a high angle or horizontal borehole, such as an oil or gas exploration or production wellbore, and in use the apparatus 10 provides for traction of the drill string as well as the reduction of downward drag and of rotational torque of the drill string in high angle or horizontal well bore drilling applications.

As shown in Figure 1 , the body 12 further comprises an upset diameter portion 24 in which there is provided a recess or pocket 26 for mounting a traction roller assembly 28. The traction roller assembly 28 comprises a traction roller 30 mounted on a carrier 32 via a bearing shaft 34. The traction roller 30 is mounted at an offset radial position from a central longitudinal axis C of the body 12 and the diameter of the traction roller 30 is such that the roller 30 does not extend beyond the central axis C. In the embodiment shown, the traction roller 30 comprises a barrel roller, although it will be recognised that the roller 30 may be of any suitable configuration.

The carrier 32 has a shoulder 36 shaped to engage a corresponding shoulder 38 of the pocket 26, preventing removal of the roller assembly 28 from the pocket 26.

In the embodiment shown in Figure 1, an inner surface 40 of the carrier 32 may be exposed to fluid in the throughbore 14, so that the carrier 32 may be urged in a radially outward direction relative to the pocket 26 from a first, passive configuration in which the roller 30 does not contact the inner wall of the borehole to a second, active configuration in which the roller 30 engages the inner wall of the borehole.

A bonded elastomer element 42 is provided between the carrier 32 and the pocket 26, the bonded elastomer element 42 providing a seal between the carrier 32 and the throughbore 14 in use, while also permitted a degree of movement of the carrier 32 between the passive and active configurations.

Only a single roller assembly 28 and pocket 26 are shown in the sectional view of Figure 1. However, and referring now also to Figure 2 which shows a perspective view of the apparatus 10, the apparatus 10 preferably comprises three pockets 26 and three roller assemblies 28 circumferentially spaced at 120 degrees around the body 12.

As shown in Figure 2, it can be seen that upset diameter body portion 24 is formed from a number of helical blades with external passages 44 provided to permit fluid and debris bypass around the apparatus 10.

As can be seen most clearly from Figure 2, the apparatus 10 is configured so that the longitudinal axis of the traction roller 30 is skewed by between about 3 degrees to about 5 degrees relative to the longitudinal axis of the body 12. The provision of a skew angle introduces a longitudinal component to the interaction between the traction roller 30 and the borehole wall such that, on rotation of the body 12, the roller 30 will, in addition to providing a rolling contact between the apparatus 10 and the borehole wall, provide a longitudinally directed force urging the apparatus 10 and associated coupled drill tubulars 20, 22 of the drill string along the inner wall of the borehole. In the embodiment shown, the direction of skew angle is selected to provide a reverse thrust force on the borehole wall which acts to urge the apparatus 10 in an up hole direction. However, it will be recognised that the skew angle may be selected to provide forward, downhole directed thrust force if required.

To assist in understanding the mechanism of the present invention, reference is made to Figures 3a to 3c which show simplified perspective views showing a body and a single roller. Figure 3a is shown for comparison and shows an arrangement having a roller mounted coaxially (no skew angle) on a body. In use, as the body rotates about its longitudinal axis, the roller about its longitudinal axis but in the opposite direction. As the roller has no skew angle with respect to the body, there is no longitudinal force component between the roller and the borehole wall and so no longitudinal movement of the body. Turning to Figures 3b and 3c, where the roller is provided with a skew angle relative to the body, it will be recognised that the interaction between the roller and the borehole wall will now involve a longitudinal component, that is a component acting in the direction of the longitudinal axis of the body. As can be seen from Figures 3b and 3c, where the roller is skewed in the direction shown in Figure 3b, rotation of the body in the direction shown will cause the body to be urged in the direction shown by the arrow A. Conversely, where the roller is skewed in the direction shown in Figure 3c, rotation of the body in the same direction will cause the body to be urged in the opposite direction, as shown by arrow B. As will be understood by the person skilled in the art, as a drill string is typically constructed from section of tubulars threadedly coupled together, a drill string will only be rotated in one direction to avoid the threaded coupling of the string from disengaging. Beneficially, embodiments of the present invention thus permit forward or reverse thrust to be achieved while also rotating the body in a single direction.

Referring again to Figures 1 and 2, in order to retain the apparatus 10 in the first, passive configuration, a collet sleeve 46 having fingers 47 is provided within the throughbore 14. The sleeve 46 is secured within the throughbore 14 by a shear pin 48 and a national pipe thread (NPT) seal plug 49. Elastomeric seals or rings 51 may be provided in grooves 53 in the collet sleeve 46 to isolate the section of the throughbore 14 around the roller assembly 28. In use, in order to activate the apparatus 10 from the first configuration to the second configuration, an activation dart 50 is dropped or driven down the drill string and into the apparatus throughbore 14. A rupture disk 54 is secured to the dart 50 by a retainer ring 56 to prevent fluid passage through the dart 50 and allow the dart 50 to be propelled through the drill string.

Application or continued application of fluid pressure will overcome the shear limit of shear pin 48 to release the collet sleeve 48 to move relative to the body 12 and thereby expose the carrier surface 40 to fluid pressure sufficient to urge the carrier 32, and thus the roller 30, into contact with the borehole wall. The collet sleeve 46 will travel through the throughbore and engage a shoulder 54 provided in the throughbore 14. Also, the collet fingers 47 will engage a groove 56 provided in the throughbore 14.

Still further application of fluid pressure will burst the rupture disk 54 and permit fluid or tool passage through the body 12. Rupture of the disk 54 may be detected as surface, providing an indication that the apparatus has set. It will be understood that this process may be repeated for each apparatus 10, where a number of apparatus' 10 are provided.

Referring now to Figures 4, 5 and 6, there are shown perspective, plan and longitudinal sectional views of an apparatus 100 according to another aspect of the present invention. The apparatus 100 comprises a thick-walled cylindrical tool body 102 with a throughbore 104 and threadable attachment means in the form of threaded pin 106 and threaded box 108 (see Figure 6) connections at either end for connecting the body 102 to drill tubulars 110, 112 (see Figure 6).

The thick-walled cylindrical body 102 has an upset section 114 through which are machined fluid bypass grooves 116 to form raised sections or pads 118. As shown in Figures 4 to 6, the raised pads 118 of the upset section 114 extend substantially axially along the body 102, although it will be recognized that the pads 118 and grooves 16 may be of any suitable configuration and may for example define a helical configuration similar to the portion 24 of apparatus 10 (shown in Figure 2).

Machined bays or pockets 120 are formed in the pads 118, into which are mounted roller assemblies 122. One pocket 120 and one roller assembly 122 may be provided. However, it is envisaged that the apparatus 100 may provide mounting for three roller assemblies 122, for example arranged in a spaced fashion at 120 degrees around the circumference of the body 102.

Each roller assembly 122 has a roller 124 supported on a bearing shaft 126, the shaft 126 held in place at either end of the pocket 120 by means of two tapered latch locked retention blocks 128. The blocks 128 are described in more detail below with reference to Figures 7, 8 and 9.

The bearing shaft 126 is angled or skewed with respect to the central longitudinal axis C of the thick walled cylindrical tool body 110, thus skewing or applying angle to the roller 124 mounted on the shaft 126. In the embodiment shown, the skew angle is selected to provide forward thrust force, urging the apparatus 100 and the coupled drill tubulars 1 10, 112 in a downhole direction. As the rotational speed of rotary drilling assemblies is normally limited between 100 and 200 rpm and the borehole diameter of the section drilled through the reservoir is generally but not always 8.5" (about 2 6 mm) or less, and the drilling rate of penetration generally below 100 ft. per minute (about 0.51 metres per second), then the skew angle required to provide efficient forward traction and transport system is relatively small, for example in the order of 0.5 degrees. However, in some circumstances it may be desirable to go higher.

In the embodiment shown, the machined pocket 120 does not extend into the throughbore 104 of the body 102 and so permanently defines an active configuration with the roller 124 contacting the inner borehole wall in use. However, in alternative embodiments the pocket 120 may be configured in a similar arrangement to that shown in Figures 1 and 2 which is capable of moving from a passive configuration to an active configuration.

Reference is now made to Figures 7 to 9a of which Figures 7 and 8 show isometric and plan views of a roller assembly 122 and Figure 9a shows an exploded view. As shown, the roller assembly 122 has two tapered latch locked retention blocks 128 at either end of the roller shaft 126. The blocks 128 are configured for location within a pocket, such as the pocket 120 provided in body 102.

To construct the assembly 122, the roller 124 is mounted on bearings, including one or more pressure-compensated radial bearings 130. Pressure-compensated lubricant is held within a pressure-compensated, modular, positive pressure reservoir 132 contained within the centre portion of one or both of the retention blocks 128.

Beneficially, the internal volume of the retention block or block 128 may provide the facility to contain substantially more lubricant than is currently provided in rolling element tools of equivalent size, thereby increasing the life of the radial bearings in operation.

The lubricant held within the positive pressured reservoirs 132 is fed into a drilled central bore 134 at either end of the bearing shaft and fed to the bearing by means of one or more cross-drilled hole 136 communicating between the drilled central bore 134 and lubrication grooves 138 machined on the external diameter of the shaft 126.

The lubricant is retained within the bearing section of the roller 124 by rotary seals located at either end of the roller 124 between the external diameter of the shaft 126 and the internal diameter of the roller 124.

The end thrust loads experienced by the roller 124 due to the traction forces may be supported by internal thrust bearings, for example contained within the pressure compensated area of the roller 124 and/or by mud lubricated thrust bearings situated at either end of the roller 124 outwith the sealed pressure compensated area between the roller 124 and the bearing faces on the retention blocks 128.

The retention blocks 128 are secured by means of cap screws 140 passing through cap screw holes 142 in the retention blocks 128 and into threaded holes 143 at the bottom of the pocket 120. A spring-loaded latch 144 is also installed on each retention block 128 to provide a secondary attachment means should the cap screws 140 fail. The spring-loaded latch 144 locks into a recess 145 in the pocket 120 and can only be released for disassembly by means of a release screw 146 inserted into a release screw hole 148. In this arrangement, the latch mechanism 144 is integral with the retention blocks 128. However, as an alternative to the construction shown and described above, and with reference to Figure 9b, the latch lock 11a may alternatively be a separate sprung loaded component mounted higher up on the tapered retention block 128 and held in place for assembly purposes by the release screw 146 passing through a retention hole 150 in the latch lock component.

It should be understood that the embodiment described herein is merely exemplary and that various modifications may be made thereto without departing from the scope of the invention. For example, the roller assembly 122 may be adapted for use in an apparatus such as the apparatus 10 shown in Figures 1 and 2. The retention blocks, latch lock, lubrication and bearing elements of the roller assembly 122 may alternatively be formed in or provided on a carrier such as the carrier 32.

In addition, at least one of the body, the upset diameter body portion/blade, or roller of any of the above described apparatus' may be provided or formed with a hard facing surface or material which may, for example be used to ream or grind the borehole.

Referring to Figure 10, as an alternative to the collet sleeve described above, the sleeve may alternatively comprise a ball retent sleeve 152. As shown in Figure 9, the sleeve 152 is adapted for location in the body 12 and comprises elastomeric seals 154 mounted in grooves 156 which in use straddle access port 158 through the body 12. As with the collet sleeve, an activation dart 160, which may be identical to the dart 50 described above, with rupture disk 162 and retainer ring 164 mounted thereon may be dropped or propelled through the drill string and seats in the sleeve 152. Applied pressure will shear the shear pin 166 and force the sleeve 152 downwards (to the left in the figure) to permit fluid access to the access port 158. The sleeve 152 comprises a number of circumferentially spaced balls which engage with a ball detent groove to prevent further movement of the sleeve 152.

Claims

1. An apparatus for use in drilling a high angle or horizontal borehole, the apparatus comprising:

a body for coupling to a drill string; and

a traction member mounted for rotation on the body, the apparatus having a first, passive, configuration and a second, active, configuration in which the traction member urges the apparatus along an inner wall of the borehole.

2. The apparatus of claim 1 , wherein the apparatus is configured to be urged along the inner wall of the borehole in a selected direction.

3. The apparatus of claim 1 or 2, wherein the apparatus is configured to be urged in a reverse direction.

4. The apparatus of any preceding claim, wherein the apparatus is configured to be urged in a forward direction.

5. The apparatus of any preceding claim, wherein the apparatus is configured to be urged along the inner wall of the borehole in response to rotation of the apparatus and/or the drill string.

6. The apparatus of any preceding claim, wherein the traction member is adapted for mounting on the body at a skew angle relative to a longitudinal axis of the body.

7. The apparatus of claim 6, wherein the direction of skew angle of the traction member is selected to urge the apparatus in the selected direction along the inner wall of the borehole.

8. The apparatus of claim 6 or 7, wherein the angle of the skew angle of the traction member is selected to urge the apparatus along the inner wall of the borehole at a selected rate.

9. The apparatus of any one of claims 6 to 8, wherein the skew angle is 1 degree or less.

10. The apparatus of any one of claims 6 to 9, wherein a reverse skew angle in the range of about 3 degrees to about 5 degrees is selected.

11. The apparatus of any one of claims 6 to 10, wherein the selected skew angle is set at surface.

12. The apparatus of any of claims 6 to 11 , wherein the apparatus is configured so that activation of the traction member from the passive configuration to the active configuration provides the skew angle.

13. The apparatus of any preceding claim, wherein the apparatus is configured so that the traction member is offset from the borehole wall in the passive configuration.

14. The apparatus of any one of claims 1 to 12, wherein the apparatus is configured so that the traction member contacts the borehole wall in both the passive and active configurations.

15. The apparatus of any preceding claim, wherein the apparatus further comprises an activation arrangement for moving the traction member from the passive

configuration to the active configuration.

16. The apparatus of claim 15, wherein the activation arrangement is configured to urge the traction member into contact with the borehole wall.

17. The apparatus of claim 15 or 16, wherein the activation arrangement urges the traction member further into contact with the borehole wall.

18. The apparatus of any of claims 15 to 17, wherein the activation arrangement is configured to selectively expose the traction member to a differential pressure.

19. The apparatus of claim 18, wherein the differential pressure comprises a difference between an internal pressure of the apparatus and an annulus pressure.

20. The apparatus of any of claims 15 to 19, wherein the activation arrangement comprises a sleeve adapted for location within a body throughbore.

21. The apparatus of claim 20, wherein the sleeve is configured for

axial/longitudinal movement relative the body to permit fluid access to urge the traction member from the passive configuration to the active configuration.

22. The apparatus of claim 21 , wherein urging the traction member from the passive configuration to the active configuration involves urging the traction member radially outwards to contact the borehole wall.

23. The apparatus of claim 21 or 22, wherein urging the traction member from the passive configuration to the active configuration comprises urging the traction member from a position in which the traction member is coaxial with the longitudinal axis of the body to a skewed position relative to the longitudinal axis.

24. The apparatus of any one of claims 20 to 23, wherein the sleeve comprises at least one of: a collet sleeve; and a ball retent sleeve.

25. The apparatus of any one of claims 20 to 24, wherein the activation

arrangement comprises a device for holding the sleeve within the body.

26. The apparatus of any one of claims 20 to 25, wherein, in use, the sleeve is released by sending a control element through the drill string to seat on the sleeve.

25. The apparatus of claim 26, wherein the activation activation arrangement comprises a rupture disk for coupling to the control element.

26. The apparatus of any preceding claim, wherein the traction member comprises a roller or journal.

27. The apparatus of claim 26, wherein the roller is adapted for rotation relative to the body on a roller bearing shaft.

28. The apparatus of any preceding claim, wherein the traction member is of sufficient diameter that the central longitudinal axis of the body lies within the diameter of the traction member.

29. The apparatus of any preceding claim, when dependent on claim 6, wherein the axis of the skewed traction member may lie within less than half its diameter from the central longitudinal axis of the body.

30. The apparatus of any preceding claim, wherein the apparatus comprises one traction member.

31. The apparatus of any preceding claim, wherein the apparatus comprises a plurality of traction members arranged around the body.

32. The apparatus of any preceding claim, wherein the body comprises a cylindrical mandrel.

33. The apparatus of any preceding claim, wherein the body comprises an upset diameter portion.

34. The apparatus of claim 33, wherein the upset diameter body portion defines or provides mounting for a stabiliser blade of the apparatus.

35. The apparatus of any preceding claim, wherein a recess or pocket is provided in the body.

36. The apparatus of claim 35, wherein the recess is adapted to receive the traction member.

37. The apparatus of any preceding claim, wherein the traction member is adapted for mounting in the body directly.

38. The apparatus of any one of claims 1 to 36, further comprising a carrier into which the traction member is rotatably mounted.

39. The apparatus of claim 38, further comprising a seal element between the carrier and the body.

40. The apparatus of claim 38 or 39, wherein the seal element is provided between the carrier and the body so as to permit movement of the carrier in a radial direction relative to the body.

41. The apparatus of claim 38, 39 or 40, wherein the seal element comprises at least one of a urethane rubber material, hydrogenated nitrile material or swelling elastomer material.

42. The apparatus of any preceding claim, wherein the traction member is secured by means of at least one tapered retention block.

43. The apparatus of claim 42, wherein the taper of the retention block is sufficient to secure the block to the body.

44. The apparatus of claim 42 or 43, wherein the retention block is secured by a latch lock.

45. The apparatus of claim 42, 43 or 44, wherein the retention block is secured in place by a fastener.

46. The apparatus of any preceding claim, wherein the traction member is provided with one or more pressure-compensated radial bearing.

47. The apparatus of any preceding claim, wherein lubricant is held within a reservoir in the retention block.

48. The apparatus of claim 47, wherein the reservoir comprises a pressure- compensated, modular, positive pressure reservoir contained within the centre portion of the retention block.

49. The apparatus of claim 47 or 48, wherein the lubricant is fed into a drilled central bore at either end of the bearing shaft.

50. The apparatus of claim 47, 48 or 49, wherein the lubricant is fed to the bearing by means of one or more cross-drilled hole.

51. The apparatus of any one of claims 47 to 50, wherein the lubricant is retained within the bearing by at least one rotary seal.

52. The apparatus of claim 51 , wherein the lubricant is retained within the bearing of the traction member by a number of rotary seals located at either end of the traction member.

53. The apparatus of any preceding claim, wherein the apparatus further comprises at least one further traction member.

54. The apparatus of claim 53, wherein the further traction member comprises a fixed traction member.

55. The apparatus of any preceding claim, wherein the apparatus forms or forms part of a downhole stabiliser.

56. The apparatus of any preceding claim, wherein the apparatus is configured for use in a cased hole or open hole borehole section.

57. A downhole assembly for use in a high angle or horizontal borehole, the assembly comprising a drill string and one or more apparatus according to any preceding claim.

58. The assembly of claim 57, further comprising a drilling assembly for drilling a borehole.

59. An apparatus for use in high angle or horizontal drilling applications, the apparatus comprising:

a body for coupling to a drill string; and

a traction member mounted for rotation on the body, the traction member mounted on the body by means of at least one latch locked retention block.

60. The apparatus of claim 59, wherein the latch locked retention block comprises a retention blocks according to any one of claims 42 to 56.