WO2016142534A2

WO2016142534A2 - Downhole tool and bottom hole assembly for running a string in a wellbore

Info

Publication number: WO2016142534A2
Application number: PCT/EP2016/055341
Authority: WO
Inventors: Malek BEN HAMIDA; Nicolas SLUYS; Abdelhakim Hahati; Benoît Deschamps
Original assignee: Tercel Oilfield Products Belgium Sa; Tercel Ip Limited
Priority date: 2015-03-11
Filing date: 2016-03-11
Publication date: 2016-09-15
Also published as: WO2016142534A3

Abstract

The invention relates to a downhole tool having a generally cylindrical body comprising a rear end adapted for connection to the bottom of a string or to a motor shaft, and terminated by a nose portion comprising the front end of the tool, the said body further comprising: - a passive area; - a front cutting area undergauge relative to the said passive area and arranged between the said passive area and the said front end.

Description

Downhole tool and bottom hole assembly for running a string in a welibore

Technical field

[0001 ] The present invention is related to a downhole tool having a generally cylindrical body comprising a rear end and a front end, the rear end being adapted for connection to the bottom of a string, preferably a casing string or to a motor shaft, the body being terminated by a nose portion comprising the front end of the tool, the said body further comprising: a passive area; a front cutting area undergauge relative to the said passive area and arranged between the said passive area and the said front end.

[0002] The present invention also relates to a bottom hole assembly comprising the said downhole tool and a motor for actuating said downhole tool.

State of the art

[0003] The construction of a welibore for oil and gas exploitation comprises steps of drilling welibore sections and stabilizing those welibore sections by installation and cementation of a casing string in the drilled welibore. The casing string is generally terminated by a casing shoe having a profile adapted to guide the casing string into the welibore and to overcome any ledges and obstruction in the borehole, provided that these ledges and obstructions are not too severe.

[0004] Some casing shoes are provided with cutting elements to help removal of asperities, to cut or displace obstacles encountered in the welibore. An example of a casing shoe provided with cutting elements is disclosed in US patent n° 6,062,326. This casing shoe comprises a generally cylindrical body having a first end adapted for connection to a casing string and having a second end including a generally rounded nose portion having a forward end. The casing shoe further comprises cutting means including cutting structures disposed along the sides of the generally cylindrical body and on the nose portion. The cutting structures comprise a plurality of raised flutes extending along a portion of the cylindrical body and converging towards the forward end of the nose portion. The shoe may comprise a stabilizing portion comprising a plurality of spiral flutes and arranged behind the cutting structure and separated from the cutting structure. The ratio of the length of the shoe relative to its diameter is superior to 6. The thickness of the blades is substantially equal to the diameter of the cutters. Such a tool is adapted to remove small ledges or small obstructions in the wellbore. It cannot be used for redrilling a long section of a wellbore wherein formation has collapsed.

[0005] Another example of a shoe is disclosed in document US patent n° 6,401 ,820. That shoe comprises an eccentric nose adapted to dislodge or push aside any small obstructions and further comprises a plurality of blades including a pilot reaming portion and a back reaming portion. The reaming portions are provided with an aggressive surface formed of blocks made of tungsten carbide welded to the body. The thickness of the reaming portion of the blades is small and is only adapted to remove small ledges in the wellbore. The tool is devoid of any cutting structure on the nose so that this tool is not adapted for redrilling a long section of a wellbore wherein formation has collapsed or wherein big obstructions are present.

[0006] The US patent n° 7,621 , 351 discloses a reaming tool for running on casing or liner, comprising a nose portion having a shallow cone profile including a central port for through which drilling fluid may be circulated. The tool further comprises a plurality of reaming blades extending from a certain distance of the nose portion. The nose portion is not adapted to drill or to push obstructions but its concave conical shape is provided for facilitating the drilling of the nose portion.

[0007] The US patent n° 8,657,036 discloses a tubing shoe comprising a cylindrical body comprising a plurality of cutting blades and a nose portion screwed on the body and provided with a plurality of nozzles. The plurality of blades comprise a surface having a radius of curvature and provided with cutting elements. Such kind of shoe is also adapted for removal of small ledges or for pushing small obstructions in the wellbore.

[0008] For some deviated wells, it may be preferred to run a casing or a liner in a wellbore without rotation of the casing or the liner. Alternatively, it can be preferred to run a casing or the liner in a wellbore with reduced torque to prevent damage on the casing or on the liner. In case of obstruction in the wellbore, for example in case of formation collapsing in the wellbore, the bottom portion of the casing string should be adapted to drill out or to remove any obstructions or irregularities without applying torque on the casing string or at least with a reduced torque.

[0009] In some applications, the casing string comprises a bottom hole assembly including a motor connected to a roller cone drill bit to help removing obstructions or wellbore irregularities. However, the roller cone may deviate from its trajectory and cause side track. There is also a need for a solution less expensive than a roller cone bit. Summary of the invention

[0010] According to a first aspect, the present invention is related to a downhole tool (1 ) having a generally cylindrical body (2) comprising a rear end (3) and a front end (4), the rear end (3) being adapted for connection to the bottom of a string or to a motor shaft, the body (2) being terminated by a nose portion (5) comprising the front end (4) of the tool, the said body (2) further comprising: a passive area (6); a front cutting area (7) undergauge relative to the said passive area (6) and arranged between the said passive area (6) and the said front end (4). [001 1 ] Preferably, the downhole tool further comprises rear cutting area (8) undergauge relative to the said passive area (6) and arranged between the said passive area (6) and the said rear end (3).

[0012] Preferably, the downhole tool comprises at least one blade (9) rising from the said generally cylindrical body (2) and having a surface (13) substantially parallel to the longitudinal axis (14) of the said cylindrical body and on which extends the said passive area (6).

[0013] Preferably, the said blade (9) comprises a front surface (15) on which extends the said front cutting area (7).

[0014] Preferably, the said blade (9) comprises a rear surface (16) on which extends the said rear cutting area (8). [0015] Preferably, the said front surface (15) of the blade (9) is inclined relative to the said surface (13) on which extends the passive area (6).

[0016] Preferably, the said rear surface (16) of the blade (9) is inclined relative to the said surface (13) on which extends the said passive area (6).

[0017] Preferably, the said front cutting area (7) extends on the said nose portion (5). [0018] Preferably, the said front cutting area (7) extends from the said front surface (15) of at least one of the said blades (9) to the said front end (4) of the tool.

[0019] Preferably, the said front cutting area (7) comprises cutting inserts (10) that are polycrystalline diamond compact cutters or tungsten carbide inserts or a combination thereof.

[0020] Preferably, the said passive area (6) comprises reaming inserts (12) that are dome shaped tungsten carbide inserts or dome truncated tungsten carbide inserts. [0021 ] Preferably, the said reaming inserts (12) have an outermost portion arranged at the same radial distance from the said longitudinal axis (14).

[0022] Preferably, the said nose portion (5) comprises a meplat (17) inclined relative to the said longitudinal axis (14) of the tool. [0023] Preferably, the said front end (4) is a unique point at a radial distance from the longitudinal axis (14) of the tool, the radial distance between the front end (4) and the longitudinal axis (14) of the tool being inferior to the radial distance between the outermost portion of the said passive area (6) and the longitudinal axis (14) of the tool.

[0024] Preferably, the said meplat (17) extends from the said front end (4) to a peripheral point (26) of the said nose portion (5).

[0025] Preferably, the said front cutting area (7) extends on at least a portion of the said meplat (17).

[0026] Preferably, the said body comprises a flute (25) formed between two blades, wherein said flute (25) comprises a nozzle (18, 19) directed towards the front lateral edge (23) of the blade which is the edge seen in the direction of rotation of the tool.

[0027] In a second aspect, the present invention is related to a bottom hole assembly comprising the said downhole tool (1 ) as described herein.

[0028] Preferably, the bottom hole assembly comprises a motor, preferably a single run motor.

[0029] In a third aspect, the present invention is related to a method for running a casing or a liner in a wellbore comprising a step of providing to the bottom end of the said casing string or liner a bottom hole assembly such as described herein.

Brief description of the drawings

[0030] The figure 1 represents a side elevation view of a downhole tool according to a first embodiment of the present invention.

[0031 ] The figure 2 represents a second side elevation view of a downhole tool according to the first embodiment of the present invention.

[0032] The figure 3 represents a first side elevation of a downhole tool according to a second embodiment of the present invention. [0033] The figure 4 represents a second side elevation of a downhole tool according to the second embodiment of the present invention. [0034] The figure 5 represents an schematic view of an embodiment of a bottom hole assembly according a a second aspect of the present invention.

Detailed description of the invention [0035] The figure 1 represents a side elevation view of a downhole tool 1 according to an embodiment of the present invention. The downhole tool 1 comprises a generally cylindrical body 2 having a rear end 3, and a front end 4. The downhole tool also comprises a nose portion 5 extending from the generally cylindrical body 2 to the front end 4. The generally cylindrical body further comprises: - a passive area 6; a front cutting area 7 undergauge relative to the said passive area 6 and arranged between the said passive area 6 and the front end 4; a rear cutting area 8 undergauge relative to the said passive area 6 and arranged between the said passive area 6 and the rear end 3. [0036] The downhole tool according to the present invention is designed in the aim to be a low cost bit that can be abandoned, and possibly drilled in the wellbore. The rear end 3 of the downhole tool is adapted for connection to the bottom of a string or to a shaft (not shown). The downhole tool of the present invention is preferably destined to be attached to a casing string or to a liner or to a motor shaft of a bottom hole assembly for reaming the wellbore, removing the ledges and opening the wellbore at any zone wherein formation may have collapsed or moved.

[0037] The downhole tool according to the embodiment of figure 1 comprises three blades 9 rising from the cylindrical body 2 and arranged symmetrically on the body relative to a longitudinal axis 14 of the downhole tool. The number of blades is not limitating for the present invention, however three blades is considered as an optimum for providing a low cost bit in the spirit of the present invention while keeping an efficient cutting structure for drilling formation, preferably ledges or doglegs or collapsed formation. Each of the blades 9 includes a passive area 6, a front cutting area 7 and a rear cutting area 8. The blades 9 may be spiralled or straight or may comprise a straight portion and a spiralled portion or two straight portions forming an angle with each other.

[0038] The passive area 6 is an area of the tool that is not intended to cut the formation. The passive area is shaped to stabilize the bit and to prevent side track. The substantially constant gauge of the passive area 6 allows directional stabilization of the tool. The passive area has a length preferably the shortest possible to reduce the cost material, but of at least 2,5 inches or 3 inches to prevent side track. The passive area 6 comprises a surface 13 substantially parallel to the longitudinal axis 14 of the downhole tool. The surface 13 of the passive area 6 may be reinforced by hard facing, or may be reinforced by providing inserts 12 made of hard materials such as for example tungsten carbide.

[0039] In a preferred embodiment of the invention, the passive area 6 is intended to ream the borehole to provide a smooth surface in the wellbore. Advantageously, the surface 13 of the passive area 6 is provided with reaming inserts 12 for reaming the borehole. The surface 13 of the passive area 6 can therefore also be called "reaming surface". The reaming inserts 12 also provide a dampening effect reducing vibration on the tool. Advantageously, the inserts are positioned symmetrically relative to the longitudinal axis 14 of the tool to provide a balancing effect. The inserts have an outermost portion that preferably protrude from the surface 13 of the passive area 6. The inserts may be dome shaped or preferably truncated dome shaped. The inserts are preferably made of tungsten carbide or any other resistant material known by the man skilled in the art. The radial distance between the outermost portion of each of the reaming inserts 12 and the longitudinal axis 14 of the tool is advantageously constant over the whole the passive area 6.

[0040] According to the embodiment of figure 1 , the reaming inserts 12 are disposed in rows on the reaming surface. As presented more in detail on figure 2, each blades 9 may comprise at least three rows A, B, C of reaming inserts 12, the rows A, B, C being inclined relative to the longitudinal axis 14. The reaming inserts 12 are arranged on the surface 13 of the passive area 6 in a number N of substantially parallel rows extending substantially parallel to a longitudinal axis of the reaming surface, the rows being laterally spaced from each other by a predetermined distance R, and wherein the shortest distance along said longitudinal axis 14 of the said body, between any two nearest inserts in two adjacent rows and between any two nearest inserts in two opposing outer rows is one and the same and has a predetermined value Y. Two adjacent inserts in the same row are spaced by a predetermined distance L and the shortest distance in the direction of the longitudinal axis of said body between two adjacent inserts in the same row can be determined as X = L cos3, wherein the distance Y is X/N and β is the angle between the longitudinal axis of the body, and the longitudinal axis of the reaming surface. Each row nearest to a lateral edge of the reaming surface is offset from the lateral edge by a predetermined distance E, wherein the ratio R/E has a predetermined value. In the embodiment of figure 1 and 2, a first row of reaming inserts comprises six reaming inserts, while two other rows comprise four reaming inserts. The number of reaming inserts is not a limitation of the present invention. Advantageously, the number and disposition of the inserts is chosen such as to reduce the cost of the bit and to keep a good quality of the borehole while reaming.

[0041 ] The front cutting area 7 comprises cutting elements 10 that are preferably polycrystalline diamond compact cutters (PDC cutters). Alternatively, other kind of cutting elements can be employed such as diamond impregnated blocs, tungsten carbide inserts, cubic boron nitride inserts or an abrasive layer of hard material such as a layer of crushed tungsten carbide. Each of these cutting elements described herein can be used in combination with one or more other type of cutting element. The front cutting area 7 is undergauge relative to the passive area 6, that means that all the outermost portions of the cutting elements 10 of the front cutting area are located at a radial distance from the longitudinal axis 14 of the tool that is less than the radial distance between the outermost portion of each of the reaming inserts 12 and the longitudinal axis 14 of the tool. The front cutting area 7 is not cutting formation until it encounters ledges, doglegs or collapsed formation.

[0042] The blades 9 have a front surface 15 tapering from the front end of the reaming surface 13 towards the nose portion 5. The front cutting area 7 extends along the front surface 15 of the blades 9. The front surface of the blade comprises a lateral edge 23 which is seen in the direction of rotation of the tool. This lateral edge 23 is provided with PDC cutters 10. In the embodiment of figure 1 , five PDC cutters are positioned along the lateral edge of the front surface of the blade and undergauge relative to the reaming inserts. The number of PDC cutters is not limitative for the present invention. On a lateral edge 23 of a first blade, the PDC cutters may be disposed side by side or with a space between each other, preferably inferior to their diameter, more preferably inferior to their radius, provided that on another blade, the cutters are arranged on a lateral edge with an axial offset position relative to the first blade, such that in a rotated profile of the tool relative to the longitudinal axis of the tool, the space between the outermost portion of two adjacent PDC cutters of a first blade is compensated by at least an outermost portion of another PDC cutter of another blade.

[0043] The rear cutting area 8 comprises cutting elements 1 1 , preferably polycrystalline diamond compact cutters (PDC cutters). Alternatively, other kind of cutting elements can be employed such as diamond impregnated blocs, tungsten carbide inserts, cubic boron nitride inserts or an abrasive layer of hard material such as a layer of crushed tungsten carbide. Each of these cutting element described herein can be used in combination with one or more other type of cutting element. The rear cutting area 8 is undergauge relative to the passive area 6, that means that all the outermost portions of the cutting elements 1 1 of the rear cutting area 8 are located at a radial distance from the longitudinal axis 14 of the tool that is less than the radial distance between the outermost portion of each of the reaming inserts 12 and the longitudinal axis 14 of the tool. The rear cutting area 8 is not cutting formation until the string comprising the tool on its bottom end is pulled from the surface of the wellbore and encounters ledges, doglegs or collapsed formation. The rear cutting area is located opposite to the front cutting area relative to the passive area. The rear cutting area 8 is intended for back reaming purpose. In case if the bottom of the string is stuck, for example when formation collapses on the string, the string is pulled under rotation for back reaming the formation and allowing to free the bottom section of the string. Then the string can be moved down again.

[0044] The blades 9 have a rear surface 16 tapering from the rear end of the reaming surface 13 towards the rear end 3. The rear cutting area 8 extends along the rear surface 16 of the blades 9. The rear surface of the blade comprises a lateral edge 24 which is seen in the direction of rotation of the tool. This lateral edge 24 is provided with PDC cutters 1 1 . In the embodiment of figure 1 , two PDC cutters are positioned along the lateral edge 24 of the rear surface 15 of the blade 9 and undergauge relative to the reaming inserts 12. The number of PDC cutters is not limitative for the present invention. On a lateral edge 24 of a first blade, the PDC cutters may be disposed side by side or with a space between each other, provided that on another blade, the cutters are arranged on a lateral edge with an axial offset position relative to the first blade, such that in a rotated profile of the tool relative to the longitudinal axis of the tool 14, the space between the outermost portion of two adjacent PDC cutters of a first blade is compensated by at least an outermost portion of another PDC cutter of another blade. For example, on a blade, each PDC cutter is separated from an adjacent cutter by a distance inferior to twice the diameter of a PDC cutter, more preferably inferior to the radius of a PDC cutter.

[0045] In the embodiment of the figure 1 , each of the blades have the same length and are disposed on the cylindrical body 2 symmetrically relative to the longitudinal axis 14 of the tool. [0046] The nose portion 5 is a substantially conical portion including the front end 4 of the tool. The front end 4 may be coaxial with the longitudinal axis to prevent vibrations. In a preferred embodiment, the front end 4 is eccentric such that the tool is more adapted to pass the irregularities of the wellbore.

[0047] In a preferred embodiment of the invention, the nose portion 5 comprises a meplat 17 which is a substantially flattened surface passing by the longitudinal axis 14 of the tool, inclined relative to the said longitudinal axis 14 and comprising the front end 4 of the tool. The inclination of the meplat 17 is optimized to reduce the cost material while keeping a certain angle a for facilitating the penetration of the tool into tight areas of the wellbore. As presented in figure 2, the front of the meplat, (i.e. the front end 4 of the downhole tool) is eccentric and the meplat 17 forms an angle a of at least 45°, preferably more than 60° and less than 90° with the longitudinal axis 14 of the tool. In the embodiment such as presented in figure 1 , and 2, a first blade 9a extends from the rear side 26 of the meplat (which is a peripheral point of the nose portion) towards the rear end 3 of the body. A second blade 9b and the third blade 9c, extends from the same axial distance than the rear side 26 of the meplat towards the rear end 3 of the body 2.

[0048] Alternatively, the second blade 9b and/or the third blade 9c may extend from the rear end 3 of the body, towards a position intermediate between the axial position of the front end 4 of the tool and a position on the body. For example, the second blade 9b and/or the third blade 9c may extend from the rear end of the tool towards an intermediate axial position between the front end of the tool 4 and the rear end 26 of the meplat.

[0049] In the embodiment of figure 1 , the meplat 17 is cambered and comprises a chamfer 21 at the circumference of the meplat 17. Three nozzles 20 are provided on the chamfer.

[0050] Alternatively, the meplat 17 can be flat with or without chamfer, with or without nozzles.

[0051 ] The downhole tool comprises a plurality of nozzles for cleaning the wellbore and the tool itself. In the embodiment of the figure 1 , a first set of nozzle 20 is arranged on the chamfer, a second set of nozzles 18 directed towards the front end 4 of the tool is arranged on the flutes 25 formed between the blades 9, and a third set of nozzles 19 directed towards the rear end 3 of the tool is arranged on the flutes 25 formed between the blades 9 at an axial position intermediate between the second set of nozzles 18 and the rear end 3 of the tool. Alternatively, the second set of nozzles 18 and the third set of nozzles 19 can be positioned at the same axial distance, or the second set of nozzle 18 can be positioned at a distance intermediate between the third set of nozzles 19 and the rear end 3 of the tool. Alternatively, only a first set of nozzles 20 directed towards the front end 4 of the tool is provided on the chamfer 21 and another set of nozzles 19 is arranged on the flutes and directed towards the rear end 3 of the tool and towards the lateral edges 23 of the blades 9. Any other alternative for the positioning of the nozzles can be envisaged by the man skilled in the art.

[0052] As well known in the art, a PDC cutter comprises a cutting layer bound to a generally cylindrical support having a longitudinal axis. In an embodiment of the invention, the PDC cutters 10 of the front cutting area 7 may be arranged on the blades 9 such that the longitudinal axis of the PDC cutters are oriented at an intermediate angle between the longitudinal axis 14 of the tool and a plane orthogonal to the longitudinal axis of the tool and such that the cutting layer is oriented in a direction towards the front end of the tool. The PDC cutters 1 1 of the rear cutting area 8 may be arranged on the blades such that the longitudinal axis of the PDC cutters are oriented at an intermediate angle between the longitudinal axis 14 of the tool and a plane orthogonal to the longitudinal axis of the tool, and such that the cutting layer is oriented towards the rear end of the tool. All the PDC cutters or some PDC cutters can be substituted by tungsten carbide inserts, for example truncated dome shaped tungsten carbide inserts or any other cutting element.

[0053] The tool body is preferably made of steel. Preferably, the tool is manufactured by casting steel into a mold adapted to form a generally cylindrical body provided with blades including pockets for insertion of the reaming inserts and cutting inserts. The cutting inserts and reaming inserts are preferably brazed into the pockets. Alternatively, the cutting inserts and the reaming inserts are pressed fit into the pockets after a step of heating of the pockets. The nose portion 5 and the chamfer 21 of the meplat 17 may be machined after molding, preferably machined by turning.

[0054] The figure 3 and 4 present another embodiment of a downhole tool according to the present invention, that comprises three blades 9 rising from a cylindrical body 2 and arranged on the body 2 relative to the longitudinal axis 14 of the downhole tool. As previously, the number of blades 9 is not limitating for the present invention, however three blades is considered as an optimum for providing a low cost bit in the spirit of the present invention while keeping an efficient cutting structure for drilling formation, preferably ledges or doglegs or collapsed formation. Each of the blades 9 includes a passive area 6, a front cutting area 7 and a rear cutting area 8.

[0055] As presented in the embodiments of figure 1 and 2, the passive area 7 comprises reaming inserts 12, preferably dome truncated reaming inserts preferably made of tungsten carbide. The layout of the reaming inserts 12 can be substantially the same as described for the embodiments of figure 1 and 2, with more or less inserts. In this embodiment, each row of reaming inserts 12 comprises three reaming inserts. The number of reaming inserts is not limitating for the present invention. However, as any of the embodiment of the present invention, the layout of the reaming inserts is chosen such as to provide a low cost tool that allows a good stabilization, a good quality of borehole reaming.

[0056] In the embodiment presented in the figures 3 and 4, the front cutting area 7 extends along the front surface 15 of the blades, and is allowed to extend towards the front end 4 of the tool and at least partially on the meplat 17. As presented before, the front surfaces 15 of the blades 9 are inclined relative to the reaming surfaces 13. The front surfaces 15 of the blades 9 are tapered and extends from the front end of the reaming surface 13 towards the cylindrical body 2. The front cutting area 7 extends along the front surface 15 of the blades 9. The front surface 15 of the blades 9 comprise a lateral edge 23 which is seen in the direction of rotation of the tool. This lateral edge 23 is provided with PDC cutters 10. As shown in figures 3 and 4, three PDC cutters 10 are positioned spaced from each other along the lateral edge 23 of the front surface of the blades and undergauge relative to the reaming inserts. The number of PDC cutters is not limitative for the present invention. The front surface 15 of each blade 9 comprises PDC cutters disposed side by side or with a space between each other, provided that on another blade the cutters are arranged on a lateral edge with an axial offset position relative to the first blade, such that in a rotated profile of the tool relative to the longitudinal axis of the tool, the space between the outermost portion of two adjacent PDC cutters of a first blade is compensated by at least an outermost portion of another PDC cutter of another blade. For example, on a blade, each PDC cutter is separated from an adjacent cutter by a distance inferior to twice the diameter of a PDC cutter, more preferably inferior to the radius of a PDC cutter.

[0057] The nose portion 5 comprises a meplat 17 passing by the longitudinal axis 14 of the tool and inclined relative to the said longitudinal axis 14. The inclination of the meplat 17 is optimized to reduce the cost material while keeping a certain angle for facilitating the penetration of the tool into tight areas of the wellbore. As previously presented in figure 2, the top 4 of the meplat 17 (i.e. the front end of the downhole tool) is eccentric and forms an angle a with the longitudinal axis of the tool of at least 45°, preferably more than 60° and less than 90°. A first blade 9a extends from the vicinity of the front end 4 of the tool towards the rear end 3 of the body. A second blade 9b and the third blade 9c, extends from the periphery of the meplat 17 towards the rear end 3 of the body 2. [0058] As shown in figure 4, the front surface 15 of each of the second blade 9b and third blade 9c further comprises three truncated dome shaped tungsten carbide inserts 27 arranged at the vicinity to the circumference of the meplat 17.

[0059] As shown in figure 3, the front surface 15 of the first blade 9a comprises three rows of truncated dome shaped tungsten carbide inserts 28 extending until the front end 4. The number of rows of tungsten carbide inserts 28 is not limitative for the present invention. In that embodiment, the front cutting area 7 extends from the front surface 15 of the first blade 9a towards the front end 4 of the tool, and further extends to an upper surface of the meplat 17. Advantageously, the upper surface of the meplat 17 also includes truncated dome shaped tungsten carbide inserts 31 , or alternatively other cutting elements, extending along a zone comprised between the front end 4 and the centre of the meplat 17. A nozzle 29 for projecting a drilling fluid is arranged at the centre or close to the centre of the meplat 17.

[0060] The cylindrical body 2 further comprises a set of nozzles 19 arranged in the flutes 25 formed between each of the blades 9. The nozzles are directed towards the rear end 3 of the tool and towards the lateral edge 23 of the blades which is the front edge seen in the direction of rotation of the tool. [0061 ] Each of the blades 9 also comprises a rear surface 16 on which extends the rear cutting area 8. The rear surfaces 16 of the blades are inclined relative to the reaming surfaces 12. The rear surfaces 16 of the blades 9 are tapered and extends from the rear end of the reaming surface 13 towards the rear end 3 of the tool. The rear cutting area 8 extends along the rear surfaces 16 of the blades. The rear surface 16 of the blades 9 comprise a plurality of truncated dome shaped tungsten carbide inserts 30. The tungsten carbide inserts 30 are advantageously distributed axially and radially spaced from each other along the rear surface such that in a rotated profile of the tool relative to the longitudinal axis of the tool, the space between the tops of two adjacent inserts of a same blade is compensated by at least the top of an insert of another blade. Alternatively as previously presented for the embodiment of figure 1 and 2, the rear surface 16 of the blades may comprise PDC cutters disposed at the lateral edge 24 of the blade seen in the direction of rotation of the tool.

[0062] In a second aspect, the present invention relates to a bottom hole assembly comprising the said downhole tool as disclosed in any of the embodiment herein and further comprising a motor. The motor comprises a shaft on which is attached the downhole tool according to the description herein above.

[0063] Preferably, the said motor is a single run motor.

[0064] An embodiment of a bottom hole assembly 100 is presented in Fig. 5. The bottom hole assembly 100 comprises a downhole tool 1 as presented above, which is fixed on the motor shaft 103 of a downhole motor 101. The downhole single run motor comprises a housing 102 including a stator having a plurality of lobes and a rotor connected to the motor shaft, the rotor having a helicoidal portion comprising a plurality of lobes, preferably less lobes than the stator. The flow of fluid passing through the stator and the rotor provides power for rotation of the rotor which rotates eccentrically. Preferably, the rotor is connected to the motor shaft 103 through a universal joint that converts eccentric rotation of rotor into concentric rotation, which concentric rotation is input into the motor shaft 103 and the downhole tool 1 (i.e. a bit). Preferably, a flow diverter is arranged on the motor shaft close to the universal joint and upwards rotary seals arranged between the housing 102 and the motor shaft, to bypass the fluid from the inner bore of the housing to an inner bore of the motor shaft. A portion of the motor shaft 103 inside the housing 102 is journaled by bearings. Preferably the motor shaft 103 crosses the bottom end of the housing 102 and small portion of the shaft is outside of the housing.

[0065] Preferably, the upper end of the housing 102 of the motor is connected a sub 104 comprising a rupture disk valve. The rupture disk valve can be designed to break upon a certain hydraulic pressure. Preferably the rupture disk valve may break upon increase of flow for cleaning the well before cementation, or upon passage of cement through the sub. The rupture disk sub may be connected to flow valve sub comprising a flow valve to avoid fluid or cement to flow back in the string. Preferably, the rupture disk sub further comprises a flow valve arranged upwards to the said rupture disk valve. Flow valves and rupture disk sub are devices well known in the art.

[0066] The present invention relates also to a method of running a casing string or a liner in a wellbore wherein the bottom of the casing string or the liner comprises a downhole tool according to the present disclosure. The downhole tool may be rotated with the rotation of the casing string or liner or with the rotation of the shaft of a motor included at the bottom of the string. The motor is preferably a single run motor. As the downhole tool and the single run motor are designed to be relatively low cost, they can be abandoned in the wellbore. While running the string into the wellbore, the downhole tool can remove ledges in the borehole, enlarge tights spots or re-open the hole in case of collapsing formation. In case of the bottom of the string is stuck, for example because of formation collapsing on the string, the string can be pulled while rotating the downhole tool for back reaming the wellbore and free the string. Then the string is pushed down to reach the total depth of the wellbore. Once the string has reached the total depth of the wellbore, a further step of cementation of the string can be applied.

Claims

Downhole tool (1 ) having a generally cylindrical body (2) comprising a rear end (3) adapted for connection to the bottom of a string or to a motor shaft, and terminated by a nose portion (5) comprising the front end (4) of the tool, the said body (2) further comprising: a passive area (6); a front cutting area (7) undergauge relative to the said passive area (6) and arranged between the said passive area (6) and the said front end (4).

Downhole tool according to claim 1 comprising a rear cutting area (8) undergauge relative to the said passive area (6) and arranged between the said passive area (6) and the said rear end (3).

Downhole tool according to claim 1 or 2 comprising at least one blade (9) rising from the said generally cylindrical body (2) and having a surface (13) substantially parallel to the longitudinal axis (14) of the said cylindrical body and on which extends the said passive area (6).

Downhole tool according to claim 3 wherein the said blade (9) comprises a front surface (15) on which extends the said front cutting area (7).

Downhole tool according to claim 3 or 4 wherein the said blade (9) comprises a rear surface (16) on which extends the said rear cutting area (8).

Downhole tool according to claim 4 or 5 wherein the said front surface (15) of the blade (9) is inclined relative to the said surface (13) on which extends the passive area (6).

7. Downhole tool according to claims 5 or 6, wherein the said rear surface (16) of the blade (9) is inclined relative to the said surface (13) on which extends the said passive area (6).

8. Downhole tool according to any one of the preceding claims wherein the said front cutting area (7) extends on the said nose portion (5).

9. Downhole tool according to any one of the preceding claims wherein the said front cutting area (7) extends from the said front surface (15) of at least one of the said blades (9) to the said front end (4) of the tool.

10. Downhole tool according to any one of the preceding claims wherein the said front cutting area (7) comprises cutting inserts (10) that are polycrystalline diamond compact cutters or tungsten carbide inserts or a combination thereof.

1 1 . Downhole tool according to any one of the preceding claims wherein the said passive area (6) comprises reaming inserts (12) that are dome shaped tungsten carbide inserts or dome truncated tungsten carbide inserts.

12. Downhole tool according to claim 1 1 wherein the said reaming inserts (12) have an outermost portion arranged at the same radial distance from the said longitudinal axis (14).

13. Downhole tool according to anyone of the preceding claims wherein the said nose portion (5) comprises a meplat (17) inclined relative to the said longitudinal axis (14) of the tool.

14. Downhole tool according to any one of the preceding claims wherein the said front end (4) is a unique point at a radial distance from the longitudinal axis (14) of the tool, the radial distance between the front end (4) and the longitudinal axis (14) of the tool being inferior to the radial distance between the outermost portion of the said passive area (6) and the longitudinal axis (14) of the tool.

15. Downhole tool according to any one of the preceding claims, wherein the said meplat (17) extends from the said front end (4) to a peripheral point (26) of the said nose portion (5).

16. Downhole tool according to any one of the claims 13 to 15 wherein the said front cutting area (7) extends on at least a portion of the said meplat (17).

17. Downhole tool according to any one of the preceding claims wherein the said body comprises a flute (25) formed between two blades, wherein said flute (25) comprises a nozzle (18, 19) directed towards the front lateral edge (23) of the blade which is the edge seen in the direction of rotation of the tool.

18. Bottom hole assembly comprising the said downhole tool (1 ) according to any one of the claims 1 to 17.

19. Bottom hole assembly according to claim 18 further comprising a single run motor.

20. Method for running a casing or a liner in a wellbore comprising a step of providing to the bottom end of the said casing string or liner a bottom hole assembly according to the claims 18 or 19.