GB2468606A

GB2468606A - Swellable downhole centraliser

Info

Publication number: GB2468606A
Application number: GB1007937A
Authority: GB
Inventors: Brian Nutley; Kim Nutley
Original assignee: Swelltec Ltd
Current assignee: Swelltec Ltd
Priority date: 2006-11-21
Filing date: 2007-05-31
Publication date: 2010-09-15
Anticipated expiration: 2027-05-31
Also published as: GB0710384D0; GB0907455D0; US7896085B2; GB0814298D0; GB2456944A; GB2468606B; US8752638B2; GB2447996A; NO20092009L; EP2402547A1; GB201007937D0; EP2402548A1; US20130213672A1; US8794339B2; GB2447996A9; NO340362B1; US8408316B2; US20090272541A1; GB2444060A; US20090272525A1

Abstract

A centralises 120 for a downhole tubular 124 comprises a body 122 and a plurality of formations 126 upstanding from the body. The body comprises a swellable material selected to expand on exposure to hydrocarbon fluid. The formations may be swellable and arranged to create turbulent flow for fluid passing the apparatus, maybe blades and may be helically oriented on the body.

Description

1 Downhole apparatus and method 3 The present invention relates to downhole apparatus for 4 use in hydrocarbon wellbores. In its various aspects, the invention relates to a downhole apparatus and a 6 method of use, and a kit of parts for forming a downhole 7 apparatus. In particular, the invention relates to an 8 apparatus for use in applications to the centralisation 9 of downhole tubulars and components.

11 Centralisers perform important functions in downhole 12 environments. Centralisers may, for example, ensure that 13 a tubular does not come into contact with a wellbore 14 surface. This provides protection for the tubular against wear due to friction or impact with the bore hole 16 during run-in. Centralisers also have an important 17 function in cementing applications. A poorly centralised 18 tubular can lead to a poor fluid sweep of drill cuttings 19 prior to cementing, and the failure to form a cement bond around the entire circumference of the annular space 21 between the tubu]ar and the weilbore. This resu]ts in 22 poor isolation of well fluids, which can ultimately lead 1 to uncontrollable flow of well fluids to the surface or 2 to subterranean geological formations.

4 Centralisers are provided with blades or other formations to assist with creating a turbulent flow of mud and 6 cement. However, micro-channels may still be formed 7 between the cement and the bore wall and/ or between the 8 outer surface of the centraliser blades and the bore 9 wall.

11 A well packer provides a seal in an annulus formed 12 between an exterior surface of a tubular and an interior 13 surface of well casing or a wellbore. Known forms of 14 well packers are introduced in an unexpanded condition to the downhole environment in which they are to be used and 16 expanded in-situ to provide the desired seal. In one 17 form, the well packer expands upon coming into contact 18 with a well fluid. In another form, the well packer 19 comprises movable parts that are actuated in-situ to form the seal.

22 The integrity of the annular seal created by a well 23 packer is paramount. It is advantageous for the tubular 24 on which the packer is located to be centrally located in the bore, such that when the packer is expanded it exerts 26 a force against the bore that is substantially uniformly 27 distributed around the circumference. If the tubular is 28 positioned to one side of the bore, which is typically 29 true for an inclined bore, the expansion force of the packer will have to act against the side load weight of 31 the tubular to move to its expanded condition. If the 32 expansion force is insufficient to overcome the sideload 33 weight, the packer may seal asymmetrically in the bore, 1 with the packer having a radially short side (on the low 2 side of the bore) and a radially longer side (on the high 3 side of the bore) . This results in a potential failure 4 mode between the packer and the bore wall on the high side of the bore.

7 It is amongst the aims of an aspect of the invention to 8 provide an apparatus and method which overcomes or 9 mitigates one or more of the deficiencies or drawbacks of

the prior art.

12 It is an aim of an aspect of the invention to provide an 13 improved centraliser for use in a variety of downhole 14 applications.

16 It is an aim of an aspect of the invention to provide an 17 apparatus offering improved centralisation for well 18 packers.

Additional aims and objects of the invention will become

21 apparent from the following description.

23 According to a first aspect of the present invention, 24 there is provided downhole apparatus configured to be disposed on a tubular in a downhole environment, the 26 downhole apparatus comprising: a swellable member which 27 expands upon contact with at least one predetermined 28 fluid; and a rigid assembly, the downhole apparatus 29 having a first condition before expansion of the swellable member, in which the rigid assembly defines a 31 maximum outer diameter of the downhole apparatus, and a 32 second condition after expansion of the swellable member, 1 in which the swellable member defines a maximum outer 2 diameter of the downhole apparatus.

4 The rigid assembly functions to provide support and protection to the swellable member. The rigid assembly 6 functions to support and protect the swellable member, 7 and is relatively rigid with respect to the swellable 8 member. However, the rigid assembly may be designed to 9 flex or deform under an axial or radial load.

11 When the downhole assembly is in use downhole in the 12 first condition the rigid assembly can provide stand-off 13 protection for the swellable member. That is, the 14 swellable member is supported by the rigid assembly away from the borehole wall or lined borehole.

17 The maximum outer diameter defined by the rigid assembly 18 may be selected to be not less than the drift diameter of 19 a borehole in which the apparatus is located. The maximum outer diameter defined by the rigid assembly may 21 be selected to be gauge with a borehole in which the 22 apparatus is located. Alternatively, the maximum outer 23 diameter defined by the rigid assembly may be selected to 24 be greater than the borehole diameter. In this scenario, maximum outer diameter defined by the rigid assembly may 26 be slightly larger than the borehole diameter such that 27 the apparatus may still be run in the borehole, with a 28 radial force from the borehole wall acting to exert a 29 compressive radial force on the apparatus.

31 The swellable member may be expanded to a maximum outer 32 diameter greater than or equal to the maximum outer 33 diameter defined by the rigid assembly. When the 1 downhole assembly is in the second condition, the 2 swellable member is expanded to, for example, provide 3 isolation.

The downhole apparatus may be configured such that a part 6 of the rigid assembly is surrounded by the swellable 7 member. The rigid assembly may comprise at least one 8 collar surrounded by the swellable member. More 9 specifically, the at least one collar may be proximal to a bore defined by the swellable member and extending 11 through the downhole apparatus.

13 Alternatively or in addition, rigid assembly may comprise 14 two collars spaced apart from each other in a longitudinal direction of the downhole apparatus.

17 Alternatively or in addition, the rigid assembly may 18 comprise a plurality of spaced apart fingers. More 19 specifically, each of the plurality of spaced apart fingers may extend in a longitudinal direction.

21 Alternatively or in addition, the fingers may be spaced 22 apart radially around the downhole apparatus.

24 Alternatively or in addition, the plurality of fingers may be attached to a collar towards each opposing end of 26 the downhole apparatus.

28 Alternatively or in addition, the at least one collar and 29 the plurality of fingers may be integrally formed with each other.

1 The rigid assembly may resemble a bow spring centraliser.

2 Accordingly, the rigid assembly may be designed to flex 3 or deform under an axial or radial load.

In an alternative embodiment, the rigid assembly may 6 comprise a rigid member extending radially from the 7 apparatus in its first condition. The rigid assembly may 8 comprise one or more members or blocks located in the 9 apparatus. The members or blocks may be embedded into or partially encapsulated by the swellable member.

12 Alternatively or in addition, the rigid assembly may be 13 formed at least in part of at least one of: a metal, a 14 composite, a plastic, and the like.

16 The apparatus may further comprise a support structure 17 adapted to act against axial and/or shear forces 18 experienced by the apparatus. More preferably, the 19 support structure is adapted to reduce extrusion of the radially expanding member due to axial and/or shear 21 forces. The support structure may be adapted to be 22 further deployed by axial and/or shear forces experienced 23 by the apparatus.

The support structure may comprise an attachment means 26 for coupling to the apparatus and a support portion, 27 wherein the support structure has a first unexpanded 28 condition and a second expanded condition, and is adapted 29 to be deployed to its second expanded condition by expansion of the swellable member.

1 The support structure may be configured to abut against a 2 surface of the swellable member before and during 3 expansion of the swellable member.

The support structure may be configured to abut against a 6 portion of the surface of the radially expanding member.

7 Preferably, the support structure is arranged to at least 8 partially surround an end of the radially expanding 9 member. The support structure may substantially cover an end of the radially expanding member.

12 The support structure may extend along a part of a length 13 of the radially expanding member.

Alternatively or in addition, the support structure may 16 comprise a plurality of rigid support members that are 17 configured for movement in relation to each other to 18 accommodate expansion of the radially expanding member.

The apparatus may be adapted to rotate on a tubular in a 21 downhole environment.

23 The swellable member may define at least one 24 irregularity. More specifically, the at least one irregularity may comprise at least one of: a groove, a 26 ridge, an indentation, a protuberance, a roughened area 27 and an aperture to a bore, which extend into the 28 swellable member.

Alternatively or in addition, the at least one 31 irregularity may extend substantially longitudinally 32 a]ong the swellab]e member. For examp]e, where the 1 irregularity is a channel the channel may extend 2 longitudinally along the swellable member.

4 The irregularity may be arranged to define a flow path for fluid passing the apparatus. The irregularity may be 6 arranged to induce or create a turbulent flow. The 7 irregularity may be arranged to create a turbulent flow 8 in drilling fluid or mud flowing past the apparatus, or 9 may be arranged to create a turbulent flow in cement flowing past the apparatus.

12 The swellable member may have a first mating profile 13 towards a first end, and the apparatus may further 14 comprise a connector having a mating profile configured to mate with the first mating profile of the swellable 16 member. The swellable member may comprise a second 17 mating profile towards a second, opposing end. The 18 second mating profile may be identical to the first. The 19 connector may be connectable to either of the first and second ends of the swellable member.

22 The connector may be adapted to permit rotation of the 23 apparatus on a tubular. The connector may comprise a 24 mating portion, which may be adapted to rotate on a tubular. The connector may further comprise a retaining 26 portion, adapted to prevent or limit axial movement of 27 the apparatus and/ or the connector on a tubular. The 28 mating portion and/ or the retaining portion may comprise 29 a bearing surface.

31 Alternatively or in addition, the apparatus may be 32 attached to the tubular, e.g. by means of an adhesive or 33 bonding agent.

2 The apparatus may be any expanding apparatus. In one 3 embodiment, the apparatus is a centraliser, and may be a 4 casing centraliser. In a further embodiment the apparatus is a weilbore packer.

7 According to a second aspect of the invention there is 8 provided a kit of parts which, when assembled together 9 forms a downhole assembly, the kit of parts comprising the apparatus of the first aspect and a connector.

12 The connector may be that defined with reference to the 13 first aspect of the invention.

According to a third aspect of the invention there is 16 provided a centraliser for a downhole tubular, the 17 centraliser comprising a body and a plurality of 18 irregularities or formations upstanding from the body, 19 wherein the centraliser comprises a swellable material selected to expand on exposure to at least one 21 predetermined fluid.

23 Preferably, the swellable material is selected to expand 24 on exposure to a hydrocarbon fluid. The centraliser therefore is capable of sealing micro-channels in the 26 annular space, preventing the further flow of 27 hydrocarbons.

29 The formations may be arranged to define a flow path for fluid passing the apparatus. The formations may be 31 arranged to induce or create a turbulent flow. The 32 irregu]arity may be arranged to create a turbu]ent flow 33 in drilling fluid or mud flowing past the apparatus, or 1 may be arranged to create a turbulent flow in cement 2 flowing past the apparatus.

4 The irregularity or formation may be arranged to define a flow path for fluid passing the apparatus. The 6 irregularity may be arranged to induce or create a 7 turbulent flow. The irregularity may be arranged to 8 create a turbulent flow in drilling fluid or mud flowing 9 past the apparatus, or may be arranged to create a turbulent flow in cement flowing past the apparatus.

12 Preferably, the formations are blades. More preferably, 13 the blades are helically oriented on the body.

The blades may comprise a swellable material selected to 16 expand on exposure to a hydrocarbon fluid.

18 Further embodiments of the second and third aspects of 19 the present invention may comprise one or more features according to any preceding aspect of the present 21 invention.

23 Further features and advantages of the present invention 24 will become apparent from the following specific description, which is given by way of example only and 26 with reference to the accompanying drawings, in which: 28 Figure 1A is a perspective, partially cut away view 29 of a downhole apparatus in accordance with a first embodiment of the invention; 32 Figure lB is a perspective, outer view of the 33 downhole apparatus of Figure 1A; 2 Figure 1C is an alternative perspective, partially 3 cut-away view of the downhole apparatus of Figure 4 1A; 6 Figure 2 is a perspective view of a rigid assembly 7 forming part the downhole apparatus of Figure 1; 9 Figure 3 is a perspective, partially cut-away view of the downhole apparatus of Figures 1 and 2 in an 11 expanded condition; 13 Figure 4A is a perspective view of an end connector 14 assembly which may be used with the invention; 16 Figure 4B is a longitudinal section through the end 17 connector assembly of Figure 4B; 19 Figure 5 is a perspective view of an alternative connector which may be used with the apparatus of 21 Figures 1A to 1C; 23 Figures 6A and 6B are respectively perspective and 24 part-sectional views of a support structure which may be used with the apparatus of Figures 1A to 1C 26 in accordance with an embodiment of the invention; 28 Figures 7A, 718, and 7C are respectively perspective, 29 part-sectional, and end views of the support structure of Figures 6A, and 6B in an expanded 31 condition; 1 Figure 8 is a perspective view of an apparatus and 2 support structure in accordance with an embodiment 3 of the invention; Figures 9A to 9C are details of longitudinal 6 sections through assembly of Figure 8 in 7 respectively unexpanded, expanded and fully expended 8 conditions; Figures 10 and 11 are perspective views of an 11 alternative support structure in unexpanded and 12 expanded conditions respectively; and 14 Figure 12 is a perspective view of a centraliser in accordance with a further embodiment of the 16 invention.

18 Referring firstly to Figures 1 and 2, there is shown 19 generally at 10 a downhole apparatus in accordance with a first embodiment of the present invention. The apparatus 21 comprises a swellable member 12 and a rigid assembly 14.

22 The apparatus 10 comprises a throughbore 11 which is 23 sized such that the apparatus can be slipped onto a 24 tubular on which it is being used. The downhole apparatus is rotatably mounted on the tubular in this 26 embodiment.

28 The rigid assembly 14, shown in isolation in Figure 2, 29 has three parts: a first collar 16, a plurality of spaced apart fingers 18 and a second collar 20. The first 31 collar 16 and second collar 20 are located within the 32 body of the swellable member 12. The first collar 16 and 33 second collar 20 are located towards opposing ends of the 1 swellable member 12 and are joined by the plurality of 2 spaced apart fingers 18. The fingers 18 are spaced apart 3 around the circumference of the swellable member 12.

4 Note that the second collar 20 is not shown in Figure 1, because Figure 1 shows the swellable member cut away in 6 the vicinity of the first collar 16 but not cut away in 7 the vicinity of the second collar 20.

9 Each of the fingers 18 comprises an outer portion 22 which defines the outer diameter of the assembly 14 and 11 the outer diameter of the apparatus in the configuration 12 shown most clearly in Figure lB. The fingers 18 follow a 13 path such that the outer portion 22 defines the maximum 14 outer diameter of the assembly at the mid-point of the fingers 18. Two transitional portions 24 join the outer 16 portions 22 to the collars 16, 20. In this embodiment, 17 the outer portion 22 defines a part-cylindrical surface 18 concentric with the collars, but in other embodiments the 19 fingers may define a smooth arcuate path and the outer portion may be curved in the axial direction.

22 The two collars and the plurality of fingers are 23 integrally formed with one another of a suitable rigid 24 material, such as a metal. The rigid assembly is similar in form and function to a bow spring centraliser, and is 26 designed such that the spaced apart fingers 18 of the 27 rigid assembly 14 can resiliently flex when exposed to 28 radial and/ or axial loads. For example, when a radial 29 load is experienced by the outer portion 22, the outer diameter defined by the rigid assembly 184 reduces, and 31 the axial length of the rigid assembly increases 32 correspondingly. This assists with shock resistance and 33 negotiation of obstacles in the bore during run in.

2 Each end of the swellable member defines a recess 19 3 having ridges to allow for push fit connection with a 4 connector (not shown) to enable the apparatus to be used as part of a modular system or kit of parts. This will 6 be described in more detail below.

8 As shown most clearly in Figure 1C, the swellable member 9 is formed around the rigid assembly such that the majority of the rigid assembly is encased by the 11 swellable member. The swellable member is therefore 12 disposed between the rigid assembly and the bore in which 13 the apparatus is located. The swellable member is also 14 formed on the interior of the rigid assembly, such that it is disposed between the rigid assembly and a tubular 16 on which the apparatus is located. Radially inward of 17 the collars 16, 20 are located cylindrical portions 26 of 18 the swellable material which lie between the collars and 19 the tubular in use. Radially inward of the fingers 18 is a portion of the swellable member which is profiled to 21 fill the space beneath the fingers, and as such comprises 22 an outer cylindrical portion 28 and transitional portions 23 30. In the spaces between the fingers 18 the swellable 24 member is continuous from the space defined by the rigid assembly to the outer surface of the swellable member.

27 The inner surface of the swellable member 12 is profiled 28 such that it has a portion 32 of increased inner diameter 29 relative to the portions 26 of the swellable member disposed inward of the collars 16, 20. This accounts for 31 the additional inward swelling experienced by this part 32 of the swellab]e member, which resu]ts from the greater 33 thickness of swellable material.

2 The swellable member 12 is formed as a single moulded 3 piece around the rigid assembly 14 from a material 4 selected to expand upon exposure to a predetermined fluid. The swellable member is formed from a material 6 which is selected to expand on contact with a 7 predetermined fluid. Such swellable materials are known 8 in the art. In this example, the swellable member is 9 required to swell in oil, and the material comprises ethylene propylene diene monomer rubber (EPDM) . In an 11 alternative embodiment, where the swellable member is 12 required to swell in water, the material comprises any 13 lightly crosslinked hydrophilic polymer embedded within 14 the main swellable member elastomer, such as at least one of chloroprene, styrene butadiene or ethylene-propylene 16 rubbers. Such water-absorbing resins are termed 17 "superabsorbent polymers" or "SAPs" and when embedded 18 within the swellable member may expand when in contact 19 with an aqueous solution. In a further alternative embodiment, the swellable member comprises an ethylene- 21 propylene-diene polymer with embedded water absorbent 22 resin such that expansion of the swellable member results 23 from contacting either an aqueous solution or polar 24 liquid such as oil or a mixture of both.

26 In use, downhole apparatus of Figure 1 is introduced 27 downhole in a first condition before expansion of the 28 swellable member. As shown in Figure 1, the rigid 29 assembly 14 defines a maximum outer diameter of the downhole apparatus such that it provides, for example, a 31 stand-off or stabilising function. The rigid nature of 32 the rigid assembly 14 provides protection for the 33 downhole apparatus. Also, the structure of the rigid 1 assembly 14, which extends into the body of the swellable 2 member, functions as a skeleton to moderate the effect of 3 shear forces that would, were it not for the rigid 4 assembly 14, be exerted in an uncontrolled manner on the swellable member. The spaced apart fingers 18 of the 6 rigid assembly 14 can flex such that the maximum outer 7 diameter defined by the rigid assembly 14 reduces. This 8 allows the downhole apparatus 10 to pass through 9 restrictions. When the downhole apparatus is in the desired location (e.g. where it desired to create a seal) 11 the swellable member is exposed to the predetermined 12 fluid. The swellable member then expands such that it 13 defines the maximum outer diameter of the downhole 14 apparatus, as shown in Figure 3.

16 The stand off provided by the ridged assembly has the 17 important benefit of avoiding restriction to the 18 expansion of the swellable member upon exposure to the 19 predetermined fluid. An annular space between the outer surface of the swellable member and the inner surface of 21 the bore in which the apparatus is located allows uniform 22 expansion of the swellable member. The uniform swelling 23 creates a substantially uniform sealing force against the 24 inner surface of the bore, which reduces the potential for a failure mode in the annular seal. This is 26 particularly useful where the swelling force capable of 27 being exerted by the swellable member is insufficient to 28 overcome a side load weight of the tubular. In such 29 circumstances, if no centralisation is provided, there would be a significantly larger degree of expansion on 31 the high side of the tubular compared with the expansion 32 on the low side.

1 The recess 19 shown in Figure 1 allows the apparatus to 2 be used as a modular system of downhole components and/ 3 or supplied as a kit of parts. The recess 19 has a 4 ridged profile, arranged to form a mating profile with a connector which is received in the recess such that the 6 connector is sandwiched between portions of the swellable 7 member. The connector may be an end connector, such as 8 that shown generally at 40 in Figures 4A and 4B.

The end connector 40 comprises two components: a mating 11 portion 41 and a retaining portion 42. The mating 12 portion 41 is of a generally cylindrical shape such that 13 it defines a bore 43. A ridged profile 44 is provided 14 towards one end of the mating portion 41, which corresponds to the mating profile in the recess 19. The 16 opposing end of the mating portion provides a bearing 17 surface 45, which abuts a corresponding bearing surface 18 46 of the retaining portion 42. Lips 47a, 47b are 19 formed on the external and internal surfaces of the mating portion 41 respectively. Lip 47a defines a 21 radially extending surface, which constrains the 22 expansion of the swellable member in the axial direction.

23 Lip 47b defines an enlarged bore for receiving the inner 24 parts of the swellable member and rigid assembly. The retaining portion 42 also has fixing means in the form of 26 bolts 48 that threadedly engage with bores 49 at 27 locations spaced apart circumferentially around the 28 external surface of the retaining portion. The bolts can 29 be used to attach the end connector 40 to a downhole component, such as a casing section.

32 When used with the end connector 40, the apparatus will 33 be rotatable on the tubular. The mating portion 41 is 1 coupled to the apparatus and rotates with the apparatus, 2 and relative to the retaining portion 42. The retaining 3 portion 42 prevents axial movement of the apparatus.

In another embodiment (not illustrated), an end connector 6 may be used which is similar to the end connector 40, 7 except that the mating portion and retaining portion are 8 integrally formed or of unitary construction to prevent 9 the mating portion 41 and apparatus from rotating on the tubular.

12 Alternatively, the connector may be of the type shown 13 generally at 50 in Figure 5. This connector 50 is 14 arranged to facilitate connection of the apparatus 10 to a further swellable member such as a packer. The 16 connector 50 is of generally cylindrical shape such that 17 it defines a bore 52. The connector has first and second 18 ridged profiles 54, 56 towards respective opposing ends 19 of the connector, as described above. First 58 and second 60 flanges (which constitute arresting members) 21 are provided on the connector 50. The first flange 58 22 extends radially from the external surface of the 23 connector, i.e. in a direction away from a tubular on 24 which an assembled kit of parts is installed. The second flange 60 extends radially into the bore 52 of the 26 connector. The first and second flanges constrain the 27 expansion of the swellable member as described above.

29 The use of the connector 50 allows the apparatus to be used as kit of parts that can be assembled in the field 31 to meet a particular specification. For example, a 32 series of kits of parts according to the invention can be 33 connected together to provide a string of swellable 1 members where packer coverage of a long length of tubular 2 is required.

4 The above-described embodiment of the invention is manufactured to be gauge with many common bore diameters, 6 thereby providing maximum stand off. The inclusion of a 7 swellable elastomer means that the invention benefits 8 from the integral construction of swellable member and 9 rigid assembly that is robust and high in impact strength. Once wetted with well fluids, the swellable 11 elastomer member allows improved running of well tubulars 12 due to a lower frictional coefficient. This is of 13 benefit in highly deviated wells or extended reach 14 horizontal wells where cumulative resistive drag can prohibit the full installation of metal tubulars.

17 There will now be described a support structure which may 18 be used in conjunction with the apparatus 10 of Figure 1, 19 or may indeed be used with alternative expanding apparatus such as well packers.

22 According to Figures 6A and 6B, there is shown 23 respectively in perspective and side views, a support 24 structure, generally shown at 70. The support structure 70 is formed from metal such as steel. The support 26 structure 70 is configured to abut against an external 27 surface of a swellable member when the swellable member 28 is in an unexpanded condition, and to remain in contact 29 with the external surface after the swellable member expands.

32 The support structure comprises a first cylindrical 33 portion 72 which defines a bore 74 sized such that the 1 support structure can be slipped over a tubular upon 2 which the apparatus is used. The support structure 70 3 comprises an expanding portion 76 consisting of a 4 plurality of support members in the form of leaves 78.

The leaves 78 are circumferentially distributed around 6 the support structure 70 in two layers. The first, inner 7 layer 80 is located inside a second, outer layer 82. The 8 outer layer 82 defines the outer surface of the expanding 9 portion 76, and surrounds and overlays the inner layer 80. The layers 80, 82 therefore define concentric rings 11 of leaves 78 on the expanding portion 76.

13 The leaves 78 consist of longitudinally extending 14 portions which are connected to the cylindrical portion 72 such that a degree of pivoting of the leaves is 16 permitted relative to the cylindrical portion 72. The 17 leaves 78 are disposed such that the edges of the leaves 18 in the inner layer are displaced relative to the edges of 19 the leaves on the outer layer. That is, the gaps between adjacent leaves in the inner layer 80 are misaligned with 21 the gaps between adjacent leaves in the outer layer 82.

22 The leaves 78 are provided with grooves 83 in their outer 23 surface. The grooves 83 extend across the leaves in the 24 circumferential direction of the support structure, and adjacent grooves are aligned such that together they 26 define a continuous circumferential groove around the 27 structure. A similar arrangement of grooves (not shown) 28 is provided on the inner layer of leaves. The grooves 83 29 provide a line about which the leaves will tend to deform or fold.

32 Around the inner surface of the support structure is 33 provided a flexible lining 71 comprising a plurality of 1 plastic layers 73. The plastic layers 73 are each cut 2 from a flexible plastic sheet, and consist of a 3 rectangular band 75 sized to fit in the cylindrical 4 portion 72, and a plurality of flexible leaves 77. The flexible leaves are sized to extend slightly beyond the 6 leaves 78 of the expanding portion. Opposing ends of the 7 plastic layers 73 are joined to create a cylindrical 8 shape that fits within the support structure. The 9 plastic layers overlap one another to provide a multi-ply flexible lining. Edges of the flexible leaves of 11 successive plastic layers are displaced relative to one 12 another, such that the gaps between adjacent layers are 13 misaligned.

Figures 7A, 7B and 70 show respectively in perspective, 16 part-sectional, and end views the support structure 70 in 17 an expanded condition. The leaves 78 have been allowed 18 to pivot radially outwardly about their connections with 19 the cylindrical portion 72, such that they define a frusto-conical portion 84. The overlapping arrangement 21 of the leaves in the inner layer 80 and outer layer 82 22 ensures that there is no direct path through the 23 expanding portion 76 from the inner volume defined by the 24 support structure to the outer surface. The flexible leaves 77 of the plastic layers 73 similarly flex 26 outwards, and the misalignment of the edges increases the 27 convoluted, tortuous path from the inner volume to the 28 outer surface. The plastic leaves are also able to flex 29 into the gaps created by the expansion of the leaves 78.

31 Figures 8 and 9A show the support structure 70 in use in 32 an assembly, generally depicted at 90, with the apparatus 33 10 of Figures 1A to 3. The support structure 70 is 1 located on end connector 92, which is similar to that 2 shown in Figure 4, with like parts bearing the same 3 reference numerals. The end connector 92 differs in that 4 the mating portion 41' comprises an extended cylindrical surface 93 on which the support structure 70 is mounted.

6 In addition, the axial length of the enlarged bore of the 7 mating portion 41' is adapted to take account of its 8 extended length. Retaining ring 95 is provided over the 9 cylindrical portion 72 of the support structure 70.

11 The cylindrical portion 72 of the support structure 70 is 12 secured to the end connector 92, and the expanding 13 portion 76 is arranged to partially surround the 14 swellable member 12. The swellable member 12 is profiled to accommodate the expanding portion 76, and such that 16 the outer profile of the support structure 70 is flush or 17 recessed with respect to the maximum outer diameter of 18 the swellable member 12.

Figure 9B shows the support structure 70 and swellable 21 member 12 in an expanded condition. The support 22 structure 70 is deployed to its expanded condition by 23 expansion of the swellable member after exposure to 24 wellbore fluids. The expanded portion 76 forms a frusto-conical portion 84 around an end of the swellable member 26 12.

28 Figure 9C shows the assembly 90 in an expanded condition 29 where the support structure 70 is fully expanded against the inner wall 85 of a bore 84 in which the assembly is 31 located. The ends 86 of the leaves 78 have been expanded 32 into contact with the wall 85. However, axial forces on 33 the tubular and apparatus will result in shear forces on 1 the swellable member. This will cause the swellable 2 material to "flow" and extrude over the support 3 structure, compromising the integrity of the seal. The 4 support structure 70 is further deployed by these axial forces, and continued expansion or extrusion of the 6 swellable member 12 tends to cause the leaves 78 to 7 deform or fold about the line of the groove 83. The 8 distal portions 87 of the leaves are then brought into 9 contact with the wall 85, providing a support to the swellable member of high integrity.

12 The support structure 70 functions to moderate the effect 13 of shear forces on the swellable member that would, were 14 it not for the support structure 70, be exerted in an uncontrollable manner on the swellable member. The 16 material of the swellable member will have a tendency to 17 extrude over the adjacent end connector 92, and may have 18 a tendency to split at the shoulder defined by the end 19 connector 92. The overlapping arrangement of leaves 78 and the inner and outer layers 80, 82 resists extrusion 21 of the swellable member 12 through gaps between adjacent 22 leaves. The flexible liner 71 further assists with 23 mitigating extrusion of the swellable member through the 24 support structure 70.

26 With reference now to Figures 10 and 11, there is shown, 27 generally depicted at 94, a support structure in 28 accordance with an alternative embodiment of the 29 invention. Figure 10 shows the support structure 94 in an unexpanded condition, and Figure 11 shows the 31 apparatus 94 in an expanded condition.

1 The support structure 94 is again configured to abut 2 against an external surface of a swellable member and a 3 retaining portion 42 of an end connector. The support 4 structure is adapted to be abut the swellable member in an unexpanded condition and to remain in contact with the 6 external surface as the swellable member expands. More 7 specifically, the support structure 94 comprises a number 8 of concentric support members 96, each of which defines a 9 bore through which a tubular is received. One of the support members 96 has four support elements 98 which are 11 spaced apart around and attached to the support member 12 96. The support elements 98 extend in a longitudinal 13 direction such that they provide for an increase in area 14 of contact between the rigid assembly and the swellable member. Each of the support elements 98 comprises four 16 rigid support parts 100 that are configured for movement 17 in relation to each other in a radial direction away from 18 a tubular whereby expansion of the swellable member is 19 accommodated.

21 It will be appreciated that the support structures of 22 Figures 6 to 11 may be used with the apparatus of Figure 23 1, or alternatively could be used with other types of 24 well packers, such as mechanical or inflatable expanding packers.

27 Referring now to Figure 12, there is shown a centraliser, 28 generally depicted at 120, in accordance with a further 29 aspect and embodiment of the invention.

31 The centraliser 120 consists of a substantially tubular 32 body 122 having a throughbore sized to fit on a tubular 33 124.

2 The centraliser 120 comprises a plurality of helical 3 blades 126 upstanding from the tubular body 122. Between 4 adjacent blades are defined flow channels 128 for fluid passing the centraliser, such as circulating mud or 6 cement. The blades and corresponding channels are 7 designed to create a turbulent flow in the fluid, 8 assisting in a sweep of drill cuttings and/ or an 9 appropriate distribution of cement during a cementing operation.

12 The maximum outer diameter of the blades 126 is selected 13 to be a close fit with the inner diameter of the bore in 14 which the centraliser is run. The centraliser is formed from a swellable material which is designed to expand on 16 exposure to a hydrocarbon fluid. In this embodiment, the 17 centraliser is formed from a solid block of a material 18 comprising ethylene propylene diene monomer rubber 19 (EPDM), into which channels are machined to create an arrangement of blades 126 and channels 128.

22 In alternative embodiments, the centraliser may be formed 23 from a combination of materials. For example, in one 24 embodiment only the blades or a portion of the blades is formed from EPDM.

27 In a cementing application, the centraliser 120 provides 28 stand off and protection for a tubular that is being run 29 into the wellbore. When the wellbore is in the required location, the centraliser creates turbulent flow of fluid 31 during the sweeping of drill cuttings up through the 32 annular space. The centraliser also creates a turbulent 33 flow of cement and sufficient stand off of the tubular 1 such that a good cement job is provided between the 2 tubular on which the centraliser is located and the outer 3 tubular. This assists in providing a good seal in the 4 annular space to prevent the flow of hydrocarbons in the annulus.

7 However, should channelling occur along portions of the 8 tubular between centraliser locations, or between the 9 outer surface of the centraliser blades and the bore, the centraliser will be exposed to hydrocarbons. The 11 centraliser will expand outwardly into sealing contact 12 with the bore. This will block the micro-channels and 13 re-establish the integrity of the cement job, preventing 14 further flow of hydrocarbons.

16 It will be appreciated that the apparatus 10 in Figures 1 17 and 2 could be provided with formations to create a 18 turbulent flow, such as upstanding blades or intervening 19 channels. It will also be appreciated that the centraliser 120 could be provided with a rigid support 21 assembly such as that shown in Figure 1.

23 In a variation to the described embodiments, the 24 apparatus may be configured for use on an expandable tubular. The rigid assembly is capable of expanding on 26 the tubular, and the swellable member is brought into 27 proximity or contact to a wall, lining or casing of a 28 bore in which the apparatus is located. Subsequent 29 exposure to wellbore fluid effects a seal in the bore and/ or further centralisation of the apparatus.

32 The present invention provides improved centralisation of 33 downhole apparatus in a variety of downhole applications.

1 In one of these aspects, the invention provides an 2 improved centraliser for assisting in providing a seal in 3 a wellbore.

Variations and modifications to the above described 6 embodiments may be made within the scope of the invention 7 herein intended.