GB2449008A

GB2449008A - Swellable downhole centraliser

Info

Publication number: GB2449008A
Application number: GB0814298A
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: 2008-11-05
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 downhole centraliser apparatus comprises a swellable member 12 which expands upon contact with at least one predetermined fluid and a rigid assembly 14. In a first condition of the apparatus, before expansion of the swellable member, the rigid assembly defines a maximum outer diameter of the apparatus. In a second condition after expansion of the swellable member, the swellable member defines a maximum outer diameter of the apparatus. The maximum outer diameter defined by the rigid assembly may be selected to be not less than the drift diameter of a borehole in which the apparatus is to be located. In this arrangement the rigid assembly provides maximum stand-off, and the swellable member may provide isolation after expansion. In a preferred embodiment the rigid assembly is designed to flex or deform under an axial or radial load.

Description

1 Downho].e apparatus and method 3 The present invention relates to

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

Centralisers perform important functions in downhole 11 environments. Centralisers may, for example, ensure that a 12 tubular does not come into contact with a weilbore surface.

13 This provides protection for the tubular against wear due to 14 friction or impact with the bore hole during run-in.

Centralisers also have an important function in cementing applications. A poorly centralised tubular can lead to a poor 17 fluid sweep of drill cuttings prior to cementing, and the 18 failure to form a cement bond around the entire circumference 19 of the annular space between the tubular and the weilbore.

This results in poor isolation of well fluids, which can 21 ultimately lead to uncontrollable flow of well fluids to the 22 surface or to subterranean geological formations.

24 Centralisers are provided with blades or other formations to assist with creating a turbulent flow of mud and cement.

1 However, micro-channels may still be formed between the cement 2 and the bore wall and! or between the outer surface of the 3 centraliser blades and the bore wall.

A well packer provides a seal in an annulus formed between an 6 exterior surface of a tubular and an interior surface of well 7 casing or a welibore. Known forms of well packers are 8 introduced in an unexpanded condition to the downhole 9 environment in which they are to be used and expanded in-situ to provide the desired seal. In one form, the well packer 11 expands upon coming into contact with a well fluid. In 12 another form, the well packer comprises movable parts that are 13 actuated in-situ to form the seal.

The integrity of the annular seal created by a well packer is 16 paramount. It is advantageous for the tubular on which the 17 packer is located to be centrally located in the bore, such 18 that when the packer is expanded it exerts a force against the 19 bore that is substantially uniformly distributed around the circumference. If the tubular is positioned to one side of 21 the bore, which is typically true for an inclined bore, the 22 expansion force of the packer will have to act against the 23 side load weight of the tubular to move to its expanded 24 condition. If the expansion force is insufficient to overcome the sideload weight, the packer may seal asymmetrically in the 26 bore, with the packer having a radially short side (on the low 27 side of the bore) and a radially longer side (on the high side 28 of the bore) . This results in a potential failure mode 29 between the packer and the bore wall on the high side of the bore.

32 It is amongst the aims of an aspect of the invention to 33 provide an apparatus and method which overcomes or mitigates 34 one or more of the deficiencies or drawbacks of the prior art.

2 It is an aim of an aspect of the invention to provide an 3 improved centraliser for use in a variety of downhole 4 applications.

6 It is an aim of an aspect of the invention to provide an 7 apparatus offering improved centralisation for well packers.

9 Additional aims and objects of the invention will become

apparent from the following description.

12 According to a first aspect of the present invention, there is 13 provided downhole apparatus configured to be disposed on a 14 tubular in a downhole environment, the downhole apparatus comprising: a swellable member which expands upon contact with 16 at least one predetermined fluid; and a rigid assembly, the 17 downhole apparatus having a first condition before expansion 18 of the swellable member, in which the rigid assembly defines a 19 maximum outer diameter of the downhole apparatus, and a second condition after expansion of the swellable member, in which 21 the swellable member defines a maximum outer diameter of the 22 downhole apparatus.

24 The rigid assembly functions to provide support and protection to the swellable member. The rigid assembly functions to 26 support and protect the swellable member, and is relatively 27 rigid with respect to the swellable member. However, the 28 rigid assembly may be designed to flex or deform under an 29 axial or radial load.

31 When the downhole assembly is in use downhole in the first 32 condition the rigid assembly can provide stand-off protection 33 for the swellable member. That is, the swellable member is 1 supported by the rigid assembly away from the borehole wall or 2 lined borehole.

4 The maximum outer diameter defined by the rigid assembly may be selected to be not less than the drift diameter of a 6 borehole in which the apparatus is located. The maximum outer 7 diameter defined by the rigid assembly may be selected to be 8 gauge with a borehole in which the apparatus is located.

9 Alternatively, the maximum outer diameter defined by the rigid assembly may be selected to be greater than the borehole 11 diameter. In this scenario, maximum outer diameter defined by 12 the rigid assembly may be slightly larger than the borehole 13 diameter such that the apparatus may still be run in the 14 borehole, with a radial force from the borehole wall acting to exert a compressive radial force on the apparatus.

17 The swellable member may be expanded to a maximum outer 18 diameter greater than or equal to the maximum outer diameter 19 defined by the rigid assembly. When the downhole assembly is in the second condition, the swellable member is expanded to, 21 for example, provide isolation.

23 The downhole apparatus may be configured such that a part of 24 the rigid assembly is surrounded by the swellable member. The rigid assembly may comprise at least one collar surrounded by 26 the swellable member. More specifically, the at least one 27 collar may be proximal to a bore defined by the swellable 28 member and extending through the downhole apparatus.

Alternatively or in addition, rigid assembly may comprise two 31 collars spaced apart from each other in a longitudinal 32 direction of the downhole apparatus.

1 Alternatively or in addition, the rigid assembly may comprise 2 a plurality of spaced apart fingers. More specifically, each 3 of the plurality of spaced apart fingers may extend in a 4 longitudinal direction. Alternatively or in addition, the fingers may be spaced apart radially around the downhole 6 apparatus.

8 Alternatively or in addition, the plurality of fingers may be 9 attached to a collar towards each opposing end of the downhole apparatus.

12 Alternatively or in addition, the at least one collar and the 13 plurality of fingers may be integrally formed with each other.

The rigid assembly may resemble a bow spring centraliser.

16 Accordingly, the rigid assembly may be designed to flex or 17 deform under an axial or radial load.

19 In an alternative embodiment, the rigid assembly may comprise a rigid member extending radially from the apparatus in its 21 first condition. The rigid assembly may comprise one or more 22 members or blocks located in the apparatus. The members or 23 blocks may be embedded into or partially encapsulated by the 24 swellable member.

26 Alternatively or in addition, the rigid assembly may be formed 27 at least in part of at least one of: a metal, a composite, a 28 plastic, and the like.

The apparatus may further comprise a support structure adapted 31 to act against axial and/or shear forces experienced by the 32 apparatus. More preferably, the support structure is adapted 33 to reduce extrusion of the radially expanding member due to 34 axial and/or shear forces. The support structure may be 1 adapted to be further deployed by axial and/or shear forces 2 experienced by the apparatus.

4 The support structure may comprise an attachment means for coupling to the apparatus and a support portion, wherein the 6 support structure has a first unexpanded condition and a 7 second expanded condition, and is adapted to be deployed to 8 its second expanded condition by expansion of the swellable 9 member.

11 The support structure may be configured to abut against a 12 surface of the swellable member before and during expansion of 13 the swellable member.

The support structure may be configured to abut against a 16 portion of the surface of the radially expanding member.

17 Preferably, the support structure is arranged to at least 18 partially surround an end of the radially expanding member.

19 The support structure may substantially cover an end of the radially expanding member.

22 The support structure may extend along a part of a length of 23 the radially expanding member.

Alternatively or in addition, the support structure may 26 comprise a plurality of rigid support members that are 27 configured for movement in relation to each other to 28 accommodate expansion of the radially expanding member.

The apparatus may be adapted to rotate on a tubular in a 31 downhole environment.

33 The swellable member may define at least one irregularity.

34 More specifically, the at least one irregularity may comprise 1 at least one of: a groove, a ridge, an indentation, a 2 protuberance, a roughened area and an aperture to a bore, 3 which extend into the swellable member.

Alternatively or in addition, the at least one irregularity 6 may extend substantially longitudinally along the swellable 7 member. For example, where the irregularity is a channel the 8 channel may extend longitudinally along the swellable member.

The irregularity may be arranged to define a flow path for 11 fluid passing the apparatus. The irregularity may be arranged 12 to induce or create a turbulent flow. The irregularity may be 13 arranged to create a turbulent flow in drilling fluid or mud 14 flowing past the apparatus, or may be arranged to create a turbulent flow in cement flowing past the apparatus.

17 The swellable member may have a first mating profile towards a 18 first end, and the apparatus may further comprise a connector 19 having a mating profile configured to mate with the first mating profile of the swellable member. The swellable member 21 may comprise a second mating profile towards a second, 22 opposing end. The second mating profile may be identical to 23 the first. The connector may be connectable to either of the 24 first and second ends of the swellable member.

26 The connector may be adapted to permit rotation of the 27 apparatus on a tubular. The connector may comprise a mating 28 portion, which may be adapted to rotate on a tubular. The 29 connector may further comprise a retaining portion, adapted to prevent or limit axial movement of the apparatus and! or the 31 connector on a tubular. The mating portion and! or the 32 retaining portion may comprise a bearing surface.

1 Alternatively or in addition, the apparatus may be attached to 2 the tubular, e.g. by means of an adhesive or bonding agent.

4 The apparatus may be any expanding apparatus. In one embodiment, the apparatus is a centraliser, and may be a 6 casing centraliser. In a further embodiment the apparatus is 7 a weilbore packer.

9 According to a second aspect of the invention there is provided a kit of parts which, when assembled together forms a 11 downhole assembly, the kit of parts comprising the apparatus 12 of the first aspect and a connector.

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

17 According to a third aspect of the invention there is provided 18 a centraliser for a downhole tubular, the centraliser 19 comprising a body and a plurality of irregularities or formations upstanding from the body, wherein the centraliser 21 comprises a swellable material selected to expand on exposure 22 to at least one predetermined fluid.

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

29 The formations may be arranged to define a flow path for fluid passing the apparatus. The formations may be arranged to 31 induce or create a turbulent flow. The irregularity may be 32 arranged to create a turbulent flow in drilling fluid or mud 33 flowing past the apparatus, or may be arranged to create a 34 turbulent flow in cement flowing past the apparatus.

2 The irregularity or formation may be arranged to define a flow 3 path for fluid passing the apparatus. The irregularity may be 4 arranged to induce or create a turbulent flow. The irregularity may be arranged to create a turbulent flow in 6 drilling fluid or mud flowing past the apparatus, or may be 7 arranged to create a turbulent flow in cement flowing past the 8 apparatus.

Preferably, the formations are blades. More preferably, the 11 blades are helically oriented on the body.

13 The blades may comprise a swellable material selected to 14 expand on exposure to a hydrocarbon fluid.

16 Further embodiments of the second and third aspects of the 17 present invention may comprise one or more features according 18 to any preceding aspect of the present invention.

Further features and advantages of the present invention will 21 become apparent from the following specific description, which 22 is given by way of example only and with reference to the 23 accompanying drawings, in which: Figure lA is a perspective, partially cut away view of a 26 downhole apparatus in accordance with a first embodiment 27 of the invention; 29 Figure lB is a perspective, outer view of the downhole apparatus of Figure 1A; 32 Figure 1C is an alternative perspective, partially cut- 33 away view of the downhole apparatus of Figure 1A; 1 Figure 2 is a perspective view of a rigid assembly 2 forming part the downhole apparatus of Figure 1; 4 Figure 3 is a perspective, partially cut-away view of the downhole apparatus of Figures 1 and 2 in an expanded 6 condition; 8 Figure 4A is a perspective view of an end connector 9 assembly which may be used with the invention; 11 Figure 4B is a longitudinal section through the end 12 connector assembly of Figure 4B; 14 Figure 5 is a perspective view of an alternative connector which may be used with the apparatus of Figures 16 1A to 1C; 18 Figures 6A and 6B are respectively perspective and part- 19 sectional views of a support structure which may be used with the apparatus of Figures 1A to 1C in accordance with 21 an embodiment of the invention; 23 Figures 7A, 73, and 7C are respectively perspective, 24 part-sectional, and end views of the support structure of Figures 6A, and 63 in an expanded condition; 27 Figure 8 is a perspective view of an apparatus and 28 support structure in accordance with an embodiment of the 29 invention; 31 Figures 9A to 9C are details of longitudinal sections 32 through assembly of Figure 8 in respectively unexpanded, 33 expanded and fully expended conditions; 1 Figures 10 and 11 are perspective views of an alternative 2 support structure in unexpanded and expanded conditions 3 respectively; and Figure 12 is a perspective view of a centraliser in 6 accordance with a further embodiment of the invention.

8 Referring firstly to Figures 1 and 2, there is shown generally 9 at 10 a downhole apparatus in accordance with a first embodiment of the present invention. The apparatus comprises 11 a swellable member 12 and a rigid assembly 14. The apparatus 12 10 comprises a throughbore 11 which is sized such that the 13 apparatus can be slipped onto a tubular on which it is being 14 used. The downhole apparatus is rotatably mounted on the tubular in this embodiment.

17 The rigid assembly 14, shown in isolation in Figure 2, has 18 three parts: a first collar 16, a plurality of spaced apart 19 fingers 18 and a second collar 20. The first collar 16 and second collar 20 are located within the body of the swellable 21 member 12. The first collar 16 and second collar 20 are 22 located towards opposing ends of the swellable member 12 and 23 are joined by the plurality of spaced apart fingers 18. The 24 fingers 18 are spaced apart around the circumference of the swellable member 12. Note that the second collar 20 is not 26 shown in Figure 1, because Figure 1 shows the swellable member 27 cut away in the vicinity of the first collar 16 but not cut 28 away in the vicinity of the second collar 20.

Each of the fingers 18 comprises an outer portion 22 which 31 defines the outer diameter of the assembly 14 and the outer 32 diameter of the apparatus in the configuration shown most 33 clearly in Figure lB. The fingers 18 follow a path such that 34 the outer portion 22 defines the maximum outer diameter of the 1 assembly at the mid-point of the fingers 18. Two transitional 2 portions 24 join the outer portions 22 to the collars 16, 20.

3 In this embodiment, the outer portion 22 defines a part- 4 cylindrical surface concentric with the collars, but in other embodiments the fingers may define a smooth arcuate path and 6 the outer portion may be curved in the axial direction.

8 The two collars and the plurality of fingers are integrally 9 formed with one another of a suitable rigid material, such as a metal. The rigid assembly is similar in form and function 11 to a bow spring centraliser, and is designed such that the 12 spaced apart fingers 18 of the rigid assembly 14 can 13 resiliently flex when exposed to radial and! or axial loads.

14 For example, when a radial load is experienced by the outer portion 22, the outer diameter defined by the rigid assembly 16 184 reduces, and the axial length of the rigid assembly 17 increases correspondingly. This assists with shock resistance 18 and negotiation of obstacles in the bore during run in.

Each end of the swellable member defines a recess 19 having 21 ridges to allow for push fit connection with a connector (not 22 shown) to enable the apparatus to be used as part of a modular 23 system or kit of parts. This will be described in more detail 24 below.

26 As shown most clearly in Figure 10, the swellable member is 27 formed around the rigid assembly such that the majority of the 28 rigid assembly is encased by the swellable member. The 29 swellable member is therefore disposed between the rigid assembly and the bore in which the apparatus is located. The 31 swellable member is also formed on the interior of the rigid 32 assembly, such that it is disposed between the rigid assembly 33 and a tubular on which the apparatus is located. Radially 34 inward of the collars 16, 20 are located cylindrical portions 1 26 of the swellable material which lie between the collars and 2 the tubular in use. Radially inward of the fingers 18 is a 3 portion of the swellable member which is profiled to fill the 4 space beneath the fingers, and as such comprises an outer cylindrical portion 28 and transitional portions 30. In the 6 spaces between the fingers 18 the swellable member is 7 COntinuous from the space defined by the rigid assembly to the 8 outer surface of the swellable member.

The inner surface of the swellable member 12 is profiled such 11 that it has a portion 32 of increased inner diameter relative 12 to the portions 26 of the swellable member disposed inward of 13 the collars 16, 20. This accounts for the additional inward 14 swelling experienced by this part of the swellable member, which results from the greater thickness of swellable 16 material.

18 The swellable member 12 is formed as a single moulded piece 19 around the rigid assembly 14 from a material selected to expand upon exposure to a predetermined fluid. The swellable 21 member is formed from a material which is selected to expand 22 on contact with a predetermined fluid. Such swellable 23 materials are known in the art. In this example, the 24 swellable member is required to swell in oil, and the material comprises ethylene propylene diene monomer rubber (EPDM). In 26 an alternative embodiment, where the swellable member is 27 required to swell in water, the material comprises any lightly 28 crosslinked hydrophilic polymer embedded within the main 29 swellable member elastomer, such as at least one of chloroprene, styrene butadiene or ethylene-propylene rubbers.

31 Such water-absorbing resins are termed "superabsorbent 32 polymers" or "SAPs" and when embedded within the swellable 33 member may expand when in contact with an aqueous solution.

34 In a further alternative embodiment, the swellable member 1 comprises an ethylene-propylene-diene polymer with embedded 2 water absorbent resin such that expansion of the swellable 3 member results from contacting either an aqueous solution or 4 polar liquid such as oil or a mixture of both.

6 In use, downhole apparatus of Figure 1 is introduced downhole 7 in a first condition before expansion of the swellable member.

8 As shown in Figure 1, the rigid assembly 14 defines a maximum 9 outer diameter of the downhole apparatus such that it provides, for example, a stand-off or stabilising function.

11 The rigid nature of the rigid assembly 14 provides protection 12 for the downhole apparatus. Also, the structure of the rigid 13 assembly 14, which extends into the body of the swellable 14 member, functions as a skeleton to moderate the effect of shear forces that would, were it not for the rigid assembly 16 14, be exerted in an uncontrolled manner on the swellable 17 member. The spaced apart fingers 18 of the rigid assembly 14 18 can flex such that the maximum outer diameter defined by the 19 rigid assembly 14 reduces. This allows the downhole apparatus 10 to pass through restrictions. Jhen the downhole apparatus 21 is in the desired location (e.g. where it desired to create a 22 seal) the swellable member is exposed to the predetermined 23 fluid. The swellable member then expands such that it defines 24 the maximum outer diameter of the downhole apparatus, as shown in Figure 3.

27 The stand off provided by the ridged assembly has the 28 important benefit of avoiding restriction to the expansion of 29 the swellable member upon exposure to the predetermined fluid.

An annular space between the outer surface of the swellable 31 member and the inner surface of the bore in which the 32 apparatus is located allows uniform expansion of the swellable 33 member. The uniform swelling creates a substantially uniform 34 sealing force against the inner surface of the bore, which 1 reduces the potential for a failure mode in the annular seal.

2 This is particularly useful where the swelling force capable 3 of being exerted by the swellable member is insufficient to 4 overcome a side load weight of the tubular. In such circumstances, if no centralisation is provided, there would 6 be a significantly larger degree of expansion on the high side 7 of the tubular compared with the expansion on the low side.

9 The recess 19 shown in Figure 1 allows the apparatus to be used as a modular system of downhole components and! or 11 supplied as a kit of parts. The recess 19 has a ridged 12 profile, arranged to form a mating profile with a connector 13 which is received in the recess such that the connector is 14 sandwiched between portions of the swellable member. The connector may be an end connector, such as that shown 16 generally at 40 in Figures 4A and 4B.

18 The end connector 40 comprises two components: a mating 19 portion 41 and a retaining portion 42. The mating portion 41 is of a generally cylindrical shape such that it defines a 21 bore 43. A ridged profile 44 is provided towards one end of 22 the mating portion 41, which corresponds to the mating profile 23 in the recess 19. The opposing end of the mating portion 24 provides a bearing surface 45, which abuts a corresponding bearing surface 46 of the retaining portion 42. Lips 47a, 26 47b are formed on the external and internal surfaces of the 27 mating portion 41 respectively. Lip 47a defines a radially 28 extending surface, which constrains the expansion of the 29 swellable member in the axial direction. Lip 47b defines an enlarged bore for receiving the inner parts of the swellable 31 member and rigid assembly. The retaining portion 42 also has 32 fixing means in the form of bolts 48 that threadedly engage 33 with bores 49 at locations spaced apart circumferentially 34 around the external surface of the retaining portion. The 1 bolts can be used to attach the end connector 40 to a downhole 2 component, such as a casing section.

4 When used with the end connector 40, the apparatus will be rotatable on the tubular. The mating portion 41 is coupled to 6 the apparatus and rotates with the apparatus, and relative to 7 the retaining portion 42. The retaining portion 42 prevents 8 axial movement of the apparatus.

In another embodiment (not illustrated), an end connector may 11 be used which is similar to the end connector 40, except that 12 the mating portion and retaining portion are integrally formed 13 or of unitary construction to prevent the mating portion 41 14 and apparatus from rotating on the tubular.

16 Alternatively, the connector may be of the type shown 17 generally at 50 in Figure 5. This connector 50 is arranged to 18 facilitate connection of the apparatus 10 to a further 19 swellable member such as a packer. The connector 50 is of generally cylindrical shape such that it defines a bore 52.

21 The connector has first and second ridged profiles 54, 56 22 towards respective opposing ends of the connector, as 23 described above. First 58 and second 60 flanges (which 24 constitute arresting members) are provided on the connector 50. The first flange 58 extends radially from the external 26 surface of the connector, i.e. in a direction away from a 27 tubular on which an assembled kit of parts is installed. The 28 second flange 60 extends radially into the bore 52 of the 29 connector. The first and second flanges constrain the expansion of the swellable member as described above.

32 The use of the connector 50 allows the apparatus to be used as 33 kit of parts that can be assembled in the field to meet a 34 particular specification. For example, a series of kits of 1 parts according to the invention can be connected together to 2 provide a string of swellable members where packer coverage of 3 a long length of tubular is required.

The above-described embodiment of the invention is 6 manufactured to be gauge with many common bore diameters, 7 thereby providing maximum stand off. The inclusion of a 8 swellable elastomer means that the invention benefits from the 9 integral construction of swellable member and rigid assembly that is robust and high in impact strength. Once wetted with 11 well fluids, the swellable elastomer member allows improved 12 running of well tubulars due to a lower frictional 13 coefficient. This is of benefit in highly deviated wells or 14 extended reach 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 be 18 used in conjunction with the apparatus 10 of Figure 1, or may 19 indeed be used with alternative expanding apparatus such as well packers.

22 According to Figures 6A and 68, there is shown respectively in 23 perspective and side views, a support structure, generally 24 shown at 70. The support structure 70 is formed from metal such as steel. The support structure 70 is configured to abut 26 against an external surface of a swellable member when the 27 swellable member is in an unexpanded condition, and to remain 28 in contact with the external surface after the swellable 29 member expands.

31 The support structure comprises a first cylindrical portion 72 32 which defines a bore 74 sized such that the support structure 33 can be slipped over a tubular upon which the apparatus is 34 used. The support structure 70 comprises an expanding portion 1 76 consisting of a pluralityof support members in the form of 2 leaves 78. The leaves 78 are circumferentially distributed 3 around the support structure 70 in two layers. The first, 4 inner layer 80 is located inside a second, outer layer 82.

The outer layer 82 defines the outer surface of the expanding 6 portion 76, and surrounds and overlays the inner layer 80.

7 The layers 80, 82 therefore define concentric rings of leaves 8 78 on the expanding portion 76.

The leaves 78 consist of longitudinally extending portions 11 which are connected to the cylindrical portion 72 such that a 12 degree of pivoting of the leaves is permitted relative to the 13 cylindrical portion 72. The leaves 78 are disposed such that 14 the edges of the leaves in the inner layer are displaced relative to the edges of the leaves on the outer layer. That 16 is, the gaps between adjacent leaves in the inner layer 80 are 17 misaligned with the gaps between adjacent leaves in the outer 18 layer 82. The leaves 78 are provided with grooves 83 in their 19 outer surface. The grooves 83 extend across the leaves in the circumferential direction of the support structure, and 21 adjacent grooves are aligned such that together they define a 22 continuous circumferential groove around the structure. A 23 similar arrangement of grooves (not shown) is provided on the 24 inner layer of leaves. The grooves 83 provide a line about which the leaves will tend to deform or fold.

27 Around the inner surface of the support structure is provided 28 a flexible lining 71 comprising a plurality of plastic layers 29 73. The plastic layers 73 are each cut from a flexible plastic sheet, and consist of a rectangular band 75 sized to 31 fit in the cylindrical portion 72, and a plurality of flexible 32 leaves 77. The flexible leaves are sized to extend slightly 33 beyond the leaves 78 of the expanding portion. Opposing ends 34 of the plastic layers 73 are joined to create a cylindrical 1 shape that fits within the support structure. The plastic 2 layers overlap one another to provide a multi-ply flexible 3 lining. Edges of the flexible leaves of successive plastic 4 layers are displaced relative to one another, such that the gaps between adjacent layers are misaligned.

7 Figures 7A, 73 and 7C show respectively in perspective, part- 8 sectional, and end views the support structure 70 in an 9 expanded condition. The leaves 78 have been allowed to pivot radially outwardly about their connections with the 11 cylindrical portion 72, such that they define a frusto-conical 12 portion 84. The overlapping arrangement of the leaves in the 13 inner layer 80 and outer layer 82 ensures that there is no 14 direct path through the expanding portion 76 from the inner volume defined by the support structure to the outer surface.

16 The flexible leaves 77 of the plastic layers 73 similarly flex 17 outwards, and the misalignment of the edges increases the 18 convoluted, tortuous path from the inner volume to the outer 19 surface. The plastic leaves are also able to flex into the gaps created by the expansion of the leaves 78.

22 Figures 8 and 9A show the support structure 70 in use in an 23 assembly, generally depicted at 90, with the apparatus 10 of 24 Figures 1A to 3. The support structure 70 is located on end connector 92, which is similar to that shown in Figure 4, with 26 like parts bearing the same reference numerals. The end 27 connector 92 differs in that the mating portion 41' comprises 28 an extended cylindrical surface 93 on which the support 29 structure 70 is mounted. In addition, the axial length of the enlarged bore of the mating portion 41' is adapted to take 31 account of its extended length. Retaining ring 95 is provided 32 over the cylindrical portion 72 of the support structure 70.

1 The cylindrical portion 72 of the support structure 70 is 2 secured to the end connector 92, and the expanding portion 76 3 is arranged to partially surround the swellable member 12.

4 The swellable member 12 is profiled to accommodate the expanding portion 76, and such that the outer profile of the 6 support structure 70 is flush or recessed with respect to the 7 maximum outer diameter of the swellable member 12.

9 Figure 93 shows the support structure 70 and swellable member 12 in an expanded condition. The support structure 70 is 11 deployed to its expanded condition by expansion of the 12 swellable member after exposure to welibore fluids. The 13 expanded portion 76 forms a frusto-conical portion 84 around 14 an end of the swellable member 12.

16 Figure 90 shows the assembly 90 in an expanded condition where 17 the support structure 70 is fully expanded against the inner 18 wall 85 of a bore 84 in which the assembly is located. The 19 ends 86 of the leaves 78 have been expanded into contact with the wall 85. However, axial forces on the tubular and 21 apparatus will result in shear forces on the swellable member.

22 This will cause the swellable material to "flow" and extrude 23 over the support structure, compromising the integrity of the 24 seal. The support structure 70 is further deployed by these axial forces, and continued expansion or extrusion of the 26 swellable member 12 tends to cause the leaves 78 to deform or 27 fold about the line of the groove 83. The distal portions 87 28 of the leaves are then brought into contact with the wall 85, 29 providing a support to the swellable member of high integrity.

31 The support structure 70 functions to moderate the effect of 32 shear forces on the swellable member that would, were it not 33 for the support structure 70, be exerted in an uncontrollable 34 manner on the swellable member. The material of the swellable 1 member will have a tendency to extrude over the adjacent end 2 connector 92, and may have a tendency to split at the shoulder 3 defined by the end connector 92. The overlapping arrangement 4 of leaves 78 and the inner and outer layers 80, 82 resists extrusion of the swellable member 12 through gaps between 6 adjacent leaves. The flexible liner 71 further assists with 7 mitigating extrusion of the swellable member through the 8 support structure 70.

With reference now to Figures 10 and 11, there is shown, 11 generally depicted at 94, a support structure in accordance 12 with an alternative embodiment of the invention. Figure 10 13 shows the support structure 94 in an unexpanded condition, and 14 Figure 11 shows the apparatus 94 in an expanded condition.

16 The support structure 94 is again configured to abut against 17 an external surface of a swellable member and a retaining 18 portion 42 of an end connector. The support structure is 19 adapted to be abut the swellable member in an unexpanded condition and to remain in contact with the external surface 21 as the swellable member expands. More specifically, the 22 support structure 94 comprises a number of concentric support 23 members 96, each of which defines a bore through which a 24 tubular is received. One of the support members 96 has four support elements 98 which are spaced apart around and attached 26 to the support member 96. The support elements 98 extend in a 27 longitudinal direction such that they provide for an increase 28 in area of contact between the rigid assembly and the 29 swellable member. Each of the support elements 98 comprises four rigid support parts 100 that are configured for movement 31 in relation to each other in a radial direction away from a 32 tubular whereby expansion of the swellable member is 33 accommodated.

1 It will be appreciated that the support structures of Figures 2 6 to 11 may be used with the apparatus of Figure 1, or 3 alternatively could be used with other types of well packers, 4 such as mechanical or inflatable expanding packers.

6 Referring now to Figure 12, there is shown a centraliser, 7 generally depicted at 120, in accordance with a further aspect 8 and embodiment of the invention.

The centraliser 120 consists of a substantially tubular body 11 122 having a throughbore sized to fit on a tubular 124.

13 The centraliser 120 comprises a plurality of helical blades 14 126 upstanding from the tubular body 122. Between adjacent blades are defined flow channels 128 for fluid passing the 16 centraliser, such as circulating mud or cement. The blades 17 and corresponding channels are designed to create a turbulent 18 flow in the fluid, assisting in a sweep of drill cuttings and! 19 or an appropriate distribution of cement during a cementing operation.

22 The maximum outer diameter of the blades 126 is selected to be 23 a close fit with the inner diameter of the bore in which the 24 centraliser is run. The centraliser is formed from a swellable material which is designed to expand on exposure to 26 a hydrocarbon fluid. In this embodiment, the centraliser is 27 formed from a solid block of a material comprising ethylene 28 propylene diene monomer rubber (EPDM), into which channels are 29 machined to create an arrangement of blades 126 and channels 128.

32 In alternative embodiments, the centraliser may be formed from 33 a combination of materials. For example, in one embodiment 1 only the blades or a portion of the blades is formed from 2 EPDM.

4 In a cementing application, the centraliser 120 provides stand off and protection for a tubular that is being run into the 6 weilbore. When the weilbore is in the required location, the 7 centraliser creates turbulent flow of fluid during the 8 sweeping of drill cuttings up through the annular space. The 9 centraliser also creates a turbulent flow of cement and sufficient stand off of the tubular such that a good cement 11 job is provided between the tubular on which the centraliser 12 is located and the outer tubular. This assists in providing a 13 good seal in the annular space to prevent the flow of 14 hydrocarbons in the annulus.

16 However, should channelling occur along portions of the 17 tubular between centraliser locations, or between the outer 18 surface of the centraliser blades and the bore, the 19 centraliser will be exposed to hydrocarbons. The centraliser will expand outwardly into sealing contact with the bore.

21 This will block the micro-channels and re-establish the 22 integrity of the cement job, preventing further flow of 23 hydrocarbons.

It will be appreciated that the apparatus 10 in Figures 1 and 26 2 could be provided with formations to create a turbulent 27 flow, such as upstanding blades or intervening channels. It 28 will also be appreciated that the centraliser 120 could be 29 provided with a rigid support assembly such as that shown in Figure 1.

32 In a variation to the described embodiments, the apparatus may 33 be configured for use on an expandable tubular. The rigid 34 assembly is capable of expanding on the tubular, and the 1 swellable member is brought into proximity or contact to a 2 wall, lining or casing of a bore in which the apparatus is 3 located. Subsequent exposure to wellbore fluid effects a seal 4 in the bore and/ or further centralisation of the apparatus.

6 The present invention provides improved centralisation of 7 downhole apparatus in a variety of downhole applications. In 8 one of these aspects, the invention provides an improved 9 centraliser for assisting in providing a seal in a weilbore.

11 Variations and modifications to the above described 12 embodiments may be made within the scope of the invention 13 herein intended.

Claims

1 CLAIMS 3 1. A downhole apparatus configured to be disposed on a 4

tubular in a downhole environment, the downhole apparatus comprising: a swellable member which expands upon contact 6 with at least one predetermined fluid; and a rigid 7 assembly integrally formed with the swellable member, the 8 downhole apparatus having a first condition before 9 expansion of the swellable member in which the rigid assembly defines a maximum outer diameter of the downhole 11 apparatus, and a second condition after expansion of the 12 swellable member in which the swellable member defines a 13 maximum outer diameter of the downhole apparatus.

2. The downhole apparatus as claimed in claim 1 wherein the 16 swellable member provides isolation in its second 17 expanded condition.

19 3. The downhole apparatus as claimed in claim 1 or claim 2 wherein the rigid assembly extends into the body of the 21 swellable member.

23 4. The downhole apparatus as claimed in any of claims 1 to 3 24 wherein the maximum outer diameter defined by the rigid assembly is selected to be not less than the drift 26 diameter of a borehole in which the downhole apparatus is 27 located.

29 5. The downhole apparatus as claimed in claim 4 wherein the maximum outer diameter defined by the rigid assembly is 31 selected to be gauge with a borehole in which the 32 downhole apparatus is located.

1 6. The downhole apparatus as claimed in any preceding claim 2 wherein the maximum outer diameter defined by the rigid 3 assembly is selected to be greater than the borehole 4 diameter.

6 7. The downhole apparatus as claimed in any preceding claim 7 wherein the swellable member is expandable to a maximum 8 outer diameter greater than or equal to the maximum outer 9 diameter defined by the rigid assembly.

11 8. The downhole apparatus as claimed in any preceding claim 12 wherein a part of the rigid assembly is surrounded by the 13 swellable member.

9. The downhole apparatus as claimed in any preceding claim 16 wherein a part of the swellable member is disposed 17 between the rigid assembly and a tubular on which the 18 downhole apparatus is located in use.

10. The downhole apparatus as claimed in any preceding claim 21 wherein a part of the rigid assembly comprises two 22 collars spaced apart from each other in a longitudinal 23 direction of the downhole apparatus.

11. The downhole apparatus as claimed in any preceding claim 26 wherein the rigid assembly comprises a plurality of 27 spaced apart fingers extending in a longitudinal 28 direction and spaced apart circumferentially around the 29 downhole apparatus.

31 12. The downhole apparatus as claimed in claim 11 when 32 dependent on claim 10 wherein at least one collar and the 33 plurality of spaced apart fingers are integrally formed 34 with one another.

2 13. The downhole apparatus as claimed in any preceding claim 3 wherein the rigid assembly is designed to flex or deform 4 under an axial or radial load.

6 14. The downhole apparatus as claimed in any preceding claim 7 wherein the rigid assembly is formed at least in part of 8 metal.

15. The downhole apparatus as claimed in any preceding claim 11 wherein the rigid assembly is formed at least in part of 12 a plastic or composite material.

14 16. The downhole apparatus as claimed in any preceding claim further comprising a support structure adapted to act 16 against axial and or shear forces experienced by the 17 downhole apparatus.

19 17. The downhole apparatus as claimed in claim 16 wherein the support structure comprises an attachment means for 21 coupling to the downhole apparatus and a support portion, 22 wherein the support structure has a first unexpanded 23 condition and a second expanded condition, and is adapted 24 to be deployed to its second expanded condition by expansion of the swellable member.

27 18. The centraliser as claimed in claim 16 or claim 17 28 wherein the support structure is configured to abut 29 against a surface of the swellable member before and during expansion of the swellable member.

32 19. The downhole apparatus as claimed in any of claims 16 to 33 18 wherein the support structure substantially covers an 34 end of the swellable member.

2 20. The downhole apparatus as claimed in any of claims 16 to 3 19 wherein the support structure extends along a part of 4 the length of the swellable member.

6 21. The downhole apparatus as claimed in any of claims 16 to 7 20 wherein the support structure comprises a plurality of 8 support members that are configured for movement in 9 relation to each other to accommodate expansion of the swellable member.

12 22. The downhole apparatus as claimed in any preceding claim 13 wherein the swellable member comprises a first mating 14 profile towards a first end, and the downhole apparatus further comprises a connector having a mating profile 16 configured to mate with the first mating profile of the 17 swellable member.

19 23. The downhole apparatus as claimed in claim 22 wherein the connector comprises a retaining portion, adapted to 21 prevent or limit axial movement of the downhole apparatus 22 on a tubular.

24 24. The downhole apparatus as claimed in any preceding claim further adapted to rotate on a tubular in a downhole 26 environment.

28 25. The downhole apparatus as claimed in claim 24 when 29 dependent on claim 23 wherein the connector is adapted to permit rotation of the downhole apparatus on a tubular.

32 26. The downhole apparatus as claimed in any of claims 22 to 33 25 wherein the connector comprises a mating portion, 34 which is adapted to rotate on a tubular.

2 27. The downhole apparatus as claimed in claim any of claims 3 1 to 23 wherein the downhole apparatus is attached to the 4 tubular by means of an adhesive or bonding agent.

6 28. A well packer comprising the apparatus of any preceding 7 claim.

9 29. A centraliser comprising the apparatus of any of claims 1 to 27.

12 30. A kit of parts which, when assembled together forms a 13 downhole assembly, the kit of parts comprising the 14 apparatus of any preceding claim and a connector.

16 31. A centraliser for a downhole tubular, the centraliser 17 comprising a body and plurality of formations upstanding 18 from the body, wherein the centraliser comprises a 19 swellable material selected to expand on exposure to at least one predetermined fluid.

22 32. The centraliser as claimed in claim 31 wherein the 23 swellable material is selected to expand on exposure to a 24 hydrocarbon fluid.

26 33. The centraliser as claimed in claim 31 wherein the 27 formations comprise a swellable material selected to 28 expand on exposure to a hydrocarbon fluid.

34. The centraliser as claimed in any of claims 31 to 33 31 wherein the formations are arranged to induce or create 32 turbulent flow for fluid passing the apparatus.

1 35. The centraliser as claimed in claim 34 wherein the 2 formations are blades.

4 36. The centraliser as claimed in claim 35 wherein the blades extend longitudinally on the body.

7 37. The centraliser as claimed in claim 35 wherein the blades 8 are helically oriented on the body.