CA2526714C

CA2526714C - Apparatus and method for recovering fluids from a well and/or injecting fluids into a well

Info

Publication number: CA2526714C
Application number: CA2526714A
Authority: CA
Inventors: Ian Donald; John Reid
Original assignee: Cameron Systems Ireland Ltd
Current assignee: OneSubsea IP UK Ltd
Priority date: 2003-05-31
Filing date: 2004-06-01
Publication date: 2013-11-19
Anticipated expiration: 2024-06-01
Also published as: ATE482324T1; DE602004029295D1; US20090301728A1; US8733436B2; EP1918509A2; EP2273066A1; US8622138B2; US20130161020A1; US7992633B2; EP2216503A1; US8469086B2; EP1990505A1; US20170138146A1; US20100206546A1; EP2216503B1; EP2282004A1; WO2005047646A1; BRPI0410869A; EP3272995A1; US20120267094A1

Abstract

Methods and apparatus for diverting fluids either into or from a well are described. Some embodiments include a diverter conduit that is located in a bore of a tree. The invention relates especially but not exclusively to a diverter assembly connected to a wing branch of a tree. Some embodiments allow diversion of fluids out of a tree to a subsea processing apparatus followed by the return of at least some of these fluids to the tree for recovery. Alternative embodiments provide only one flowpath and do not include the return of any fluids to the tree. Some embodiments can be retro-fitted to existing trees, which can allow the performance of a new function without having to replacing the tree. Multiple diverter assembly embodiments are also described.

Description

1 Apparatus and Method for recovering fluids from a 2 well and/or in~ectinq fluids into a well 4 The present invention relates to apparatus and methods for diverting fluids. Embodiments of the 6 invention can be used for recovery and injection 7 Some embodiments relate especially but not 8 exclusively to recovery and injection, into either 9 the same, or a different well.
11 Christmas trees are well known in the art of oil and 12 gas wells, and generally comprise an assembly of 13 pipes, valves and fittings installed in a wellh a ad 14 after completion of drilling and installation o f the production tubing to control the flow of oil an d gas 16 from the well. Subsea christmas trees typically 17 have at least two bores one of which communicates 18 with the production tubing (the production bore), 19 and the other of which communicates with the annulus (the annulus bore).

1 Typical designs of Christmas tree have a side outlet 2 (a production wing branch) to the production bore 3 closed by a production wing valve for removal of 4 production fluids from the production bore. The annulus bore also typically has an annulus wing 6 branch with a respective annulus wing valve. The 7 top of the production bore and the top of the 8 annulus bore are usually capped by a Christmas tree 9 cap which typically seals off the various bores in the Christmas tree, and provides hydraulic Channels 11 for operation of the various valves in the Christmas 12 tree by means of intervention equipment, or remotely 13 from an offshore installation.

Wells and trees are often active for a long time, 16 and wells from a decade ago may still be in use 17 today. However, technology has progressed a great 18 deal during this time, for example, subsea 19 processing of fluids is now desirable. Such processing can involve adding chemicals, separating 21 water and sand from the hydrocarbons, etC.
22 Furthermore, it is sometimes desired to take fluids 23 from one well and inject a component of these fluids 24 into another well, or into the same well. To do any of these things involves breaking the pipework 26 attached to the outlet of the wing branch, inserting 27 new pipework leading to this processing equipment, 28 alternative well, etc. This provides the problem 29 and large associated risks of disconnecting pipe work which has been in place for a considerable time 31 and which was never intended to be disconnected.
32 Furthermore, due to environmental regulations, no 1 produced fluids are allowed to leak out into the 2 ocean, and any such unanticipated and unconventional 3 disconnection provides the risk that this will 4 occur.
6 Conventional methods of extracting fluid from wells 7 involves recovering all of the fluids along pipes to 8 the surface (e.g. a rig or even to land) before the 9 hydrocarbons are separated from the unwanted sand and water. Conveying the sand and water such great 11 distances is wasteful of energy. Furthermore, 12 fluids to be injected into a well are often conveyed 13 over significant distances, which is also a waste of 14 energy.
16 In low pressure wells, it is generally desirable to 17 boost the pressure of the production fluids flowing 18 through the production bore, and this is typically 19 done by installing a pump or similar apparatus after the production wing valve in a pipeline or similar 21 leading from the side outlet of the Christmas tree.
22 However, installing such a pump in an active well is 23 a difficult operation, for which production must 24 cease for some time until the pipeline is cut, the pump installed, and the pipeline resealed and tested 26 for integrity.

28 A further alternative is to pressure boost the 29 production fluids by installing a pump from a rig, but this requires a well intervention from the rig, 31 which can be even more expensive than breaking the 32 subsea or seabed pipework.

1 According to a first aspect of the present invention 2 there is provided a diverter assembly for a manifold 3 of an oil or gas well, comprising a housing having 4 an internal passage, wherein the diverter assembly is adapted to connect to a branch of the manifold.

7 According to a second aspect of the invention there 8 is provided a diverter assembly adapted to be 9 inserted within a manifold branch bore, wherein the diverter assembly includes a separator to divide the 11 branch bore into two separate regions.

13 The oil or gas well is typically a subsea well but 14 the invention is equally applicable to topside wells.

17 The manifold may be a gathering manifold at the 18 junction of several flow lines carrying production 19 fluids from, or conveying injection fluids to, a number of different wells. Alternatively, the 21 manifold may be dedicated to a single well; for 22 example, the manifold may comprise a Christmas tree.

24 By "branch" we mean any branch of the manifold, other than a production bore of a tree. The wing 26 branch is typically a lateral branch of the tree, 27 and can be a production or an annulus wing branch 28 connected to a production bore or an annulus bore 29 respectively.
31 Optionally, the housing is attached to a choke body.
32 "Choke body" can mean the housing which remains 1 after the manifold's standard choke has been 2 removed. The choke may be a choke of a tree, or a 3 choke of any other kind of manifold.

5 The diverter assembly could be located in a branch 6 of the manifold (or a branch extension) in series 7 with a choke. For example, in an embodiment where 8 the manifold comprises a tree, the diverter assembly 9 could be located between the choke and the production wing valve or between the choke and the 11 branch outlet. Further alternative embodiments 12 could have the diverter assembly located in pipework 13 coupled to the manifold, instead of within the 14 manifold itself. Such embodiments allow the diverter assembly to be used in addition to a choke, 16 instead of replacing the choke.

18 Embodiments where the diverter assembly is adapted 19 to connect to a branch of a tree means that the tree cap does not have to be removed to fit the diverter 21 assembly. Embodiments of the invention can be 22 easily retro-fitted to existing trees.

24 Preferably, the diverter assembly is locatable within a bore in the branch of the manifold.

27 Optionally, the internal passage of the diverter 28 assembly is in communication with the interior of 29 the choke body, or other part of the manifold branch.

1 The invention provides the advantage that fluids can 2 be diverted from their usual path between the well 3 bore and the outlet of the wing branch. The fluids 4 may be produced fluids being recovered and travelling from the well bore to the outlet of a 6 tree. Alternatively, the fluids may be injection 7 fluids travelling in the reverse direction into the 8 well bore. As the choke is standard equipment, 9 there are well-known and safe techniques of removing and replacing the choke as it wears out. The same 11 tried and tested techniques can be used to remove 12 the choke from the choke body and to clamp the 13 diverter assembly onto the choke body, without the 14 risk of leaking well fluids into the ocean. This enables new pipe work to be connected to the choke 16 body and hence enables safe re-routing of the 17 produced fluids, without having to undertake the 18 considerable risk of disconnecting and reconnecting 19 any of the existing pipes (e. g. the outlet header).
21 Some embodiments allow fluid communication between 22 the well bore and the diverter assembly. Other 23 embodiments allow the well bore to be separated from 24 a region of the diverter assembly. The choke body may be a production choke body or an annulus choke 26 body.

28 Preferably, a first end of the diverter assembly is 29 provided with a clamp for attachment to a choke body or other part of the manifold branch.

1 Optionally, the housing is cylindrical and the 2 internal passage extends axially through the housing 3 between opposite ends of the housing. Alternatively, 4 one end of the internal passage is in a side of the housing.

7 Typically, the diverter assembly includes separation 8 means to provide two separate regions within the 9 diverter assembly. Typically, each of these regions has a respective inlet and outlet so that fluid can 11 flow through both of these regions independently.

13 Optionally, the housing includes an axial insert 14 portion.
16 Typically, the axial insert portion is in the form 17 of a conduit. Typically, the end of the conduit 18 extends beyond the end of the housing. Preferably, 19 the conduit divides the internal passage into a first region comprising the bore of the conduit and 21 a second region comprising the annulus between the 22 housing and the conduit.

24 Optionally, the conduit is adapted to seal within the inside of the branch (e. g. inside the choke 26 body) to prevent fluid communication between the 27 annulus and the bore of the conduit.

29 Alternatively, the axial insert portion is in the form of a stem. Optionally, the axial insert 31 portion is provided with a plug adapted to block an 32 outlet of the Christmas tree, or other kind of 1 manifold. Preferably, the plug is adapted to fit 2 within and seal inside a passage leading to an 3 outlet of a branch of the manifold.

Optionally, the diverter assembly provides means for 6 diverting fluids from a first portion of a first 7 flowpath to a second flowpath, and means for 8 diverting the fluids from a second flowpath to a 9 second portion of a first flowpath.
11 Preferably, at least a part of the first flowpath 12 comprises a branch of the manifold.

14 The first and second portions of the first flowpath could comprise the bore and the annulus of a 16 conduit.

18 According to a third aspect of the present invention 19 there is provided a manifold having a branch and a diverter assembly according to the first or second 21 aspects of the invention.

23 Optionally, the diverter assembly is attached to the 24 branch so that the internal passage of the diverter assembly is in communication with the interior of 26 the branch.

28 Optionally, the manifold has a wing branch outlet, 29 and the internal passage of the diverter assembly is in fluid communication with the wing branch outlet.

1 Optionally, a region defined by the diverter 2 assembly is separate from the production bore of the 3 well. Optionally, the internal passage of the 4 diverter assembly is separated from the well bore by a closed valve in the manifold.

7 Alternatively, the diverter assembly is provided 8 with an insert in the form of a conduit which 9 defines a first region comprising the bore of the conduit, and a second separate region comprising the 11 annulus between the conduit and the housing.
12 Optionally, one end of the conduit is sealed inside 13 the choke body or other part of the branch, to 14 prevent fluid communication between the first and second regions.

17 Optionally, the annulus between the conduit and the 18 housing is closed so that the annulus is in 19 communication with the branch only.
21 Alternatively, the annulus has an outlet for 22 connection to further pipes, so that the second 23 region provides a flowpath which is separate from 24 the first region formed by the bore of the conduit.
26 Optionally, the first and second regions are 27 connected by pipework. Optionally, a processing 28 apparatus is connected in the pipework so that 29 fluids are processed whilst passing through the connecting pipework.

1 Typically, the processing apparatus is chosen from 2 at least one of: a pump; a process fluid turbine;
3 injection apparatus for injecting gas or steam;
4 chemical injection apparatus; a fluid riser;
5 measurement apparatus; temperature measurement 6 apparatus; flow rate measurement apparatus;
7 constitution measurement apparatus; consistency 8 measurement apparatus; gas separation apparatus;
9 water separation apparatus; solids separation 10 apparatus; and hydrocarbon separation apparatus.

12 Optionally, the diverter assembly provides a barrier 13 to separate a branch outlet from a branch inlet.

14 The barrier may separate a branch outlet from a production bore of a tree. Optionally, the barrier 16 comprises a plug, which is typically located inside 17 the choke body (or other part of the manifold 18 branch) to block the branch outlet. Optionally, the 19 plug is attached to the housing by a stem which extends axially through the internal passage of the 21 housing.

23 Alternatively, the barrier comprises a conduit of 24 the diverter assembly which is engaged within the choke body or other part of the branch.

27 Optionally, the manifold is provided with a conduit 28 connecting the first and second regions.

Optionally, a first set of fluids are recovered from 31 a first well via a first diverter assembly and 32 combined with other fluids in a communal conduit, 1 and the combined fluids are then diverted into an 2 export line via a second diverter assembly connected 3 to a second well.

According to a fourth aspect of the present 6 invention, there is provided a method of diverting 7 fluids, comprising: connecting a diverter assembly 8 to a branch of a manifold, wherein the diverter 9 assembly comprises a housing having an internal passage; and diverting the fluids through the 11 housing.

13 According to a fifth aspect of the present invention 14 there is provided a method of diverting well fluids, the method including the steps of:
16 diverting fluids from a first portion of a 17 first flowpath to a second flowpath and diverting 18 the fluids from the second flowpath back to a second 19 portion of the first flowpath;
wherein the fluids are diverted by at least one 21 diverter assembly connected to a branch of a 22 manifold.

24 The diverter assembly is optionally located within a choke body; alternatively, the diverter assembly may 26 be coupled in series with a choke. The diverter 27 assembly may be located in the manifold branch 28 adjacent to the choke, or it may be included within 29 a separate extension portion of the manifold branch.
3p 31 Typically, the method is for recovering fluids from 32 a well, and includes the final step of diverting 1 fluids to an outlet of the first flowpath for 2 recovery therefrom. Alternatively or additionally, 3 the method is for injecting fluids into a well.

Optionally, the internal passage of the diverter 6 assembly is in communication with the interior of 7 the branch.

9 The fluids may be passed in either direction through the diverter assembly.

12 Typically, the diverter assembly includes separation 13 means to provide two separate regions within the 14 diverter assembly, and the method may includes the step of passing fluids through one or both of these 16 regions.

18 Optionally, fluids are passed through the first and 19 the second regions in the same direction.
Alternatively, fluids are passed through the first 21 and the second regions in opposite directions.

23 Optionally, the fluids are passed through one of the 24 first and second regions and subsequently at least a proportion of these fluids are then passed through 26 the other of the first and the second regions.
27 Optionally, the method includes the step of 28 processing the fluids in a processing apparatus 29 before passing the fluids back to the other of the first and second regions.

1 Alternatively, fluids may be passed through only one 2 of the two separate regions. For example, the 3 diverter assembly could be used to provide a' 4 connection between two flow paths which are unconnected to the well bore, e.g. between two 6 external fluid lines. Optionally, fluids could flow 7 only through a region which is sealed from the 8 branch. For example if the separate regions were 9 provided with a conduit sealed within a manifold branch, fluids may flow through the bore of the 11 conduit only. A flowpath could connect the bore of 12 the conduit to a well bore (production or annulus 13 bore) or another main bore of the tree to bypass the 14 manifold branch. This flowpath could optionally link a region defined by the diverter assembly to a l6 well bore via an aperture in the tree cap.

18 Optionally, the first and second regions are l9 connected by pipework. Optionally, a processing apparatus is connected in the pipework so that 21 fluids are processed whilst passing through the 22 connecting pipework.

24 The processing apparatus can be, but is not limited to, any of those described above.

27 Typically, the method includes the step of removing 28 a choke from the choke body before attaching the 29 diverter assembly to the choke body.
31 Optionally, the method includes the step of 32 diverting fluids from a first portion of a first 1 flowpath to a second flowpath and diverting the 2 fluids from the second flowpath to a second portion 3 of the first flowpath.

For recovering production fluids, the first portion 6 of the first flowpath is typically in communication 7 with the production bore, and the second portion of 8 the first flowpath is typically connected to a 9 pipeline for carrying away the recovered fluids (e. g. to the surface). For injecting fluids into 11 the well, the first portion of the first flowpath is 12 typically connected to an external fluid line, and 13 the second portion of the first flowpath is in 14 communication with the annulus bore. Optionally, the flow directions may be reversed.

17 The method provides the advantage that fluids can be 18 diverted (e. g. recovered or injected into the well, 19 or even diverted from another route, bypassing the well completely) without having to remove and 21 replace any pipes already attached to the manifold 22 branch outlet (e. g. a production wing branch 23 outlet).

Optionally, the method includes the step of 26 recovering fluids from a well and the step of 27 injecting fluids into the well. Optionally, some of 28 the recovered fluids are re-injected into the same 29 well, or a different well.
31 For example, the production fluids could be 32 separated into hydrocarbons and water; the 1 hydrocarbons being returned to the first flowpath 2 for recovery therefrom, and the water being returned 3 and injected into the same or different well.
a 5 Optionally, both of the steps of recovering fluids 6 and injecting fluids include using respective flow 7 diverter assemblies. Alternatively, only one of the 8 steps of recovering and injecting fluids includes 9 using a diverter assembly.
11 Optionally, the method includes the step of 12 diverting the fluids through a processing apparatus.

14 According to a sixth aspect of the present invention there is provided a manifold having a first diverter 16 assembly according to the first aspect of the 17 invention connected to a first branch and a second 18 diverter assembly according to the first aspect of 19 the invention connected to a second branch.
21 Typically, the manifold comprises a tree and the 22 first branch comprises a production wing branch and 23 the second branch comprises an annulus wing branch.

According to a seventh aspect of the present 26 invention, there is provided a manifold having a 27 first bore having an outlet;~a second bore having an 28 outlet; a first diverter assembly connected to the 29 first bore; a second diverter assembly connected to the second bore; and a flowpath connecting the first 31 and second diverter assemblies.

1 Typically at least one of the first and second 2 diverter assemblies blocks a passage in the manifold 3 between a bore of the manifold and its respective 4 outlet. Optionally, the manifold comprises a tree, and the first bore comprises a production bore and 6 the second bore comprises an annulus bore.

8 Certain embodiments have the advantage that the 9 first and second diverter assemblies can be connected together to allow the unwanted parts of 11 the produced fluids (e.g. water and sand) to be 12 directly injected back into the well, instead of 13 being pumped away with the hydrocarbons. The 14 unwanted materials can be extracted from the hydrocarbons substantially at the wellhead, which 16 reduces the quantity of production fluids to be 17 pumped away, thereby saving energy. The first and 18 second diverter assemblies can alternatively or 19 additionally be used to connect to other kinds of processing apparatus (e. g. the types described with 21 reference to other aspects of the invention), such 22 as a booster pump, filter apparatus, chemical 23 injection apparatus, etc. to allow adding or taking 24 away of substances and adjustment of pressure to be carried out adjacent to the wellhead. The first and 26 second diverter assemblies enable processing to be 2'7 performed on both fluids being recovered and fluids 38 being injected. Preferred embodiments of the 29 invention enable both recovery and injection to occur simultaneously in the same well.

1 Typically, the first and second diverter assemblies 2 are connected to a processing apparatus. The 3 processing apparatus can be any of those described 4 with reference to other aspects of the invention.
6 The diverter assembly may be a diverter assembly as 7 described according to any aspect of the invention.

9 Typically, a tubing system adapted to both recover and inject fluids is also provided. Preferably, the 11 tubing system is adapted to simultaneously recover 12 and inject fluids.

14 According to a eighth aspect of the present invention there is provided a method of recovery of 16 fluids from, and injection of fluids into, a well, 17 wherein the well has a manifold that includes at 18 least one bore and at least one branch having an 19 outlet, the method including the steps of:
blocking a passage in the manifold between a 21 bore of the manifold and its respective branch 22 outlet;
23 diverting fluids recovered from the well out of 24 the manifold; and injecting fluids into the well;
26 wherein neither the fluids being diverted out 27 of the manifold nor the fluids being injected travel 28 through the branch outlet of the blocked passage.

Preferably, the method is performed using a diverter 31 assembly according to any aspect of the invention.

1 Preferably, a processing apparatus is coupled to the 2 second flowpath. The processing apparatus can be 3 any of the ones defined in any aspect of the 4 invention.
6 Typically, the processing apparatus separates 7 hydrocarbons from the rest of the produced fluids.
8 Typically, the non-hydrocarbon components of the 9 produced fluids are diverted to the second diverter assembly to provide at least one component of the 11 injection fluids.

13 Optionally, at least one component of the injection 14 fluids is provided by an external fluid line which is not connected to the production bore or to the 16 first diverter assembly.

18 Optionally, the method includes the step of 19 diverting at least some of the injection fluids from a first portion of a first flowpath to a second 2l flowpath and diverting the fluids from the second 22 flowpath back to a second portion of the first 23 flowpath for injection into the annulus bore of the 24 well.
26 Typically, the steps of recovering fluids from the 27 well and injecting fluids into the well are carried 28 out simultaneously.

According to a ninth aspect of the present invention 31 there is provided a well assembly comprising:
32 a first well having a first diverter assembly;

1 a second well having a second diverter assembly; and 2 a flowpath connecting the first and second diverter 3 assemblies.

Typically, each of the first and second wells has a 6 tree having a respective bore and a respective 7 outlet, and at least one of the diverter assemblies 8 blocks a passage in the tree between its respective 9 tree bore and its respective tree outlet.
11 Typically, an alternative outlet is provided, and 12 the diverter assembly diverts fluids into a path 13 leading to the alternative outlet.

Optionally, at least one of the first and second 16 diverter assemblies is located within the production 17 bore of its respective tree. Optionally, at least 18 one of the first and second diverter assemblies is 19 connected to a wing branch of its respective tree.
21 According to a tenth aspect of the present invention 22 there is provided a method of diverting fluids from 23 a first well to a second well via at least one 24 manifold, the method including the steps of:
blocking a passage in the manifold between a 26 bore of the manifold and a branch outlet of the 27 manifold; and 28 diverting at least some of the fluids from the 29 first well to the second well via a path not including the branch outlet of the blocked passage.

1 Optionally the at least one manifold comprises a 2 tree of the first well and the method includes the 3 further step of returning a portion of the recovered 4 fluids to the tree of the first well and thereafter 5 recovering that portion of the recovered fluids from 6 the outlet of the blocked passage.

8 According to an eleventh aspect of the present 9 invention there is provided a method of recovery of 10 fluids from, and injection of fluids into, a well 11 having a manifold; wherein at least one of the steps 12 of recovery and injection includes diverting fluids 13 from a first portion of a first flowpath to a second 14 flowpath and diverting the fluids from the second 15 flowpath to a second portion of the first flowpath 17 Optionally, recovery and injection is simultaneous.

18 Optionally, some of the recovered fluids are re-19 injected into the well.
21 According to a twelfth aspect of the present 22 invention there is provided a method of recovering 23 fluids from a first well and re-injecting at least 24 some of these recovered fluids into a second well, wherein the method includes the steps of diverting 26 fluids from a first portion of a first flowpath to a 27 second flowpath, and diverting at least some of 28 these fluids from the second flowpath to a second 29 portion of the first flowpath.
31 Typically, the fluids are recovered from the first 32 well via a first diverter assembly, and wherein the 1 fluids are re-injected into the second well via a 2 sec and diverter assembly.

4 Typi tally, the method also includes the step of pro cessing the production fluids in a processing 6 apparatus connected between the first and second 7 wells.

9 Opt z onally, the method includes the further step of returning a portion of the recovered fluids to the 11 firs t diverter assembly and thereafter recovering 12 that portion of the recovered fluids via the first 13 dive rter assembly.

Acco riling to a thirteenth aspect of the present 16 invention there is provided a method of recovering 17 fluids from, or injecting fluids into, a well, 18 incl siding the step of diverting the fluids between a 19 well bore and a branch outlet whilst bypassing at leas t a portion of the branch.

22 Such embodiments are useful to divert fluids to a 23 pros essing apparatus and then to return them to the 24 wing branch outlet for recovery via a standard export line attached to the outlet. The method is 26 also useful if a wing branch valve gets stuck shut.

28 Optionally, the fluids are diverted via the tree 29 cap.
31 Acco riling to a fourteenth aspect of the present 32 rove no on there is provided a method of injecting 1 fluids into a well, the method comprising diverting 2 fluids from a first portion of a first flowpath to a 3 second flowpath and diverting the fluids from the 4 second flowpath into a second portion of the first flowpath.

7 Optionally, the method is performed using a diverter 8 assembly according to any aspect of the invention.
9 The diverter assembly may be locatable in a wide range of places, including, but not limited to: the 11 production bore, the annulus bore, the production 12 wing branch, the annulus wing branch, a production 13 choke body, an annulus choke body, a tree cap or 14 external conduits connected to a tree. The diverter assembly is not necessarily connected to a tree, but 16 may instead be connected to another type of 17 manifold. The first and second flowpaths could 18 comprise some or all of any part of the manifold.

Typically the first flowpath is a production bore or 21 production line, and the first portion of it is 22 typically a lower part near to the wellhead.
23 Alternatively, the first flowpath comprises an 24 annulus bore. The second portion of the first flowpath is typically a downstream portion of the 26 bore or line adjacent a branch outlet, although the 27 first or second portions can be in the branch or 28 outlet of the first flowpath.

The diversion of fluids from the first flowpath 31 allows the treatment of the fluids (e. g. with 1 chemical s) or pressure boosting for more efficient 2 recovery before re-entry into the first flowpath.

4 Optional ly the second flowpath is an annulus bore, or a conduit inserted into the first flowpath.
6 Other types of bore may optionally be used for the 7 second flowpath instead of an annulus bore.

9 Typicall y the flow diversion from the first flowpath to the second flowpath is achieved by a cap on the 11 tree. Optionally, the cap contains a pump or 12 treatment apparatus, but this can be provided 13 separate ly, or in another part of the apparatus, and 14 in most embodiments of this type, flow will be diverted via the cap to the pump etc and returned to 16 the cap by way of tubing. A connection typically in 17 the form of a conduit is typically provided to 18 transfer fluids between the first and second 19 flowpaths .
21 Typicall y, the diverter assembly can be formed from 22 high grade steels or other metals, using e.g.
23 resilient or inflatable sealing means as required.

The assembly may include outlets for the first and 26 second flowpaths, for diversion of the fluids to a 27 pump or treatment assembly, or other processing 28 apparatus as described in this application.

The assembly optionally comprises a conduit capable 31 of rose rtion into the first flowpath, the assembly 32 having sealing means capable of sealing the conduit 1 agains t the wall of the production bore. The 2 conduZt may provide a flow diverter through its 3 central bore which typically leads to a christmas 4 tree cap and the pump mentioned previously. The seal effected between the conduit and the first 6 flowpath prevents fluid from the first flowpath 7 enter.z.ng the annulus between the conduit and the 8 production bore except as described hereinafter.
9 After passing through a typical booster pump, squeeze or scale chemical treatment apparatus, the 11 fluid is diverted into the second flowpath and from 12 there to a crossover back to the first flowpath and 13 first flowpath outlet.

The assembly and method are typically suited for 16 subse a production wells in normal mode or during 17 well testing, but can also be used in subsea water 18 inject ion wells, land based oil production injection 19 wells, and geothermal wells.
21 The pump can be powered by high pressure water or by 22 elect ricity which can be supplied direct from a 23 fixed or floating offshore installation, or from a 24 tethe red buoy arrangement, or by high pressure gas from a local source.

27 The cap preferably seals within Christmas tree bores 28 above the upper master valve. Seals between the cap 29 and b ores of the tree are optionally 0-ring, infla t able, or preferably metal-to-metal seals. The 31 cap c an be retro-fitted very cost effectively with 1 no disruption to existing pipework and minimal 2 impact on control systems already in place.

4 The typical design of the flow diverters within the 5 cap can vary with the design of tree, the number, 6 size, and configuration of the diverter channels 7 being matched with the production and annulus bores, 8 and others as the case may be. This provides a way 9 to isolate the pump from the production bore if 10 needed, and also provides a bypass loop.

12 The cap is typically capable of retro-fitting to 13 exist ing trees, and many include equivalent 14 hydraulic fluid conduits for control of tree valves, 15 and which match and co-operate with the conduits or 16 other control elements of the tree to which the cap 17 is being fitted.

19 In most preferred embodiments, the cap has outlets 20 for production and annulus flow paths for diversion 21 of fluids away from the cap.

23 In accordance with a fifteenth aspect of the 24 invention there is also provided a pump adapted to 25 fit within a bore of a manifold. The manifold 26 optionally comprises a tree, but can be any kind of 27 manifold for an oil or gas well, such as a gathering 28 manifold.

According to a sixteenth aspect of the present 31 invention there is provided a diverter assembly 1 having a pump according to the fifteenth aspect of 2 the present invention.

4 The diverter assembly can be a diverter assembly according to any aspect of the invention, but it is 6 not limited to these.

8 The tree is typically a subsea tree, such as a 9 christmas tree, typically on a subsea well, but a topside tree (or other topside manifold) connected 11 to a topside well could also be appropriate.
12 Horizontal or vertical trees are equally suitable 13 for use of the invention.

The bore of the tree may be a production bore.
16 However, the diverter assembly and pump could be 17 located in any bore of the tree, for example, in a 18 wing branch bore.

The flow diverter typically incorporates diverter 21 means to divert fluids flowing through the bore of 22 the tree from a first portion of the bore, through 23 the pump, and back to a second portion of the bore 24 for recovery therefrom via an outlet, which is typically the production wing valve.

27 The first portion from which the fluids are 28 initially diverted is typically the production 29 bore/other bore/line of the well, and flow from this portion is typically diverted into a diverter 31 conduit sea led within the bore. Fluid is typically 32 diverted th rough the bore of the diverter conduit, 1 and after passing therethrough, and exiting the bore 2 of the diverter conduit, typically passes through 3 the annulus created between the diverter conduit and 4 the bore or line. At some point on the diverted fluid path, the fluid passes through the pump 6 internally of the tree, thereby minimising the 7 external profile of the tree, and reducing the 8 chances of damage to the pump.

The pump is typically powered by a motor, and the 11 type of motor can be chosen from several different 12 forms. In some embodiments of the invention, a 13 hydraulic motor, a turbine motor or moineau motor 14 can be driven by any well-known method, for example an electro-hydraulic power pack or similar power 16 source, and can be connected, either directly or 17 indirectly, to the pump. In certain other 18 embodiments, the motor can be an electric motor, 19 powered by a local power source or by a remote power source.

22 Certain embodiments of the present invention allow 23 the construction of wellhead assemblies that can 24 drive the fluid flow in different directions, simply by reversing the flow of the pump, although in some 26 embodiments valves may need to be changed (e. g.
27 reverse d) depending on the design of the embodiment.

29 The diverter assembly typically includes a tree cap that can be retrofitted to existing designs of tree, 31 and can integrally contain the pump and/or the motor 32 to drive it.

2 The flow divert a r preferably also comprises a 3 conduit capable of insertion into the bore, and may 4 have sealing means capable of sealing the conduit against the wall of the bore. The flow diverter 6 typically seals within Christmas tree production 7 bores above an upper master valve in a conventional 8 tree, or in the tubing hangar of a horizontal tree, 9 and seals can be optionally 0-ring, inflatable, elastomeric or metal to metal seals. The cap or 11 other parts of t he flow diverter can comprise 12 hydraulic fluid conduits. The pump can optionally 13 be sealed within the conduit.

According to a seventeenth aspect of the invention 16 there is provide d a method of recovering production 17 fluids from a we 11 having a manifold, the manifold 18 having an integr al pump located in a bore of the 19 manifold, and th a method comprising diverting fluids from a first portion of a bore of the manifold 21 through the pump and into a second portion of the 22 bore.

24 According to an eighteenth aspect of the present invention there is provided a Christmas tree having 26 a diverter assembly sealed in a bore of the tree, 27 wherein the dive rter.assembly comprises a separator 28 which divides th a bore of the tree into two separate 29 regions, and which extends through the tree bore and into the product ion zone of the well.

1 Optionally, th a at least one diverter assembly 2 comprises a conduit and at least one seal; the 3 conduit option ally comprises a gas injection line.

This invention may be used in conjunction with a 6 further divert er assembly according to any other 7 aspect of the invention, or with a diverter assembly 8 in the form of a conduit which is sealed in the 9 production bor e. Both diverter assemblies may comprise condu its; one conduit may be arranged 11 concentrically within the other conduit to provide 12 concentric, separate regions within the production l3 bore.

According to a nineteenth aspect of the present 16 invention there is provided a method of diverting 17 fluids, including the steps of:
18 providing a fluid diverter assembly sealed in a 19 bore of a tree to form two separate regions in the bore and extending into the production zone of the 21 well;
22 injecting fluids into the well via one of the 23 regions; and 24 recovering fluids via the other of the regions.
26 The injection fluids are typically gases; the method 27 may include the steps of blocking a flowpath between 28 the bore of the tree and a production wing outlet 29 and diverting the rec overed fluids out of the tree along route. The recovered fluids an alternative 31 may be diverting the recovered fluids to a 32 processing and returning at least some apparatus of 1 these recovered fluids to the tree and recovering 2 these fluids from a wing branch outlet. The 3 recovered fluids may undergo any of the processes 4 described in this invention, and may be returned to 5 the tree for recovery, or not, (e.g. they may be 6 recovered from a fluid riser) according to any of 7 the described methods and flowpaths.

9 Embodiments of the invention will now be described 10 by way of example only and with reference to the 11 accompanying drawings in which:-13 Fig. 1 is a side sectional view of a typical 14 production tree;
15 Fig. 2 is a side view of the Fig. 1 tree with. a 16 diverter cap in place;
17 Fig. 3a is a view of the Fig. 1 tree with a 18 second embodiment of a cap in place;
19 Fig. 3b is a view of the Fig. 1 tree with a 20 third embodiment of a cap in place;
21 Fig. 4a is a view of the Fig. 1 tree with a 22 fourth embodiment of a cap in place; and 23 Fig. 4b is a side view of the Fig. 1 tree with 24 a fifth embodiment of a cap in place.
25 Fig. 5 shows a side view of a first embodiment 26 of a diverter assembly having an internal pump;
27 Fig. 6 shows a similar view of a second 28 embodiment with an internal pump;
29 Fig. 7 shows a similar view of a third 30 embodiment with an internal pump;

31 Fig. 8 shows a similar view of a fourth 32 embodiment with an internal pump;

1 Fig. 9 shows a similar view of a fifth 2 embodiment with a n internal pump;
3 Figs. 10 and 11 s how a sixth embodiment with an 4 internal pump;
Figs. 12 and 13 s how a seventh embodiment with 6 an internal pump;
7 Figs. 14 and 15 s how an eighth embodiment with 8 an internal pump;
9 Fig. 16 shows a ninth embodiment with an internal pump;
11 Fig. 17 shows a schematic diagram of the Fig. 2 12 embodiment coupled to processing apparatus;
13 Fig. 18 shows a schematic diagram of two 14 embodiments of the invention engaged with a production well and an injection well respectively, 16 the two wells being connected via a processing 17 apparatus;
18 Fig. 19 shows a specific example of the Fig. 18 19 embodiment;
Fig. 20 shows a cross-section of an alternative 21 embodiment, which has a diverter conduit located 22 inside a choke body;
23 Fig. 21 shows a cross-section of the embodiment 24 of Fig. 20 located in a horizontal tree;
Fig. 22 shows a cross-section of a further 26 embodiment, similar to the Fig. 20 embodiment, but 27 also including a choke, 28 Fig 23 shows a cross-sectional view of a tree 29 having a first diverter assembly coupled to a first branch of the tree and a second diverter assembly 31 coupled to a second branch of the tree;

1 Fig 24 shows a schematic view of the Fig 23 2 assembly used in conjunction with a first downhole 3 tubing system;
4 Fig 25 shows an alternative embodiment of a downhole tubing system which could be used with the 6 Fig 23 assembly;
7 Figs 26 and 27 show alternative embodiments of 8 the invention, each having a diverter assembly 9 coupled to a modified Christmas tree branch between a choke and a pro duction wing valve;
11 Figs 28 and 29 show further alternative 12 embodiments, each having a diverter assembly coupled 13 to a modified Christmas tree branch below a choke;
14 Fig 30 shows a first diverter assembly used to divert fluids from a first well and connected to an 16 inlet header; and a second diverter assembly used to 17 divert fluids from a second well and connected to an 18 output header;
19 Fig 31 shows a cross-sectional view of an embodiment of a diverter assembly having a central 21 stem;
22 Fig 32 shows a cross-sectional view of an 23 embodiment of a diverter assembly not having a 24 central conduit;
Fig 33 shows a cross-sectional view of a 26 further embodiment of a diverter assembly; and 27 Fig 34 shows a cross-sectional view of a 28 possible method of use of the Fig 33 embodiment to 29 provide a flowpat h bypassing a wing branch of the tree;
31 Fig 35 shows a schematic diagram of a tree with 32 a Christmas tree cap having a gas injection line;

1 Fig. 36 shows a more detailed view of the 2 apparatus of Fig. 35;
3 Fig. 37 shows a combination of the embodiments 4 of Figs. 3 and 35;
Fig 38 shows a further embodiment which is 6 similar to Fig 23; and 7 Fig 39 shows a further embodiment which is 8 similar to Fig 18.

Referring now to the drawings, a typical production 11 manifold on an offshore oil or gas wellhead 12 comprises a Christmas tree with a production bore 1 13 leading from production tubing (not shown) and 14 carrying production fluids from a perforated region of the production casing in a reservoir (not shown).
16 An annulus bore 2 leads to the annulus between the 17 casing and the production tubing and a Christmas 18 tree cap 4 which seals off the production and 19 annulus bores 1, 2, and provides a number of hydraulic control channels 3 by which a remote 21 platform or intervention vessel can communicate with 22 and operate the valves in t he Christmas tree. The 23 cap 4 is removable from the Christmas tree in order 24 to expose the production and annulus bores in the event that intervention is required and tools need 26 to be inserted into the pro duction or annulus bores 27 1, 2.

29 The flow of fluids through the production and annulus bores is governed b y various valves shown in 31 the typical tree of Fig. 1. The production bore 1 32 has a branch 10 which is c1 osed by a production wing 1 valve (PWV) 12. A production swab valve (PSV) 15 2 closes the production bore 1 above the branch 10 and 3 PWV 12. Two lower valves UPMV 17 and ZPMV 18 (which 4 is optional) close the production bore 1 below the branch 10 and PWV 12. Between UPMV 17 and PSV 15, a 6 crossover port (XOV) 20 is provided in the 7 production bore 1 which connects to a the crossover 8 port (XOV) 21 in annulus bore 2.

The annulus bore is closed by an annulus master 11 valve (AMV) 25 below an annulus outlet 28 controlled 12 by an annulus wing valve (AWV) 29, itself below 13 crossover port 21. The crossover port 21 is closed 14 by crossover valve 30. An annulus swab valve 32 located above the crossover port 21 closes the upper 16 end of the annulus bore 2.

18 A11 valves in the tree are typically hydraulically 19 controlled (with the ex oeption of ZPMV 18 which may be mechanically controlled) by means of hydraulic 21 control channels 3 passing through the cap 4 and the 22 body of the tool or via hoses as required, in 23 response to signals generated from the surface or 24 from an intervention vessel.
26 When production fluids are to be recovered from the 27 production bore 1, ZPMV 18 and UPMV 17 are opened, 28 PSV 15 is close d, and PTnIV12 is opened to open the 29 branch 10 which leads to he pipeline (not shown).
t PSV 15 and ASV 32 are only opened if intervention is 31 required.

1 Referring now to Fig. 2, a wellhead cap 40 has a 2 hollow conduit 42 with metal, inflatable or 3 resilient seals 43 at its lower end which can seal 4 the outside of the conduit 42 against the inside 5 walls of the production bore 1, diverting production 6 fluids flowing in through branch 10 into the annulus 7 between the conduit 42 and the production bore 1 and 8 through the outlet 46.

10 Outlet 46 leads via tubing 216 to processing 11 apparatus 213 (see Fig. 17). Many different types 12 of processing apparatus could be used here. For 13 example, the processing apparatus 213 could comprise 14 a pump or process fluid turbine, for boosting the 15 pressure of the fluid. Alternatively, or 16 additionally, the processing apparatus could inject 17 gas, steam, sea water, drill cuttings or waste 18 material into the fluids. The injection of gas 19 could be advantageous, as it would give the fluids 20 "lift", making them easier to pump. The addition of 21 steam has the effect of adding energy to the fluids.

23 Injecting sea water into a well could be useful to 24 boost the formation pressure for recovery of 25 hydrocarbons from the well, and to maintain the 26 pressure in the underground formation against 27 collapse. Also, inject2ng waste gases or drill 28 cuttings etc into a well obviates the need to 29 dispose of these at the surface, which can prove 30 expensive and environmentally damaging.

1 The processing apparatus 213 could also enable 2 chemicals to be added to the flu ids, e.g. viscosity 3 moderators, which thin out the fluids, making them 4 easier to pump, or pipe skin fri coon moderators, which minimise the friction between the fluids and 6 the pipes. Further examples of chemioals which 7 could be injected are surfactant s, refrigerants, and 8 well fracturing chemicals. Processing apparatus 213 9 could also comprise injection water electrolysis equipment. The chemicals/inject ed materials could 11 be added via one or more additional input conduits 12 214.

14 Additionally, an additional inpu t conduit 214 could be used to provide extra fluids t o be injected. An 16 additional input conduit 214 cou 1 d, for example, 17 originate from an inlet header (shown in Fig 30).
18 Likewise, an additional outlet 212 could lead to an 19 outlet header (also shown in Fig 30) for recovery of fluids.

22 The processing apparatus 213 cou 1d also comprise a 23 fluid riser, which could provide an alternative 24 route between the well bore and the surface. This could be very useful if, for example, the branch 10 26 becomes blocked.

28 Alternatively, processing apparatus 213 could 29 comprise separation equipment e.g. for separating gas, water, sand/debris and/or hydrocarbons. The 31 separated components) could be siphoned off via one 32 or more additional process condu.i is 212.

2 The processing apparatus 213 could alternatively or 3 additionally include measurement apparatus, e.g. for 4 measuring the temperature/ flow rate/ constitution/
consistency, etc. The temperature could then be 6 compared to temperature readings taken from the 7 bottom of the well to calculate the temperature 8 change in produced fluids. Furthermore, the 9 processing apparatus 213 cowl d include injection water electrolysis equipment.

12 Alternative embodiments of the invention (described 13 below) can be used for both recovery of production 14 fluids and injection of fluids, and the type of processing apparatus can be selected as appropriate.

17 The bore of conduit 42 can be closed by a cap 18 service valve (CSV) 45 which is normally open but 19 can close off an inlet 44 of the hollow bore of the conduit 42.

22 After treatment by the processing apparatus 213 the 23 fluids are returned via tubing 217 to the production 24 inlet 44 of the cap 40 which leads to the bore of the conduit 42 and from there the fluids pass into 26 the well bore. The conduit b ore and the inlet 46 27 can also have an optional crossover valve (COV) 28 designated 50, and a tree cap adapter 51 in order to 2~ adapt the flow diverter channels in the tree cap 40 to a particular design of tree head. Control 31 channels 3 are mated with a cap controlling adapter 32 5 in order to allow continuity of electrical or 1 hydraulic control functions from surface or an 2 intervention vessel.

4 This embodiment therefore provides a fluid diverter for use with a wellhead tree comprising a thin 6 walled diverter conduit and a seal st a ck element 7 connected to a modified christmas tree cap, sealing 8 inside the production bore of the Christmas tree 9 typically above the hydraulic master valve, diverting flow through the conduit annulus, and the 11 top of the Christmas tree cap and tree cap valves to 12 typically a pressure boosting device o r chemical 13 treatment apparatus, with the return flow routed via 14 the tree cap to the bore of the divert er conduit and to the well bore.

17 Referring to Fig. 3a, a further embod zment of a cap 18 40a has a large diameter conduit 42a extending 19 through the open PSV 15 and terminating in the production bore 1 having seal stack 43a below the 21 branch 10, and a further seal stack 43b sealing the 22 bore of the conduit 42a to the inside of the 23 production bore 1 above the branch 10, leaving an 24 annulus between the conduit 42a and b o re 1. Seals 43a and 43b are disposed on an area of the conduit 26 42a with reduced diameter in the regi on of the 27 branch 10. Seals 43a and 43b are also disposed on 28 either side of the crossover port 20 communicating 29 via channel 21c to the crossover port 21 of the annulus bore 2.

1 Injection fluids enter the branch 10 from where they 2 pass into the annulus between the conduit 42a and 3 the production bore 1. Fluid flow in the axial 4 direction is limited by the seals 43a, 43b and the fluids leave the annulus via the crossover port 20 6 into the crossover channel 21c. The crossover 7 channel 21c leads to the annulus bore 2 and from 8 there the fluids pass through the outlet 62 to the 9 pump or chemical treatment apparatus. The treated or pressurised fluids are returned from the pump or 11 treatment apparatus to inlet 61 in the production 12 bore 1. The fluids travel down the bore of the 13 conduit 42a and from there, directly into the well 14 bore.
16 Cap service valve (CSV) 60 is normally open, annulus 17 swab valve 32 is normally held op en, annulus master 18 valve 25 and annulus wing valve 29 are normally 19 closed, and crossover valve 30 is normally open. A
crossover valve 65 is provided between the conduit 21 bore 42a and the annular bore 2 in order to bypass 22 the pump or treatment apparatus if desired.
23 Normally the crossover valve 65 is maintained 24 closed.
26 This embodiment maintains a fairl y wide bore for 27 more efficient recovery of fluids at relatively high 28 pressure, thereby reducing pressu re drops across the 29 apparatus.
31 This embodiment therefore provide s a fluid diverter 32 for use with a manifold such as a wellhead tree 1 comprising a thin walled diverter with two seal 2 stack elements, connected to a tree cap, which 3 straddles the crossover valve outlet and flowline 4 outlet (which are approximately in the same 5 horizontal plane), diverting flow from the annular 6 space between the straddle and the existing xmas 7 tree bore, through the crossover loop and crossover 8 outlet, into the annulus bore (or annulus flowpath 9 in concentric trees), to the top of the tree cap to 10 pressure boosting or chemical treatment apparatus 11 etc, with the return flow routed via the tree cap 12 and the bore of the conduit.

14 Fig. 3b shows a simplified version of a similar 15 embodiment, in which the conduit 42a is replaced by 16 a production bore straddle 70 having seal s 73a and 17 73b having the same position and function as seals 18 43a and 43b described with reference to t he Fig. 3a 19 embodiment. In the Fig. 3b embodiment, production 20 fluids enter via the branch 10, pass through the 21 open valve PWV 12 into the annulus betwee n the 22 straddle 70 and the production bore 1, th rough the 23 channel 21c and crossover port 20, through the 24 outlet 62a to be treated or pressurised etc, and the 25 fluids are then returned via the inlet 61a, through 26 the straddle 70, through the open LPMV18 and UPMV 17 27 to the production bore 1.

29 This embodiment therefore provides a fluff d diverter 30 for use with a manifold such as a wellhea d tree 31 which is not connected to the tree cap by a thin 32 walled conduit, but is anchored in the tree bore, 1 and which allows full bore flow above the "straddle"
2 portion, but routes flow through the crossover and 3 will allow a swab valve (PSV) to function normally.

The Fig. 4a embodiment has a different design of cap 6 40c with a wide bore conduit 42c extending clown the 7 production bore 1 as previously described. The 8 conduit 42c substantially fills the production bore 9 1, and at its distal end seals the production bore at 83 just above the crossover port 20, and below 11 the branch 10. The PSV 15 is, as before, maintained 12 open by the conduit 42c, and perforations 8~ at the 13 lower end of the conduit are provided in the 14 vicinity of the branch 10. Crossover valve 65b is provided between the production bore 1 and annulus 16 bore 2 in order to bypass the chemical treatment or 17 pump as required.

19 The Fig 4a embodiment works in a similar way to the previous embodiments. This embodiment therefore 21 provides a fluid diverter for use with a wet lhead 22 tree comprising a thin walled conduit connected to a 23 tree cap, with one seal stack element, which is 24 plugged at the bottom, sealing in the production bore above the hydraulic master valve and crossover 26 outlet (where the crossover outlet is below the 27 horizontal plane of the flowline outlet), dz.verting 28 flow through the branch to the annular space between 29 the perforated end of the conduit and the existing tree bore, through perforations 84, through the bore 31 of the conduit 42, to the tree cap, to a treatment 32 or booster apparatus, with the return flow routed 1 through the annulus bore (or annulus flow path in 2 concentric trees) and crossover outlet, to the 3 production bore 1 and the well bore.

Referring now to Fig. 4b, a modified embodiment 6 dispenses with the conduit 42c of the Fi g. 4a 7 embodiment, and simply provides a seal 83a above the 8 XOV port 20 and below the branch 10. This 9 embodiment works in the same way as the previous embodiments.

12 This embodiment provides a fluid diverter for use 13 with a manifold such as a wellhead tree which is not 14 connected to the tree cap by a thin walled conduit, but is anchored in the tree bore and which routes 16 the flow through the crossover and allows full bore 17 flow for the return flow, and will allow the swab 18 valve to function normally.

Fig. 5 shows a subsea tree 101 having a production 21 bore 123 for the recovery of production fluids from 22 the well. The tree 101 has a cap body 103 that has 23 a central bore 103b, and which is attached to the 24 tree 101 so that the bore 103b of the cap body 103 is aligned with the production bore 123 of the tree.
26 Flow of production fluids through the production 27 bore 123 is controlled by the tree master valve 112, 28 which is normally open, and the tree swab valve 114, 29 which is normally closed during the production phase of the well, so as to divert fluids flowing through 31 the production bore 123 and the tree master valve 32 112, through the production wing valve 113 in the 1 production branch, and to a production line for 2 recovery as is conventional in the art.

4 In the embodiment of the invention shown in Fig. 5, the bore 103b of the cap body 103 contains a turbine 6 or turbine motor 108 mounted on a shaft that is 7 journalled on bearings 122. The shaft extends 8 continuously through the lower part of the cap body 9 bore 103b and into the production bore 123 at which point, a turbine pump, centrifugal pump or, as shown 11 here a turbine pump 107 is mounted on the same 12 shaft. The turbine pump 107 is housed within a 13 conduit 102.

The turbine motor 108 is configured with inter-16 collating vanes 108v and 103v on the shaft and side 17 walls of the bore 103b respectively, so that passag a 18 of fluid past the vanes in the direction of the 19 arrows 126a and 126b turns the shaft of the turbine motor 108, and thereby turns the vanes of the 21 turbine pump 107, to which it is directly connected.

23 The bore of the conduit 102 housing the turbine pump 24 107 is open to the production bore 123 at its lower end, but there is a seal between the outer face of 26 the conduit 102 and the inner face of the production 27 bore 123 at that lower end, between the tree master 28 valve 112 and the production wing branch, so that 29 all production fluid passing through the production bore 123 is diverted into the bore of the conduit 31 102. The seal is typically an elastomeric or a 32 metal to metal seal.

2 The upper end of the conduit 102 is sealed in a 3 similar fashion to the inner surface of the cap body 4 bore 103b, at a lower end thereof, but the conduit 102 has apertures 102a allowing fluid communication 6 between the interior of the conduit 102, and th a 7 annulus 124, 125 formed between the conduit 102 and 8 the bore of the tree.

The turbine motor 108 is driven by fluid propel led 11 by a hydraulic power pack H which typically flo'as in 12 the direction of arrows 126a and 126b so that fluid 13 forced down the bore 103b of the cap turns the vanes 14 108v of the turbine motor 108 relative to the vanes 103v of the bore, thereby turning the shaft and the 16 turbine pump 107. These actions draw fluid from the 17 production bore 123 up through the inside of the 18 conduit 102 and expels the fluid through the 19 apertures 102a, into the annulus 124, 125 of the production bore. Since the conduit 102 is sealed to 21 the bore above the apertures 102a, and below the 22 production wing branch at the lower end of the 23 conduit 102, the fluid flowing into the annulus 124 24 is diverted through the annulus 125 and into the production wing through the production wing valve 2~ 113 and can be recovered by normal means.

28 Another benefit of the present embodiment is that 29 the direction of flow of the hydraulic power pac k H
can be reversed from the configuration shown in Fig.
31 5, and in such case the fluid flow would be in the 32 reverse direction from that shown by the arrows in 1 Fig. 5, which would allow the re-injection of fluid 2 from the production wing valve 113, through the 3 annulus 125, 124 aperture 102a, conduit 102 and into 4 the production bore 123, all powered by means of the 5 pump 107 and motor 108 operating in reverse. This 6 can allow water injection or injection of other 7 chemicals or substances into all kinds of wells.

9 In the Fig. 5 embodiment, any suitable turbine or 10 moineau motor can be used, and can be powered by any 11 well known method, such as the electro-hydraulic 12 power pack shown in Fig. 5, but this particular 13 source of power is not essential to the invention.

15 Fig. 6 shows a different embodiment that uses an 16 electric motor 104 instead of the turbine motor 108 17 to rotate the shaft and the turbine pump 107. The 18 electric motor 104 can be powered from an external 19 or a local power source, to which it is connected by 20 cables (not shown) in a conventional manner. The 21 electric motor 104 can be substituted for a 22 hydraulic motor or air motor as required.

24 Like the Fig. 5 embodiment, the direction of 25 rotation of the shaft can be varied by changing the 26 direction of operation of the motor 104, so as to 27 change the direction of flow of the fluid by the 28 arrows in Fig. 6 to the reverse direction.

30 Like the Fig. 5 embodiment, the Fig. 6 assembly can 31 be retrofitted to existing designs of christmas 32 trees, and can be fitted to many different tree bore 1 diameters. The embodiments described also be can 2 incorporated into new designs of Christmastree as 3 integral features rather than as retrofit 4 assemblies. Also, the embodim ents can fitted be to other kinds of manifold apart from trees,such as 6 gathering manifolds, on subsea or topside wells.

8 Fig. 7 shows a further embodiment which illustrates 9 that the connection between the shafts of the motor and the pump can be direct or indirect. In the Fig.
11 7 embodiment, which is otherwise similar to the 12 previous two embodiments described, the electrical 13 motor 104 powers a drive belt 109, which in turn 14 powers the shaft of the pump 107. This connection between the shafts of the pump and motor permits a 16 more compact design of cap 103. The drive belt 109 17 illustrates a direct mechanical type of connection, 18 but could be substituted for a chain drive 19 mechanism, or a hydraulic coupling, or any similar indirect connector such as a hydraulic viscous 21 coupling or well known design.

23 Like the preceding embodiments, the Fig. 7 24 embodiment can be operated in reverse to draw fluids in the opposite direction of the arrows shown, if 26 required to inject fluids such as water, chemicals 27 for treatment, or drill cuttings for disposal into 28 the well.

Fig. 8 shows a further modified embodiment using a 31 hollow turbine shaft 102s that draws fluid from the 32 production bore 123 through the inside of conduit 1 102 and into the inlet of a combined motor and pump 2 unit 105, 107. The motor/pump unit has a hollow 3 shaft design, where the pump rotor 107r is arranged 4 concentrically inside the motor rotor 105r, both of which are arranged inside a motor stator 105s. The 6 pump rotor 107r and the motor rotor 105r rotate as a 7 single piece on bearings 122 around the static 8 hollow shaft 102s thereby drawing fluid from the 9 inside of the shaft 102 through the upper apertures 102u, and down through the annulus 124 between the 11 shaft 102s and the bore 103b of the cap 103. The 12 lower portion of the shaft 102s is apertured at 13 1021, and the outer surface of the conduit 102 is 14 sealed within the bore of the shaft 102s above the lower aperture 1021, so that fluid pumped from the 16 annulus 124 and entering the apertures 1021, 17 continues flowing through the annulus 125 between 18 the conduit 102 and the shaft 102s into the 19 production bore 123, and finally through the production wing valve 113 for export as normal.

22 The motor can be any prime mover of hollow shaft 23 construction, but electric or hydraulic motors can 24 function adequately in this embodiment. The pump design can be of any suitable type, but a moineau 26 motor, or a turbine as shown here, are both 27 suitable.

29 Like previous embodiments, the direction of flow of fluid through the pump shown in Fig. 8 can be 31 reversed simply by reversing the direction of the 1 motor, so as to drive the fluid in the opposite 2 direction of the arrows shown in Fig. 8.

4 Referring now to Fig. 9a, this embodiment employs a motor 106 in the form of a disc rotor that is 6 preferably electrically powered, but could be 7 hydraulic or could derive power from any other 8 suitable source, connected to a centrifugal disc-9 shaped pump 107 that draws fluid from the production bore 123 through the inner bore of the conduit l02 11 and uses centrifugal impellers to expel the fluid 12 radially outwards into collecting conduits 124, and 13 thence into an annulus 125 formed between the 14 conduit 102 and the production bore 123 in which it is sealed. As previously described in earlier 16 embodiments, the fluid propelled down the annulus 17 125 cannot pass the seal at the lower end of the 18 conduit 102 below the production wing branch, and 19 exits through the production wing valve 113.
21 Fig. 9b shows the same pump configured to operate in 22 reverse, to draw fluids through the production wing 23 valve 113, into the conduit 125, across the pump 24 107, through the re-routed conduit 124' and conduit 102, and into the production bore 123.

27 One advantage of the Fig. 9 design is that the disc 28 shaped motor and pump illustrated therein can be 29 duplicated to provide a multi-stage pump with several pump units connected in series and/or in 31 parallel in order to increase the pressure at which 1 the fluid is pumped through the production wing 2 valve 113.

4 Referring now to Figs. 10 and 11, this embodiment illustrates a piston 115 that is sealed within the 6 bore 103b of the cap 103, and connected via a rod to 7 a further lower piston assembly l16 within the bore 8 of the conduit 102. The conduit 102 is again sealed 9 within the bore 103b and the production bore 123.
The lower end of the piston assembly 116 has a check 11 valve 119.

13 The piston 115 is moved up from the lower position 14 shown in Fig. 10a by pumping fluid into the aperture 126a through the wall of the bore 103b by means of a 16 hydraulic power pack in the direction shown by the 17 arrows in Fig. 10a. The piston annulus is sealed 18 below the aperture 126a, and so a build-up of 19 pressure below the piston pushes it upward towards the aperture 126b, from which fluid is drawn by the 21 hydraulic power pack. As the piston 115 travels 22 upward, a hydraulic signal 130 is generated that 23 controls the valve 117, to maintain the direction of 24 the fluid flow shown in Fig. 10a. When the piston 115 reaches its uppermost stroke, another signal 131 26 is generated that switches the valve 117 and 27 reverses direction of fluid~from the hydraulic power 28 pack, so that it enters through upper aperture 126b, 29 and is exhausted through lower aperture 126a, as shown.in Fig. 11a. Any other similar switching 31 system could be used, and fluid lines are not 32 essential to the invention.

2 As the piston is moving up as shown in Fig. 10a, 3 production fluids in the production bore 123 are 4 drawn into the bore 102b of the conduit 102, thereby 5 filling the bore 102b of the conduit underneath the 6 piston. When the piston reaches the upper extent of 7 its travel, and begins to move downwards, the check 8 valve 119 opens when the pressure moving the piston 9 downwards exceeds the reservoir pressure in the 10 production bore 123, so that the production fluids 11 123 in the bore 102b of the conduit 102 flow through 12 the check valve 119, and into the annulus 124 13 between the conduit 102 and the piston shaft. Once 14 the piston reaches the lower extent of its stroke, 15 and the pressure between the annulus 124 and the 16 production bore 123 equalises, the check valve 119 17 in the lower piston assembly 116 closes, trapping 18 the fluid in the annulus 124 above the lower piston 19 assembly 116. At that point, the valve 117 20 switches, causing the piston 115 to rise again and 21 pull the lower piston assembly 116 with it. This 22 lifts the column of fluid in the annulus 124 above 23 the lower piston assembly 116, and once sufficient 24 pressure is generated in the fluid in the annulus 25 124 above lower piston assembly 116, the check 26 valves 120 at the upper end of the annulus open, 27 thereby allowing the well fluid in the annulus to 28 flow through the check valves 120 into the annulus 29 125, and thereby exhausting through wing valve 113 30 branch conduit. When the piston reaches its highest 31 point, the upper hydraulic signal 131 is triggered, 32 changing the direction of valve 117, and causing the 1 pistons 115 and 116 to move down their respective 2 cylinders. As the piston 116 moves down once more, 3 the check valve 119 opens to allow well fluid to 4 fill the displaced volume above the moving lower piston assembly 116, and the cycle repeats.

7 The fluid driven by the hydraulic power pack can be 8 driven by other means. Alternatively, linear 9 oscillating motion can be imparted to the lower piston assembly 116 by other well-known methods i.e.
11 rotating crank and connecting rod, scotch yolk 1~ mechanisms etc.

14 By reversing and/or re-arranging the orientations of the check valves 119 and 120, the direction of flow 16 in this embodiment can also be reversed, as shown in 17 Fig. 10d.

19 The check valves shown are ball valves, but can be substituted for any other known fluid value. The 21 Figs. l0 and 11 embodiment can be retrofitted to 22 existing trees of varying diameters or incorporated 33 into the design of new trees.

Referring now to Figs. 12 and 13, further a 26 embodiment has a similar piston arra ngement as the 27 embodiment shown but the piston in Figs. 10 and 11, 28 assembly 115, 116 is housed within cylinder formed a 29 entirely by th e bore 103b of the 103. As cap before, drive fluid is pumped by hydraulic power the 31 pack into the chamber below the upper piston 115, 32 causing it to rise as shown in Fig. 12a, and the 1 signal line 130 keeps the valve 117 in the correct 2 position as the piston 115 is rising. This draws 3 well fluid through the conduit 102 and check valve 4 119 into the chamber formed in the cap bore 103b.
When the piston has reached its full stroke, the 6 signal line 131 is triggered to switch the valve 117 7 to the position shown in Fig. 13a, so that drive 8 fluid is pumped in the other direction and the 9 piston 115 is pushed down. This drives piston 116 down the bore 103b expelling well fluid through the 11 check valves 120 (valve 119 is closed), into annulus 12 124, 125 and through the production wing valve 113.
13 In this embodiment the check valve 119 is located in 14 the conduit 102, but could be immediately above it.
By reversing the orientation of the check valves as 16 in previous embodiments the flow of the fluid can be 17 reversed.

19 A further embodiment is shown in Figs. 14 and 15, which works in a similar fashion but has a short 21 diverter assembly 102 sealed to the production bore 22 and straddling the production wing branch. The 23 lower piston 116 strokes in the production bore 123 24 above the diverter assembly 102. As before, the drive fluid raises the piston 115 in a first phase 26 shown in Fig. 14, drawing well fluid through the 27 check valve 119, through the diverter assembly 102 28 and into the upper portion of the production bore 29 123. When the valve 117 switches to the configuration shown in Fig. 15, the pistons 115, 116 31 are driven down, thereby expelling the well fluids 32 trapped in the bore 123u, through the check valve 1 120 (valve 119 is closed) and the production wing 2 valve 113.

4 Fig. 16 shows a further embodiment, which employs a rotating crank 110 with an eccentrically attached 6 arm 110a instead of a fluid drive mechanism to move 7 the piston 116. The crank 110 is pulling the piston 8 upward when in the position shown in Fig. 16a, and 9 pushing it downward when in the position shown in 16b. This draws fluid into the upper part of the 11 production bore 123u as previously described. The 12 straddle 102 and check valve arrangements as 13 described in the previous embodiment.

It should be noted that the pump does not have to be 16 located in a production bore; the pump could be 17 located in any bore of the tree with an inlet and an 18 outlet. For example, the pump and diverter assembly 19 may be connected to a wing branch of a tree/a choke body as shown in other embodiments of the invention.

22 The present invention can also usefully be used in 23 multiple well combinations, as shown in Figs. 18 and 24 19. Fig. 18 shows a general arrangement, whereby a production well 230 and an injection well 330 are 26 connected together via processing apparatus 220.

28 The injection well 330 can be any of the capped 29 production well embodiments described above. The production well 230 can also be any of the 31 abovedescribed production well embodiments, with 32 outlets and inlets reversed.

2 Produced fluids from production well 230 flow up 3 through the bore of conduit 42, exit via outlet 244, 4 and pass through tubing 232 to processing apparatus 220, which may also have one or more further input 6 lines 222 and one or more further outlet lines 224.

8 Processing apparatus 220 can be selected to perform 9 any of the functions described above with reference to processing apparatus 213 in the Fig. 17 11 embodiment. Additionally, processing apparatus 220 12 can also separate water/ gas/ oil / sand/ debris 13 from the fluids produced from production well 230 14 and then inject one or more of these into injection well 330. Separating fluids from one well and re-16 injecting into another well via subsea processing 17 apparatus 220 reduces the quantity of tubing, time 18 and energy necessary compared to performing each 19 function individually as described with respect to the Fig. 17 embodiment. Processing apparatus 220 21 may also include a riser to the surface, for 22 carrying the produced fluids or a separated 23 component of these to the surface.

Tubing 233 connects processing apparatus 220 back to 26 an inlet 246 of a wellhead cap 240 of production 27 well 230. The processing apparatus 220 could also 28 be used to inject gas into the separated 29 hydrocarbons for lift and also for the injection of any desired chemicals such as scale or wax 31 inhibitors. The hydrocarbons are then returned via 32 tubing 233 to inlet 246 and flow from there into the 1 annulus between the conduit 42 and the bore in which 2 it is disposed. As the annulus is sealed at the 3 upper and lower ends, the fluids flow through the 4 export line 210 for recovery.

6 The horizontal line 310 of injection well 330 serves 7 as an injection line (instead of an export line).
8 Fluids to be injected can enter injection line 310, 9 from where they pass via the annulus between the 10 conduit 42 and the bore to the tree cap outlet 346 11 and tubing 235 into processing apparatus 220. The 12 processing apparatus may include a pump, chemical 13 injection device, and/or separating devices, etc.
14 Once the injection fluids have been thus processed 15 as required, they can now be combined with any 16 separated water/sand/debris/other waste material 17 from production well 230. The injection fluids are 18 then transported via tubing 234 to an inlet 344 of 19 the cap 340 of injection well 330, from where they 20 pass through the conduit 42 and into the wellbore.

22 It should be noted that it is not necessary to have 23 any extra injection fluids entering via injection 24 line 310; all of the injection fluids could 25 originate from production well 230 instead.
26 Furthermore, as in the previous embodiments, if 27 processing apparatus 220 includes a riser, this 28 riser could be used to transport the processed 29 produced fluids to the surface, instead of passing 30 them back down into the Christmas tree of the 31 production bore again for recovery via export line 32 210.

2 Fig. 19 shows a specific example of the more general 3 embodiment of Fig. 18 and like numbers are used to 4 designate like parts. The processing apparatus in this embodiment includes a water injection booster 6 pump 260 connected via tubing 235 to an injection 7 well, a production booster pump 270 connected via 8 tubing 232 to a production well, and a water 9 separator vessel 250, connected between the two wells via tubing 232, 233 and 234. Pumps 260, 270 11 are powered by respective high voltage electricity 12 power umbilicals 265, 275.

14 In use, produced fluids from production well 230 exit as previously described via conduit 42 (not 16 shown in Fig. 19), outlet 244 and tubing 232; the 17 pressure of the fluids are boosted by booster pump 18 270. The produced fluids then pass into separator 19 vessel 250, which separates the hydrocarbons from the produced water. The hydrocarbons are returned.
21 to production well cap 240 via tubing 233; from cap 22 240, they are then directed via the annulus 23 surrounding the conduit 42 to export line 210.

The separated water is transferred via tubing 234 to 26 the wellbore of injection well 330 via inlet 344.
27 The separated water enters injection well through 28 inlet 344, from where it passes directly into its 29 conduit 42 and from there, into the production bore and the depths of injection well 330.

1 Optionally, it may also be desired to inject 2 additional fluids into injection well 330. This can 3 be done by closing a valve in tubing 234 to prevent 4 any fluids from entering the injection well via tubing 234. Now, these additional fluids can enter 6 injection well 330 via injection line 310 (which was 7 formerly the export line in previous embodiments).
8 The rest of this procedure will follow that 9 described above with reference to Fig. 17. Fluids entering injection line 310 pass up the annulus 11 between conduit 42 (see Figs. 2 and 17) and the 12 wellbore, are diverted by the seals 43 (see Fig. 2) 13 at the lower end of conduit 42 to travel up the 14 annulus, and exit via outlet 346. The fluids then l5 pass along tubing 235, are pressure boosted by 16 booster pump 260 and are returned via conduit 237 to 17 inlet 344 of the Christmas tree. From here, the 18 fluids pass through the inside of conduit 42 and 19 directly into the wellbore and the depths of the well 330.

22 Typically, fluids are injected into injection well 23 330 from tubing 234 (i.e. fluids separated from the 24 produced fluids of production well 230) and from injection line 310 (i.e, any additional fluids) in 26 sequence. Alternatively, tubings 234 and 237 could 27 combine at inlet 344 and the two separate lines of 28 injected fluids could be injected into well 330 29 simultaneously.
31 In the Fig. 19 embodiment, the processing apparatus 32 could comprise simply the water separator vessel 1 250, and not include either of the booster pumps 2 260, 270.

4 Although only two connected wells are shown in Figs.
18 and 19, it should be understood that more wells 6 could also be connected to the processing apparatus.

8 Two further embodiments of the invention are shown 9 in Figs. 20 and 21; these embodiments are adapted for use in a traditional and horizontal tree 11 respectively. These embodiments have a diverter 12 assembly 502 located partially inside a Christmas 13 tree choke body 500. (The internal parts of the 14 choke have been removed, just leaving choke body 500). Choke body 500 communicates with an interior 16 bore of a perpendicular extension of branch 10.

18 Diverter assembly 502 comprises a housing 504, a 19 conduit 542, an inlet 546 and an outlet 544.
Housing 504 is substantially cylindrical and has an 21 axial passage 508 extending along its entire length 22 and a connecting lateral passage adjacent to its 23 upper end; the lateral passage leads to outlet 544.
24 The lower end of housing 504 is adapted to attach to the upper end of choke body 500 at clamp 506. Axial 26 passage 508 has a reduced diameter portion at its 27 upper end; conduit 542 is located inside axial 28 passage 508 and extends through axial passage 508 as 29 a continuation of the reduced diameter portion. The rest of axial passage 508 beyond the reduced 31 diameter portion is of a larger diameter than 32 conduit 542, creating an annulus 520 between the 1 outside surface of conduit 542 and axial passage 2 508. Conduit 542 extends beyond housing 504 into 3 choke body 500, and past the junction between branch 4 l0 and its perpendicular extension. At this point, the perpendicular extension of branch 10 becomes an 6 outlet 530 of branch 10; this is the same outlet as 7 shown in the Fig. 2 embodiment. Conduit 542 is 8 sealed to the perpendicular extension at seal 532 9 just below the junction. Outlet 544 and inlet 546 are typically attached to conduits (not shown) which 11 leads to and from processing apparatus, which could 12 be any of the processing apparatus described above 13 with referenoe to previous embodiments.

The diverter assembly 502 can be used to recover 16 fluids from or inject fluids into a well. A method 17 of recovering fluids will now be described.

19 In use, produced fluids come up the production bore 1, enter branch 10 and from there enter annulus 520 21 between conduit 542 and axial passage 508. The 22 fluids are prevented from going downwards towards 23 outlet 530 by seal 532, so they are forced upwards 24 in annulus 520, exiting annulus 520 via outlet 544.
Outlet 544 typically leads to a processing apparatus 26 (which could be any of the ones described earlier, 27 e.g. a pumping or injection apparatus). Once the 28 fluids have been processed, they are returned 29 through a further conduit (not shown) to inlet 546.
From here, the fluids pass through the inside of 31 conduit 542 and exit though outlet 530, from where 32 they are recovered via an export line.

2 To inject fluids into the well, the embodiments of 3 Figs 20 and 21 can be used with the flow directions 4 reversed.

6 It is very common for manifolds of various types to 7 have a choke; the Fig. 20 and Fig. 21 tree 8 embodiments have the advantage that the diverter 9 assembly can be integrated easily with the existing 10 choke body with minimal intervention in the well;
11 locating a part of the diverter assembly in the 12 choke body need not even involve removing well cap 13 40.

15 A further embodiment is shown in Fig. 22. This is 16 very similar to the Fig. 20 and 21 embodiments, with 17 a choke 540 coupled (e.g. clamped) to the top of 18 choke body 500. Like parts are designated with like 19 reference numerals. Choke 540 is a standard subsea 20 choke.

22 Outlet 544 is coupled via a conduit (not shown) to 23 processing apparatus 550, which is in turn connected 24 to an inlet of choke 540. Choke 540 is a standard 25 choke, having an inner passage with an outlet at its 26 lower end and an inlet 541. The lower end of 27 passage 540 is aligned with inlet 546 of axial 28 passage 508 of housing 504; thus the inner passage 29 of choke 540 and axial passage 508 collectively form 30 one combined axial passage.

1 A method of recovering fluids will now be described.
2 In use, produced fluids from production bore 1 enter 3 branch 10 and from there enter annulus 520 between 4 conduit 542 and axial passage 508. The fluids are prevented from going downwards towards outlet 530 by 6 seal 532, so they are forced upwards in annulus 520, 7 exiting annulus 520 via outlet 544. Outlet 544 8 typically leads to a processing apparatus (which 9 could be any of the ones described earlier, e.g, a pumping or injection apparatus). Once the fluids 11 have been processed, they are returned through a 12 further conduit (not shown) to the inlet 541 of 13 choke 540. Choke 540 may be opened, or partially 14 opened as desired to control the pressure of the produced fluids. The produced fluids pass through 16 the inner passage of the choke, through conduit 542 17 and exit though outlet 530, from where they are 18 recovered via an export line.

The Fig. 22 embodiment is useful for embodiments 21 which also require a choke in addition to the 22 diverter assembly of Figs. 20 and 2l. Again, the 23 Fig 22 embodiment can be used to inject fluids into 24 a well by reversing the flow paths.
26 Conduit 542 does not necessarily form an extension 27 of axial passage 508. Alternative embodiments could 28 include a conduit which is a separate component to 29 housing 504; this conduit could be sealed to the upper end of axial passage 508 above outlet 544, in 31 a similar way as conduit 542 is sealed at seal 532.

1 Embodiments of the invention can be retrofitted to 2 many different existing designs of manifold, by 3 simply matching the positions and shapes of the 4 hydraulic control channels 3 in the cap, and providing flow diverting channels or connected to 6 the cap which are matched in position (and 7 preferably size) to the production, annulus and 8 other bores in the tree or other manifold.

Referring now to Fig 23, a conventional tree 11 manifold 601 is illustrated having a production bore 12 602 and an annulus bore 603.

14 The tree has a production wing 620 and associated production wing valve 610. The production wing 620 16 terminates in a production choke body 630. The 17 production choke body 630 has an interior bore 607 18 extending therethrough in a direction perpendicular 19 to the production wing 620. The bore 607 of the production choke body is in communication with the 21 production wing 620 so that the choke body 630 forms 22 an extension portion of the production wing 620.
23 The opening at the lower end of the bore 607 24 comprises an outlet 612. In prior art trees, a choke is usually installed in the production choke 26 body 630, but in the tree 601 of the present 27 invention, the choke itself has been removed.

29 Similarly, the tree 601 also has an annulus wing 621, an annulus wing value 611, an annulus choke 31 body 631 and an interior bore 609 of the annulus 32 choke body 631 terminating in an inlet 613 at its 1 lower end. There is no choke inside the annulus 2 choke body 631.

4 Attached to the production choke body 630 of the production wing 620 is a first diverter assembly 604 6 in the form of a production insert. The diverter 7 assembly 604 is very similar to the flow diverter 8 assemblies of Figs 20 to 22.

The production insert 604 comprises a substantially 11 cylindrical housing 640, a conduit 642, an inlet 646 12 and an outlet 644. The housing 640 has a reduced 13 diameter portion 641 at an upper end and an 14 increased diameter portion 643 at a lower end.
16 The conduit 642 has an inner bore 649, and forms an 17 extension of the reduced diameter portion 641. The 18 conduit 642 is longer than the housing 640 so that 19 it extends beyond the end of the housing 640.
21 The space between the outer surface of the conduit 22 642 and the inner surfaoe of the housing 640 forms 23 an axial passage 647, which ends where the conduit 24 642 extends out from the housing 640. A connecting lateral passage is provided adjacent to the join of 26 the conduit 642 and the housing 640; the lateral 27 passage is in communication with the axial passage 28 647 of the housing 640 and terminates in the outlet 29 644.
31 The lower end of the housing 640 is attached to the 32 upper end of the production choke body 630 at a 1 clamp 648. The conduit 642 is sealingly attached 2 inside the inner bore 607 of the choke body 630 at 3 an annular seal 645.

Attached to the annular choke body 631 is a second 6 diverter assembly 605. The second diverter assembly 7 605 is of the same form as the first diverter 8 assembly 604. The components of the second diverter 9 assembly 605 are the same as those of the first diverter assembly 604, including a housing 680 11 comprising a reduced diameter portion 681 and an 12 enlarged diameter portion 683; a conduit 682 13 extending from the reduced diameter portion 681 and 14 having a bore 689; an outlet 686; an inlet 684; and an axial passage 687 formed between the enlarged 16 diameter portion 683 of the housing 680 and the 17 conduit 682. A connecting lateral passage is 18 provided adjacent to the join of the conduit 682 and 19 the housing 680; the lateral passage is in communication with the axial passage 687 of the 21 housing 680 and terminates in the inlet 684. The 22 housing 680 is clamped by a clamp 688 on the annulus 23 choke body 631, and the conduit 682 is sealed to the 24 inside of the annulus choke body 631 at seal 685.
26 A conduit 690 connects the outlet 644 of the first 27 diverter assembly 604 to a processing apparatus 700.
28 In this embodiment, the processing apparatus 700 29 comprises bulk water separation equipment, which is adapted to separate water from hydrocarbons. A
31 further conduit 692 connects the inlet 646 of the 32 first diverter assembly 604 to the processing 1 apparatus 700. Likewise, conduits 694, 696 connect 2 the outlet 686 and the inlet 684 respectively of the 3 second diverter assembly 605 to the processing 4 apparatus 700. The processing apparatus 700 has 5 pumps 820 fitted into the conduits between the 6 separation vessel and the first and second flow 7 diverter assemblies 604, 605.

9 The production bore 602 and the annulus bore 603 10 extend down into the well from the tree 601, where 11 they are connected to a tubing system 800a, shown in l2 Fig 24.

14 The tubing system 800a is adapted to allow the 15 simultaneous injection of a first fluid into an 16 injection zone 805 and production of a second fluid 17 from a production zone 804. The tubing system 800a 18 comprises an inner tubing 810 which is located 19 inside an outer tubing 812. The production bore 602 20 is the inner bore of the inner tubing 810. The 21 inner tubing 810 has perforations 814 in the region 22 of the production zone 804. The outer tubing has 23 perforations 816 in the region of the injection zone 24 805. A cylindrical plug 801 is provided in the 25 annulus bore 603 which lies between the outer tubing 26 812 and the inner tubing 810. The plug 801 27 separates the part of the annulus bore 803 in the 28 region of the injection.zone 805 from the rest of 29 the annulus bore 803.
31 In use, the produced fluids (typically a mixture of 32 hydrocarbons and water) enter the inner tubing 810 1 through the perforations 814 and pass into the 2 production bore 602. The produced fluids then pass 3 through the production wing 620, the axial passage 4 647, the outlet 644, and the conduit 690 into the processing apparatus 700. The processing apparatus 6 700 separates the hydrocarbons from the~water (and 7 optionally other elements such as sand), e.g. using 8 centrifugal separation. Alternatively or 9 additionally, the processing apparatus can comprise any of the types of processing apparatus mentioned 11 in this specification.

13 The separated hydrocarbons flow into the conduit 14 692, from where they return to the first diverter assembly 604 via the inlet 646. The hydrocarbons 16 then flow down through the conduit 642 and exit the 17 choke body 630 at outlet 612, e.g. for removal to 18 the surface.
l9 The water separated from the hydrocarbons by the 21 processing apparatus 700 is diverted through the 22 conduit 696, the axial passage 687, and the annulus 23 wing 611 into the annulus bore 603. When the water 24 reaches the injection zone 805, it passes through the perforations 816 in the outer tubing 812 into 26 the injection zone 805.

28 If desired, extra fluids can be injected into the 29 well in addition to the separated water. These extra fluids flow into the second diverter assembly 31 631 via the inlet 613, flow directly through the 32 conduit 682, the conduit 694 and into the processing 1 apparatus 700. These extra fluids are then directed 2 back through the conduit 696 and into the annulus 3 bore 603 as explained above for the path of the 4 separated water.
6 Fig 25 shows an alternative form of tubing system 7 800b including an inner tubing 820, an outer tubing 8 822 and an annular seal 821, for use in situations 9 where a production zone 824 is located above an injection zone 825. The inner tubing 820 has 11 perforations 836 in the region of the production 12 zone 824 and the outer tubing 822 has perforations 13 834 in the region of the injection zone 825.

The outer tubing 822, which generally extends round 16 the circumference of the inner tubing 820, is split 17 into a plurality of axial tubes in the region of the 18 production zone 824. This allows fluids from the 19 production zone 824 to pass between the axial tubes and through the perforations 836 in the inner tubing 21 820 into the production bore 602. From the 22 production bore 602 the fluids pass upwards into the 23 tree as described above. The returned injection 24 fluids in the annulus bore 603 pass through the perforations 834 in the outer tubing 822 into the 26 injection zone 825.

28 The Fig 23 embodiment does not necessarily include 29 any kind of processing apparatus 700. The Fig 23 embodiment may be used to recover fluids and/or 31 inject fluids, either at the same time, or different 32 times. The fluids to be injected do not necessarily 1 have to originate from any recovered fluids; the 2 injected fluids and recovered fluids may instead be 3 two un-related streams of fluids. Therefore, the 4 Fig 23 embodiment does not have to be used for re-injection of recovered fluids; it can additionally 6 be used in methods of injection.

8 The pumps 820 are optional.

The tubing system 800a, 800b could be any system 11 that allows both production and injection; the 12 system is not limited to the examples given above.
l3 Optionally, the tubing system could comprise two 14 conduits which are side by side, instead of one inside the other, one of the conduits providing the 16 production bore and the second providing the annulus 17 bore.

19 Figs 26 to 29 illustrate alternative embodiments where the diverter assembly is not inserted within a 21 choke body. These embodiments therefore allow a 22 choke to be used in addition to the diverter 23 assembly.

Fig 26 shows a manifold in the form of a tree 900 26 having a production bore 902, a production wing 27 branch 920, a production wing valve 910, an outlet 28 912 and a production choke 930. The production 29 choke 930 is a full choke, fitted as standard in many christmas trees, in contrast with the 31 production choke body 630 of the Fig 23 embodiment, 32 from which the actual choke has been removed. In 1 Fig 26, the production choke 930 is shown in a fully 2 open position.

4 A diverter assembly 904 in the form of a production insert is located in the production wing branch 920 6 between the production wing value 910 and the 7 production choke 930. The diverter assembly 904 is 8 the same as the diverter assembly 604 of the Fig 23 9 embodiment, and like parts are designated here by like numbers, prefixed by "9". Zike the Fig 23 11 embodiment, the Fig 26 housing 940 is attached to 12 the production wing branch 920 at a clamp 948.

14 The lower end of the conduit 942 is sealed inside the production wing branch 920 at a seal 945. The 16 production wing branch 920 includes a secondary 17 branch 921 which connects the part of the production 18 wing branch 920 adjacent to the diverter assembly 19 904 with the part of the production wing branch 920 adjacent to the production choke 930. A valve 922 21 is located in the production wing branch 920 between 22 the diverter assembly 904 and the production choke 23 930.

The combination of the valve 922 and the seal 945 26 prevents production fluids from flowing directly 27 from the production bore 902 to the outlet 912.
28 Instead, the production fluids are diverted into the 29 axial annular passage 947 between the conduit 942 and the housing 940. The fluids then exit the 31 outlet 944 into a processing apparatus (examples of 32 which are described above), then re-enter the 1 diverter assembly via the inlet 946, from where they 2 pass through the conduit 942, through the secondary 3 branch 921, the choke 930 and the outlet 912.

5 Fig 27 shows an alternative embodiment of the Fig 26 6 design, and like parts are denoted by like numbers 7 having a prime. In this embodiment, the valve 922 8 is not needed because the secondary branch 921' 9 continues directly to the production choke 930', 10 instead of rejoining the production wing branch 11 920'. Again, the diverter assembly 904' is sealed 12 in the production wing branch 920', which prevents 13 fluids from flowing directly along the production 14 wing branch 920', the fluids instead being diverted 15 through the diverter assembly 904'.

17 Fig 28 shows a further embodiment, in which a 18 diverter assembly 1004 is located in an extension 19 1021 of a production wing branch 1020 beneath a 20 choke 1030. The diverter assembly 1004 is the same 21 as the diverter assemblies of Figs 26 and 27; it is 22 merely rotated at 90 degrees with respect to the 23 production wing branch 1020.

25 The diverter assembly 1004 is sealed within the 2~ branch extension 1021 at a seal 1045. A valve 1022 27 is located in the branch extension 1021 below the 28 diverter assembly 1004.

30 .The branch extension 1021 comprises a primary 31 passage 1060 and a secondary passage 1061, which 32 departs from the primary passage 1060 on one side of 1 the valve 1022 and rejoins the primary passage 1060 2 on the other side of the valve 1022.

4 Production fluids pass through the choke 1030 and are diverted by the valve 1022 and the seal 1045 6 into the axial annular passage 1047 of the diverter 7 assembly 1004 to an outlet 1044. They are then 8 typically processed by a processing apparatus, as 9 described above, and then they are returned to the bore 1049 of the diverter assembly 1004, from where 11 they pass through the secondary passage 1061, back 12 into the primary passage 1060 and out of the outlet 13 1012.
l4 Fig 29 shows a modified version of the Fig 28 16 apparatus, in which like parts are designated by the 17 same reference number with a prime. In this 18 embodiment, the secondary passage 1061' does not 19 rejoin the primary passage 1060'; instead the secondary passage 1061' leads directly to the outlet 21 1012'. This embodiment works in the same way as the 22 Fig 6 embodiment.

24 The embodiments of Figs 28 and 29 could be modified for use with a conventional Christmas tree by 26 incorporating the diverter assembly 1004, 1004' into 27 further pipework attached to the tree, instead of 28 within an extension branch of the tree.

Fig 30 illustrates an alternative method of using 31 the flow diverter assemblies in the recovery of 32 fluids from multiple wells. The flow diverter 1 assemblies can be any of the ones shown in the 2 previously illustrated embodiments, and are not 3 shown in detail in this Figure; for this example, 4 the flow diverter assemblies are the production flow diverter assemblies of Fig 23.

7 A first diverter assembly 704 is connected to a 8 branch of a first production well A. The diverter 9 assembly 704 comprises a conduit (not shown) sealed within the bore of a choke body to provide a first 11 flow region inside the bore of the conduit and a 12 second flow region in the annulus between the 13 conduit and the bore of the choke body. It is 14 emphasised that the diverter assembly 704 is the same as the diverter assembly 604 of Fig 23; however 16 it is being used in a different way, so some outlets 17 of Fig 23 correspond to inlets of Fig 30 and vice 18 versa.

The bore of the conduit has an inlet 712 and an 21 outlet 746 (inlet 712 corresponds to outlet 612 of 22 Fig 23 and outlet 746 corresponds to inlet 646 of 23 Fig 23). The inlet 712 is in communication with an 24 inlet header 701. The inlet header 701 may contain produced fluids from several other production wells 26 (not shown) .

28 The annular passage between the conduit and the 29 choke body is in communication with the production wing branch of the tree of the first well A, and 31 with the outlet 744 (which corresponds to the outlet 32 644 in Fig 23).

2 Likewise, a second diverter assembly 714 is 3 connected to a branch of a second production well B.
4 The second diverter assembly 714 is the same as the first diverter assembly 704, and is located in a 6 production wing branch in the same way. The bore of 7 the conduit of the second diverter assembly has an 8 inlet 756 (corresponding to the inlet 646 in Fig 23) 9 and an outlet 722 (corresponding to the outlet 612 of Fig 23). The outlet 722 is connected to an 11 output header 703. The output header 703 is a 12 conduit for conveying the produced fluids to the 13 surface, for example, and may also be fed from 14 several other wells (not shown).
16 The annular passage between the conduit and the 17 inside of the choke body connects the production 18 wing branch to an outlet 754 (which corresponds to 19 the outlet 644 of Fig 23).
21 The outlets 746, 744 and 754 are all connected via 22 tubing to the inlet of a pump 750. Pump 750 then 23 passes all of these fluids into the inlet 756 of the 24 second diverter assembly 714. Optionally, further fluids from other wells (not shown) are also pumped 26 by pump 750 and passed into the inlet 756.

28 In use, the second diverter assembly 714 functions 29 in the same way as the diverter assembly 604 of the Fig 23 embodiment. Fluids from the production bore 31 of the second well B are diverted by the conduit of 32 the second diverter assembly 714 into the annular 1 passage between the conduit and the inside of the 2 choke body, from where they exit through outlet 754, 3 pass through the pump 750 and are then returned to 4 the bore of the conduit through the inlet 756. The returned fluids pass straight through the bore of 6 the conduit and into the outlet header 703, from 7 where they are recovered.

9 The first diverter assembly 704 functions differently because the produced fluids from the 11 first well 702 are not returned to the first 12 diverter assembly 704 once they leave the outlet 744 13 of the annulus. Instead, both of the flow regions 14 inside and outside of the conduit have fluid flowing in the same direction. Inside the conduit (the 16 first flow region), fluids flow upwards from the 17 inlet header 701 straight through the conduit to the 18 outlet 746. Outside of the conduit (the second flow 19 region), fluids flow upwards from the production bore of the first well 702 to the outlet 744.

22 both streams of upwardly flowing fluids combine with 23 fluids from the outlet 754 of the second diverter 24 assembly 714, from where they enter the pump 750, pass through the second diverter assembly into the 26 outlet header 703, as described above.

28 It should be noted that the tree 601 is a 29 conventional tree but the invention can also be used with horizontal trees.

1 One or both of the flow diverter assemblies of the 2 Fig 23 embodiment could be located within the 3 production bore and/or the annulus bore, instead of 4 within the production and annular choke bodies.

6 The processing apparatus 700 could be one or more of 7 a wide variety of equipment. For example, the 8 processing apparatus 700 could comprise any of the 9 types of equipment described above with reference to 10 Fig 17.

l2 The above described flow paths could be completely 13 reversed or redirected for other process 14 requirements.
16 Fig 31 shows a further embodiment of a diverter 17 assembly 1110 which is attached to a choke body 18 1112, which is located in the production wing branch 19 1114 of a christmas tree 1116. The production wing branch 1114 has an outlet 1118, which is located 21 adjacent to the choke body 1112. The diverter 22 assembly 1110 is attached to the choke body 1112 by 23 a clamp 1119. A first valve V1 is located in the 24 central bore of the christmas tree and a second 25~ valve V2 is located in the production wing branch 26 1114.

28 The choke body 1112 is a standard subsea choke body 29 from which the original choke has been removed. The choke body 1112 has a bore which is in fluid 31 communication with the production wing branch 1114.
32 The upper end of the bore of the choke body 1112 1 terminates in an aperture in the upper surface of 2 the choke body 1112. The lower end of the bore of 3 the choke body communicates with the bore of the 4 production wing branch 1114 and the outlet 1118.
6 The diverter assembly 1110 has a cylindrical housing 7 1120, which has an interior axial passage 1122. The 8 lower end of the axial passage 1122 is open; i.e. it 9 terminates in an aperture. The upper end of the axial passage 1122 is closed, and a lateral passage 11 1126 extends from the upper end of the axial passage 12 1122 to an outlet 1124 in the side wall of the 13 cylindrical housing 1120.

The diverter assembly 1110 has a stem 1128 which 16 extends from the upper closed end of the axial 17 passage 1122, down through the axial passage 1122, 18 where it terminates in a plug 1130. The stem 1128 19 is longer than the housing 1120, so the lower end of the stem 1128 extends beyond the lower end of the 21 housing 1120. The plug 1130 is shaped to engage a 22 seat in the choke body 1112, so that it blocks the 23 part of the production wing branch 1114 leading to 24 the outlet 1118. The plug therefore prevents fluids from the production wing branch 1114 or from the 26 choke body 1112 from exiting via the outlet 1118.
27 The plug is optionally provided with a seal, to 28 ensure that no leaking of fluids can take place.

Before fitting the diverter assembly 1110 to the 31 tree 1116, a choke is typically present inside the 32 choke body 1112 and the outlet 1118 is typically 1 connected to an outlet conduit, which conveys the 2 produced fluids away e.g. to the surface. Produced 3 fluids flow through the bore of the Christmas tree 4 1116, through valves V1 and V2, through the production wing branch 1114, and out of outlet 1118 6 via the choke.

8 The diverter assembly 1110 can be retrofitted to a 9 well by closing one or both of the valves V1 and V2 of the Christmas tree 1116. This prevents any 11 fluids leaking into the ocean whilst the diverter 12 assembly 1110 is being fitted. The choke (if 13 present) is removed from the choke body 1112 by a 14 standard removal procedure known in the art. The diverter assembly 1110 is then clamped onto the top 16 of the choke body 1112 by the clamp 1119 so that the 17 stem 1128 extends into the bore of the choke body 18 1112 and the plug 1130 engages a seat in the choke 19 body 1112 to block off the outlet 1118. Further pipework (not shown) is then attached to the outlet 21 1124 of the diverter assembly 1110. This further 22 pipework can now be used to divert the fluids to any 23 desired location. For example, the fluids may be 24 then diverted to a processing apparatus, or a component of the produced fluids may be diverted 26 into another well bore to be used as injection 27 fluids.

29 The valves V1 and V2 are now re-opened which allows the produced fluids to pass into the production wing 31 branch 1114 and into the choke body 1112, from where 32 they are diverted from their former route to the 1 outlet 1118 by the plug 1130, and are instead 2 diverted through the diverter assembly 1110, out of 3 the outlet 1124 and into the pipework attached to 4 the outlet 1124.
6 Although the above has been described with reference 7 to recovering produced fluids from a well, the same 8 apparatus could equally be used to inject fluids 9 into a well, simply by reversing the flow of the fluids. Injected fluids could enter the diverter 11 assembly 1110 at the aperture 1124, pass through the 12 diverter assembly 1110, the production wing branch 13 14 and into the well. Although this example has 14 described a production wing branch 1114 which is connected to the production bore of a well, the 16 diverter assembly 1110 could equally be attached to 17 an annulus choke body connected to an annulus wing 18 branch and an annulus bore of the well, and used to 1 9 divert fluids flowing into or out from the annulus 2 0 bore. An example of a diverter assembly attached to 2 1 an annulus choke body has already been described 22 with reference to Fig 23.

24 Fig 32 shows an alternative embodiment of a diverter assembly 1110' attached to the Christmas tree 1116, 26 and like parts will be designated by like numbers 27 having a prime. The Christmas tree 1116 is the same 28 Christmas tree 1116 as shown in Fig 31, so these 29 reference numbers are not primed.
31 The housing 1120' in the diverter assembly 1110' is 32 cylindrical with an axial passage 1122'. However, 1 in t his embodiment, there is no lateral passage, and 2 the upper end of the axial passage 1122' terminates 3 in an aperture 1130' in the upper end of the housing 4 1120', so that the upper end of the housing 1120' is open. Thus, the axial passage 1122' extends all of 6 the way through the housing 1120' between its lower 7 and upper ends. The aperture 1130' can be connected 8 to external pipework (not shown).

Fig 33 shows a further alternative embodiment of a 11 dive rter assembly 1110" , and like parts are 12 designated by like numbers having a double prime.
13 Thi s Figure is cut off after the valve V2; the rest 14 of t he Christmas tree is the same as that of the previous two embodiments. Again, the Christmas tree 16 of t his embodiment is the same as those of the 17 previous two embodiments, and so these reference 18 numb ers are not primed.

The housing 1120" of the Fig 33 embodiment is 21 sub s tantially the same as the housing 1120' of the 22 Fig 32 embodiment. The housing 1120" is 23 cyl.i ndrical and has an axial passage 1122"
24 extending therethrough between its lower and upper ends, both of which are open. The aperture 1130"
26 can be connected to external pipework (not shown).

28 The housing 1120" is provided with an extension 29 port ion in the form of a conduit 1132" , which ext a nds from near the upper end of the housing 31 1120 " , down through the axial passage 1122" to a 32 point beyond the end of the housing 1120" . The 1 conduit 1132" is therefore internal to the housing 2 1120" , and defines an annulus 1134" between the 3 conduit 1132" and the housing 1120" .

5 The lower end of the conduit 1132" is adapted to 6 fit inside a recess in the choke body 1112, and is 7 provided with a seal 1136, so that it can seal 8 within this recess, and the length of conduit 1132"
9 is determined accordingly.
11 As shown in Fig 33, the conduit 1132" divides the 12 space within the choke body 1112 and the diverter 13 assembly 1110" into two distinct and separate 14 regions. A first region is defined by the bore of the conduit 1132" and the part of the production 16 wing bore 1114 beneath the choke body 1112 leading 17 to the outlet 1118. The second region is defined by 18 the annulus between the conduit 1132" and the 19 housing 1120" /the choke body 1112. Thus, the conduit 1132" forms the boundary between these two 21 regions, and the seal 1136 ensures that there is no 22 fluid communication between these two regions, so 23 that they are completely separate. The Fig 33 24 embodiment is similar to the embodiments of Figs 20 and 21, with the difference that the Fig 33 annulus 26 is closed at its upper end.

28 In use, the embodiments of Figs 32 and 33 may 29 function in substantially the same way. The valves V1 and V2 are closed to allow the choke to be 31 removed from the choke body 1112 and the diverter 32 assembly 1110', 1110" to be clamped on to the choke 1 body 1112, as described above with reference to Fig 2 31. Further pipework leading to desired equipment 3 is then attached to the aperture 1130', 1130" . The 4 diverter assembly 1110', 1110" can then be used to divert fluids in either direction therethrough 6 between the apertures 1118 and 1130', 1130" .

8 In the Fig 32 embodiment, there is the option to 9 divert fluids into or from the well, if the valves V1, V2 are open, and the option to exclude these 11 fluids by closing at least one of these valves.

13 The embodiments of Figs 32 and 33 can be used to 14 recove r fluids from or inject fluids into a well.
Any of the embodiments shown attached to a 16 production choke body may alternatively be attached 17 to an annulus choke body of an annulus wing branch 18 leading to an annulus bore of a well.

In the Fig 33 embodiment, no fluids can pass 21 directly between the production bore and the 22 aperture 1118 via the wing branch 1114, due to the 23 seal 1136. This embodiment may optionally function 24 as a pipe connector for a flowline not connected to the well. For example, the Fig 33 embodiment could 26 simply be used to connect two pipes together.
27 Alternatively, fluids flowing through the axial 28 passage 1132" may be directed into, or may come 29 from, the well bore via a bypass line. An example of such an embodiment is shown in Fig 34.

1 Fig 34 shows the Fig 33 apparatus attached to the 2 choke body 1112 of the tree 1116. The tree 1116 has 3 a cap 1140, which has an axial passage 1142 4 extending therethrough. The axial passage 1142 is aligned with and connects directly to the production 6 bore of the tree 1116. A first conduit 1146 7 connects the axial passage 1142 to a processing 8 apparatus 1148. The processing apparatus 1148 may 9 comprise any of the types of processing apparatus described in this specification. A second conduit 11 1150 connects the processing apparatus 1148 to the 12 aperture 1130" in the housing 1120" . Valve V2 is 13 shut and valve V1 is open.

To recover fluids from a well, the fluids travel up 16 through the production bore of the tree; they cannot 17 pass into through the wing branch 1114 because of 18 the V2 valve which is closed, and they are instead 19 divert ed into the cap 1140. The fluids pass through the conduit 114, through the processing apparatus 21 1148 and they are then conveyed to the axial passage 22 1122' by the conduit 1150. The fluids travel down 23 the axi al passage 1122' to the aperture 1118 and are 24 recovered therefrom via a standard outlet line connect ed to this aperture.

27 To inject fluids into a well, the direction of flow 28 is reversed, so that the fluids to be injected are 29 passed into the aperture 1118 and are then conveyed through the axial passage 1122', the conduit 1150, 31 the~pro cessing apparatus 1148, the conduit 1146, the 1 cap 1140 and from the cap directly into the 2 production bore of the tree and the well bore.

4 This embodiment therefore enables fluids to travel between the well bore and the aperture 1118 of the 6 wing branch 1114, whilst bypassing the wing branch 7 1114 itself. This embodiment may be especially in 8 well s in which the wing branch valve V2 has stuck in 9 the closed position. In modifications to this embodiment, the first conduit does not lead to an 11 aperture in the tree cap. For example, the first 12 conduit 1146 could instead connect to an annulus 13 branch and an annulus bore: a crossover port could 14 then connect the annulus bore to the production bore, if desired. Any opening into the tree 16 manifold could be used. The processing apparatus 17 could comprise any of the types described in this 18 specsfication, or could alternatively be omitted 19 completely.
21 These embodiments have the advantage of providing a 22 safe way to connect pipework to the well, without 23 having to disconnect any of the existing pipework, 24 and without a significant risk of fluids leaking from the well into the ocean.

27 The uses of the invention are very wide ranging.
28 The further pipework attached to the diverter 29 assembly could lead to an outlet header, an inlet heade r, a further well, or some processing apparatus 31 (not shown). Many of these processes may never have 32 been envisaged when the christmas tree was 1 originally Installed, and the invention provides the 2 advantage of being able to adapt these existing 3 trees in a 1 ow cost way while reducing the risk of 4 leaks.
6 Fig. 35 shows an embodiment of the invention 7 especially adapted for injecting gas into the 8 produced fluids. A wellhead cap 40e is attached to 9 the top of a horizontal tree 400. The wellhead cap 40e has plugs 408, 409; an inner axial passage 402;
11 and an inner lateral passage 404, connecting the 12 inner axial passage 402 with an inlet 406. One end 13 of a coil tubing insert 410 is attached to the inner 14 axial passage 402. Annular sealing plug 412 is provided to seal the annulus between the top end of 16 coil tubing insert 410 and inner axial passage 402.
17 Coil tubing insert 410 of 2 inch (5Cm) diameter 18 extends downwards from annular sealing plug 412 into 19 the producti on bore 1 of horizontal Christmas tree 400.

22 In use, inlet 406 is Connected to a gas injection 23 line 414. Gas is pumped from gas injection line 414 24 into Christmas tree Cap 40e, and is diverted by plug 408 down int o coil tubing insert 410; the gas mixes 26 with the pro duction fluids in the well. The gas 27 reduces the density of the produced fluids, giving 28 them "lift". The mixture of oil well fluids and gas 29 then travels up production bore 1, in the annulus between production bore 1 and Coil tubing insert 31 410. This mixture is prevented from travelling into 1 cap 40e by plug 408; instead it is diverted into 2 branch 10 for recovery therefrom.

4 This embodiment therefore divides the production 5 bore into two separate regions, so that the 6 production bore can be used both for injecting gases 7 and recovering fluids. This is in contrast to known 8 methods of inject fluids via an annulus bore of the 9 well, which cannot work if the annulus bore becomes 10 blocke d. In the conventional methods, which rely on 11 the annulus bore, a blocked annulus bore would mean 12 the entire tree would have to be removed and 13 replaced, whereas the present embodiment provides a 14 quick and inexpensive alternative.
16 In this embodiment, the diverter assembly is the 17 coil tubing insert 410 and the annular sealing plug 18 412.

Fig. 36 shows a more detailed view of the Fig. 35 21 apparatus; the apparatus and the function are the 22 same, and like parts are designated by like numbers.

24 Fig. 37 shows the gas injection apparatus of Fig. 35 combined with the flow diverter assembly of Fig 3 26 and like parts in these two drawings are designated 27 here with like numbers. In this figure, outlet 44 28 and inlet 46 are also connected to inner axial 29 passage 402 via respective inner lateral passages.
31 A booster pump (not shown) is connected between the 1 outlet 44 and the inlet 46. The top end of conduit 2 42 is sealingl y connected at annularseal 416 to 3 inner axial passage 402 above inlet 46 and below 4 outlet 44. Annular sealing plug 412 of coil tubing insert 410 lie s between outlet 44 and gas inlet 406.

7 In use, as in the Fig. 35 embodiment, gas is 8 injected throe gh inlet 406 into christmas tree cap 9 40e and is diverted by plug 408 and annular sealing plug 412 into coil tubing insert 410. The gas 11 travels down t he coil tubing insert 410, which 12 extends into t he depths of the well. The gas 13 combines with the well fluids at the bottom of the 14 wellbore, giving the fluids "lift" and making them easier to pump. The booster pump between the outlet 16 44 and the inl et 46 draws the "gassed" produced 17 fluids up the annulus between the wall of production 18 bore 1 and coi 1 tubing insert 410. When the fluids 19 reach conduit 42, they are diverted by seals 43 into the annulus between conduit 42 and coil tubing 21 insert 410. T he fluids are then diverted by annular 22 sealing plug 412 through outlet 44, through the 23 booster pump, and are returned through inlet 4~. At 24 this point, th a fluids pass into the annulus created between the production bore/tree cap inner axial 26 passage and conduit 42, in the volume bounded by 27 seals 416 and 4 3. As the fluids cannot pass seals 28 416, 43, they a re diverted out of the Christmas tree 29 through valve 12 and branch 10 for recovery.
31 This embodiment is therefore similar to the Fig 35 32 embodiment, additionally allowing for the diversion 1 of fluids to a processing apparatus before returning 2 them to the tree for recovery from the outlet of the 3 branch 10. In this embodiment, the conduit 42 is a 4 first diverts r assembly, and the coil tubing insert 410 is a second diverter assembly. The conduit 42, 6 which forms a secondary diverter assembly in this 7 embodiment, does not have to be located in the 8 production bo re. Alternative embodiments may use 9 any of the ofher forms of diverter assembly described in this application (e. g. a diverter 11 assembly on a choke body) in conjunction with the 12 coil tubing insert 410 in the production bore.

14 Modifications and improvements may be incorporated without depart ing from the scope of the invention.
16 For example, a s stated above, the diverter assembly 17 could be attached to an annulus choke body, instead 18 of to a production choke body.

It should be noted that the flow diverters of Figs 21 20, 21, 22, 2 4, 26 to 29 and 32 could also be used 22 in the Fig 34 method; the Fig 33 embodiment shown in 23 Fig 34 is just one possible example.

Likewise, the methods shown in Fig 30 were described 26 with reference to the Fig 23 embodiment, but these 27 could be accomplished with any of the embodiments 28 providing two separate flowpaths; these include the 29 embodiments of Figs 2 to 6, 17, 20 to 22 and 26 to 29. With modifications to the method of Fig 30, so 31 that fluids from the well A are only required to 32 flow to the outlet header 703, without any addition 1 of fluids from the inlet header 701, the embodiments 2 only providing a single flowpath (Figs 31 and 32) 3 could also be used. Alternatively, if fluids were 4 only needed to be diverted between the inlet header 701 and the outlet header 703, without the addition 6 of any fluids from well A, the Fig 33 embodiment 7 could also be used. Similar considerations apply to 8 well B.

The method of Fig 18, which involves recovering 11 fluids from a first well and injecting at least a 12 portion of these fluids into a second well, could 13 likewise be achieved with any of the two-flowpath 14 embodiments of Figs 3 to 6, 17, 20 to 22 and 26 to 29. With modifications to this method (e.g. the 16 removal of the conduit 234), the single flowpath 17 embodiments of Figs 31 and Figs 32 could be used for 18 the injection well 330. Such an embodiment is shown 19 in Fig 38, which shows a first recovery well A and a second injection well B. Wells A and B each have a 21 tree and a diverter assembly according to Fig 3l.
22 Fluids are recovered from well A via the diverter 23 assembly; the fluids pass into a conduit C and enter 24 a processing apparatus P. The processing apparatus includes a separating apparatus and a fluid riser R.
26 The processing apparatus separates hydrocarbons from 27 the recovered fluids and sends these into the fluid 28 riser R for recovery to the surface via this riser.
29 The remaining fluids are diverted into conduit D
which leads t o the diverter assembly of the 31 injection well B, and from there, the fluids pass 32 into the well bore. This embodiment allows 1 diversion of fluid s whilst bypassing the export line 2 which is normally connected to outlets 1118.

4 Therefore, with th Zs modification, single flowpath embodiments could also be used for the production 6 well. This method can therefore lae achieved with a 7 diverter assembly 1 ocated in the production/annulus 8 bore or in a wing branch, and with most of the 9 embodiments of diverter assembly described in this l0 specification.

12 Likewise, the method of Fig 23, in which recovery 13 and injection occur in the same well, could be 14 achieved with the flow diverters of Figs 2 to 6 (so that at least one of the flow diverters is located 16 in the production bore/annulus bore). A first 17 diverter assembly could be located in the production 18 bore and a second diverter assembly could be 19 attached to the annulus choke, for example. Further alternative embodiments (not shown) may have a 21 diverter assembly i_n the annulus bore, similar to 22 the embodiments of Figs 2 to 6 in the production 23 bore.

The Fig 23 method, in which recovery and injection 26 occur in the same ~,rell, could also be achieved with 27 any of the other di verter assemblies described in 28 the application, including the diverter assemblies 29 which do not provide two separate flowpaths. An example of one such modified method is shown in Fig 31 39. This shows the same tree as Fig 23, used with 32 two Fig 31 diverter assemblies. In this modified 1 method, none of the fluids recovered from the first 2 diverter assembly 640 connected to the production 3 bore 602 are returned to the first diverter assembly 4 640. Instead, fluids are recovered from the 5 production bore, are diverted through the first 6 diverter assembly 640 into a conduit 690, which 7 leads to a processing apparatus 700. The processing 8 apparatus 700 could be any of the ones described in 9 this application. In this embodiment, the 10 processing apparatus 700 including both a separating 11 apparatus and a fluid riser R to the surface. The 12 apparatus 700 separates hydrocarbons from the rest 13 of the produced fluids, and the hydrocarbons are 14 recovered t o the surface via the fluid riser R, 15 whilst the rest of the fluids are returned to the 16 tree via conduit 696. These fluids are injected 17 into the annulus bore via the second diverter 18 assembly X80.

20 Therefore, as illustrated by the examples in Figs 38 21 and 39, the methods of recovery and injection are 22 not limited to methods which include the return of 23 some of the recovered fluids to the diverter 24 assembly used in the recovery, or return of the 25 fluids to a second portion of a first flowpath.

27 All of the diverter assemblies shown and described 28 can be used for both recovery of fluids and 29 injection of fluids by reversing the flow direction.
31 Any of the embodiments which are shown connected to 32 a production wing branch could instead be connected 1 to an annul us wing branch, or another branch of the 2 tree. The embodiments of Figs 31 to 34 could be 3 connected t o other parts of the wing branch, and are 4 not necessarily attached to a choke body. For example, these embodiments could be located in 6 series with a choke, at a different point in the 7 wing branch, such as shown in the embodiments of 8 Figs 26 to 29.

Claims

92

1. A method of diverting fluids in a well, comprising: connecting a diverter assembly to a branch of a tree, forming a first flowpath between a bore of the tree and a processing apparatus, locating a part of the diverter assembly in a bore of the branch to provide a second flowpath between the processing apparatus and an outlet of the branch; and diverting the fluids between the bore and branch outlet through the processing apparatus.

2. A method as claimed in claim 1, wherein the diverter assembly is attached to a choke body.

3. A method as claimed in claim 1 or claim 2, for recovering produced fluids from the well for processing in the processing apparatus.

4. A method as claimed in any one of claims 1-3, for injecting fluids into the well through the branch outlet.

5. A method as claimed in any one of claims 1-4, also including injecting fluids provided by an external fluid line into the well.

6. A method as claimed in any one of claims 1-5, wherein the diverter assembly provides two separate regions within the diverter assembly, and the method includes the step of passing fluids through at least one of these regions.

7. A method as claimed in claim 6, wherein the fluids are passed through one of the first and second regions in a first direction and subsequently at least a portion of these fluids are then passed through the other of the first and the second regions in an opposite direction.

8. A method as claimed in claim 6, wherein a first set of fluids is passed through the first region and a second set of fluids is passed through the second region.

9. A method as claimed in any one of claims 6-8, wherein the method includes the step of processing the fluids in the processing apparatus located between the first and second regions in a housing of the diverter assembly.

10. A method as claimed in claim 9, wherein the processing apparatus is chosen from at least one of: a pump; a process fluid turbine; injection apparatus; chemical injection apparatus; a fluid riser; measurement apparatus; temperature measurement apparatus; flow rate measurement apparatus; constitution measurement apparatus; consistency measurement apparatus; gas separation apparatus; water separation apparatus; solids separation apparatus;
and hydrocarbon separation apparatus.

11. A method as claimed in any one of claims 1-10, including the step of recovering fluids from a first well and re-injecting at least a portion of the recovered fluids into a second well.

12. A method as claimed in claim 11, wherein a first diverter assembly is connected to the first well, and a second diverter assembly is connected to the second well, and wherein the fluids are recovered from the first well via the first diverter assembly and are re-injected into the second well via the second diverter assembly.

13. A method as claimed in any one of claims 1-10, including the step of recovering fluids from a well through the branch, processing the fluids, and the step of injecting the processed fluids into the well.

14. A method as claimed in claim 13, wherein recovery occurs through a first diverter assembly and injection occurs simultaneously through a second diverter assembly.

15. A method as claimed in claim 13 or claim 14, wherein the first diverter assembly is connected to a first branch of the tree and a second diverter assembly is connected to a second branch of the tree, and the recovered fluids are recovered via one of the diverter assemblies and the injection fluids are injected via the other of the diverter assemblies.

16. A method as claimed in any one of claims 13-15, wherein at least some of the recovered fluids are re-injected into the well.

17. A method as claimed in claim 16, wherein the recovered fluids are processed before they are re- injected into the well.

18. A method as claimed in any one of claims 1-17, wherein a first set of fluids are recovered from a first well via a first diverter assembly and combined with other fluids in a communal conduit, and the combined fluids are then diverted into an export line via a second diverter assembly connected to the second well.

19. A method as claimed in any one of claims 1-18, including the step of diverting fluids between the diverter assembly and the well bore whilst bypassing at least a portion of the branch.

20. A method as claimed in claim 19, wherein the fluids are diverted via a tree cap.

21. A method as claimed in any one of claims 1-20, wherein a gathering manifold communicates with a branch of a tree.

22. A diverter assembly for a production tree having a tree body with a bore and a lateral production port extending from the bore, the diverter assembly comprising:
a branch extending from the tree and comprising a branch bore aligned with the lateral production port and a diverter bore extending from the branch bore;
the branch comprising a production wing valve that is located between the tree body and the diverter bore; and a diverter disposed on the branch at the diverter bore.

23. The diverter assembly of claim 22 further including a choke disposed on an end of the branch.

24. The diverter assembly of claim 22 further including a processing apparatus communicating with the diverter.

25. The diverter assembly of claim 24 wherein the processing apparatus is selected from the group consisting of at least one of a pump, process fluid turbine, gas injection apparatus, steam injection apparatus, chemical injection apparatus, materials injection apparatus, gas separation apparatus, water separation apparatus, sand/debris separation apparatus, hydrocarbon separation apparatus, fluid measurement apparatus, temperature measurement apparatus, flow rate measurement apparatus, constitution measurement apparatus, consistency measurement apparatus, chemical treatment apparatus, pressure boosting apparatus, and water electrolysis apparatus.

26. The diverter assembly of claim 22 wherein the diverter bore is a choke body disposed on the branch.

27. The diverter assembly of claim 26, further including a processing apparatus and wherein the diverter has a diverter passage, the processing apparatus communicating with the diverter passage, and the diverter being mountable on the choke body to allow flow between the choke body and the processing apparatus through the diverter passage.

28. The diverter assembly of claim 26 wherein the choke body is disposed on the branch and is adapted for diverting flow between a tree bore and a flowline, comprising:
a tubular body comprising:
a first bore in fluid communication with the flowline;
a second bore in fluid communication with the tree bore; and a third bore comprising a standard interface capable of receiving and connecting a choke insert or a flow insert.

29. The diverter assembly of claim 26 wherein the branch is connected to an export line and the choke body comprises:
a lateral branch passage in fluid communication in use with the branch and tree bore;
an export line passage in fluid communication in use with the export line; and a choke insert passage adapted to receive a choke insert of a choke; and the choke insert passage forming a fluid flow path therethrough to flow fluids in use through the choke insert passage into or from either the branch or the export line.

30. The diverter assembly of claim 26 wherein the choke body comprises a production bore, a flowline bore, and a choke insert bore, the choke insert bore being adapted to receive an insert of a choke to restrict flow through the production bore and flowline bore, and a flow insert comprising a seal-bearing stinger with an internal bore receivable by the choke insert bore, the seal-bearing stinger permitting flow through the seal-bearing stinger and into the choke body.

31. The diverter assembly of claim 22 further including a flow insert for connection to the diverter bore, the flow insert being receivable by the diverter bore.

32. The diverter assembly of claim 22 further including a conduit received by the diverter bore and forming the internal passage.

33. The diverter assembly of claim 32 wherein the conduit has seals to seal in use with the branch.

34. The diverter assembly of claim 32 wherein the conduit is a stab to stab in use into the branch.

35. The diverter assembly claim 32 wherein the conduit has seals around one end.

36. The diverter assembly of claim 32 wherein the conduit comprises a seal-bearing stinger with the internal passage, the seal-bearing stinger permitting flow through the seal-bearing stinger.

37. The diverter assembly of claim 36 wherein the seal-bearing stinger comprises seals that sealingly engage an outside end of the stinger.

38. The diverter assembly of claim 32, wherein the conduit is in fluid communication with a processing apparatus for flowing fluids.

39. The diverter assembly of claim 22 wherein:
the branch is connected to an export line;
a choke is coupled to the top of the choke body;
the choke having an inlet passage and an outlet passage;
the inlet passage or outlet passage being connected to a processing apparatus;
and the other of the inlet passage or outlet passage being in fluid communication with the branch and/or export line.

40. The diverter assembly as claimed in claim 22 wherein the branch bore forms part of a first flowpath to and from the tree bore;
a choke body is disposed on the branch, the choke body having a choke bore communicating with the branch bore to form a part of the first flowpath or a second flowpath with an export line; and the diverter having an internal passage, a part of the diverter being locatable in the diverter bore either in the lateral branch or choke body, the internal passage communicating with either the first or second flowpaths via the diverter bore.

41. The diverter assembly tree of claim 40 wherein the diverter bore is located in the lateral branch.

42. The diverter assembly tree of claim 40 wherein the diverter bore is located in the choke body.

43. The diverter assembly as claimed in claim 22 adapted for diverting flow between the tree bore and a flowline, comprising:
a tubular body comprising:
a first port in fluid communication with the tree bore;
a second port in fluid communication with the flowline; and a third port capable of receiving a choke insert; and a flow insert receivable in the third port and having an axial bore for flow therethrough, the flow insert enabling flow to be diverted from between the tree bore and the flowline to between the flow insert axial bore and flowline.

44. The diverter assembly of claim 43 wherein the third port is in fluid communication with a processing apparatus.

45. The diverter assembly as claimed in claim 22 including a choke body having a bore, the choke body being part of the branch, the choke body bore forming a flowpath between the tree bore and a flowline, comprising:
a housing comprising an internal passage;
the housing being mountable to the choke body to divert flow through the flowpath such that the internal passage is in fluid communication with the choke body bore to form a flow passage with the flowline;
the housing internal passage forming part of the flow passage in communication with the tree bore; and an insert disposed between the housing and choke body.

46. The diverter assembly as claimed in claim 22 further comprising a choke body that is part of the branch, the choke body comprising a bore forming part of a first flowpath in communication with the tree bore;
a diverter housing comprising an internal passage;

the diverter housing being releasably mountable to the choke body such that the internal passage is in fluid communication with the choke body bore; and the diverter housing internal passage forming part of a second flowpath, alternative to the first flowpath, in communication with the production bore.

47. The diverter assembly as claimed in claim 22 further comprising:
a choke body comprising:
a choke body first bore adapted for fluid communication with the branch;
a choke body second bore adapted to receive a choke; and a choke body export bore;
the choke body first bore in a first configuration forming part of a first flowpath in communication with the tree bore and the choke body export bore when the choke is disposed on the choke body; and a diverter housing being releasably mountable to the choke body in a second configuration with an internal passage of the diverter housing being in fluid communication with the choke body second bore and choke body export bore, the diverter housing forming a barrier between the choke body first bore and the choke body export bore.

48. The diverter assembly as claimed in claim 22, wherein the branch comprises a branch outlet; and the diverter is coupled to the branch, wherein the diverter comprises a first fluid path to a diverter outlet and a second fluid path from a diverter inlet to the branch outlet.

49. The diverter assembly as claimed in claim 22 wherein a bypass conduit is coupled to the diverter and the bypass conduit is configured to couple to the tree bore whilst bypassing at least a part of the branch.

50. The diverter assembly of claim 49 further including a pump connected to the bypass conduit.

51. The diverter assembly of claim 49 further including a pump adapted to be disposed within the tree.

52. The diverter assembly of claim 49, wherein the bypass conduit connects the diverter assembly to the tree bore via an aperture in a cap.

53. The diverter assembly as claimed in claim 22 wherein the branch has a branch outlet and further including a choke mounted on the branch between the diverter bore and the branch outlet, the choke having an open position to allow flow through the branch bore and a closed position to close flow through the branch bore.

54. The assembly of claim 53 further comprising a conduit communicating with the diverter bore to form a flowpath extending from an apparatus and through the conduit and diverter bore and into at least a portion of the branch bore to flow fluids or materials into or from the at least a portion of the branch bore.

55. The assembly of claim 54 wherein the branch outlet communicates with a bore of another well.

56. A diverter assembly as claimed in claim 22 wherein the diverter includes a housing having an internal passage and an axial insert portion, wherein the axial insert portion is received by the diverter bore in the branch and extends into the branch bore of the branch to connect to the branch of the tree.

57. A diverter assembly as claimed in claim 56, wherein the axial insert portion extends through the diverter bore into sealing engagement with the branch.

58. A diverter assembly as claimed in claim 56 or claim 57, wherein the diverter bore is located in a choke body disposed in the branch.

59. A diverter assembly as claimed in any one of claims 56-58, wherein the internal passage and the axial insert portion form two separate regions within the diverter assembly.

60. A diverter assembly as claimed in any one of claims 56-59, wherein the axial insert portion extends through the internal passage.

61. A diverter assembly as claimed in claim 60, wherein the axial insert portion is in the form of a conduit.

62. A diverter assembly as claimed in claim 61, wherein the conduit divides the internal passage into a first region comprising a bore of the conduit and a second region comprising an annulus between the housing and the conduit.

63. A diverter assembly as claimed in claim 61 or claim 62, wherein the conduit is adapted to seal within the inside of the branch to prevent direct fluid communication between the annulus and the bore of the conduit.

64. A diverter assembly as claimed in claim 60, wherein the axial insert portion is in the form of a stem provided with a plug adapted to block an outlet of the branch.

65. A diverter assembly as claimed in any one of claims 56-64, having conduits diverting fluids from a first portion of a first flowpath to a second flowpath, and to divert the fluids from a second flowpath to a second portion of the first flowpath.

66. A diverter assembly as claimed in any one of claims 56-65, including a pump adapted to fit within the bore of the tree.

67. A diverter assembly as claimed in claim 66, wherein the diverter assembly is adapted to divert fluids flowing through a first region of the branch bore, through the pump, and back to a second portion of the branch bore for recovery therefrom via the branch outlet.

68. A diverter assembly as claimed in claim 66 or claim 67, wherein the diverter includes a conduit sealed within the branch bore thereby creating an annulus between the branch bore and the diverter conduit, and is adapted to divert the fluids from the bore through the diverter conduit, and to subsequently divert the fluids out of the diverter conduit, and into the annulus between the diverter conduit and the branch bore.

69. A diverter assembly as claimed in any one of claims 56-68, wherein a gathering manifold communicates with the branch outlet.

70. An assembly having the tree with the branch and the diverter assembly as claimed in any one of claims 56-69.

71. An assembly as claimed in claim 70, wherein the internal passage of the diverter is in communication with the branch bore.

72. An assembly as claimed in claim 70 or claim 71, wherein the internal passage of the diverter is in fluid communication with the branch outlet.

73. An assembly as claimed in any one of claims 70-72, wherein the branch bore has an inlet and wherein the diverter provides a barrier to separate the branch inlet from the branch outlet.

74. An assembly as claimed in any one of claims 70-73, wherein a part of the diverter is sealed inside the branch to prevent fluid communication between two separate regions of the diverter assembly.

75. An assembly as claimed in claim 74, wherein the two separate regions are connected by pipes.

76. An assembly as claimed in any one of claims 70-75, connected to a processing apparatus.

77. An assembly as claimed in claim 76, wherein the processing apparatus is chosen from at least one of: a pump; a process fluid turbine injection apparatus; chemical injection apparatus;
gas injection apparatus; steam injection apparatus; materials injection apparatus; a fluid riser;
process fluid turbine; measurement apparatus; fluid measurement apparatus;
temperature measurement apparatus; flow rate measurement apparatus; constitution measurement apparatus;
consistency measurement apparatus; gas separation apparatus; water separation apparatus;
sand/debris separation apparatus; solids separation apparatus; chemical treatment apparatus;
pressure boosting apparatus; water electrolysis apparatus; and hydrocarbon separation apparatus.

78. An assembly as claimed in any one of claims 70-77, having a first diverter assembly as claimed in any one of claims 56-69 connected to a first branch and a second diverter assembly as claimed in any one of claims 56-69 connected to a second branch.

79. An assembly as claimed in claim 78, wherein the first branch comprises a production wing branch and the second branch comprises an annulus wing branch.

80. An assembly in communication with a well bore, the manifold having a branch and a diverter assembly as claimed in any one of claims 56-69, and a bypass conduit connecting the diverter assembly to the well bore whilst bypassing at least a part of the branch.

81. An assembly as claimed in claim 80, also having a cap, and wherein the bypass conduit connects the diverter assembly to the well bore via an aperture in the cap.

82. An assembly as claimed in claim 80 or claim 81, connected to a processing apparatus.

83. An assembly comprising a first tree as claimed in any one of claims 70-82, and a second tree as claimed in any one of claims 70-82, the first and second trees being connected by at least one flowpath.

84. An assembly as claimed in claim 83, wherein a processing apparatus is located in the at least one flowpath.