Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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1
1 Apparatus and Method for recovering fluids from a
2 well and/or injecting fluids into a well
3
4 The present invention relates to apparatus and
methods for diverting fluids. Embodiments of the
6 invention can be used for recovery and injectiora
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 wellhead
14 after completion of drilling and installation of the
production tubing to control the flow of oil and 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
. 20 (the annulus bore).
=
21
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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.
14
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
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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.
27
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.
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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.
6
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.
12
13 The oil or gas well is typically a subsea well but
14 the invention is equally applicable to topside
wells.
16
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.
23
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
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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.
4
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.
17
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.
23
24 Preferably, the diverter assembly is locatable
within a bore in the branch of the manifold.
26
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.
31
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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.
27
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.
31
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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.
6
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.
12
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.
23
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.
28
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
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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.
4
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.
13
14 The first and second portions of the first flowpath
could comprise the bore and the annulus of a
16 conduit.
17
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.
22
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.
27
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.
31
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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.
6
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.
16
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.
31
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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.
11
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.
22
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.
26
27 Optionally, the manifold is provided with a conduit
28 connecting the first and second regions.
29
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,
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1 and the combined fluids are then diverted into an
2 export line via a second diverter assembly connected
3 to a second well.
4
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.
12
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.
23
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.
31 Typically, the method is for recovering fluids from
32 a well, and includes the final step of diverting
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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.
4
Optionally, the internal passage of the diverter
6 assembly is in communication with the interior of
7 the branch.
8
9 The fluids may be passed in either direction through
the diverter assembly.
11
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.
17
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.
22
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.
31
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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
16 well bore via an aperture in the tree cap.
17
18 Optionally, the first and second regions are
19 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.
23
24 The processing apparatus can be, but is not limited
to, any of those described above.
26
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
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1 flowpath to a second flowpath and diverting the
2 fluids from the second flowpath to a second portion
3 of the first flowpath.
4
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.
16
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).
24
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
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1 hydrocarbons being returned to the first flowpath
2 for recovery therefrom, and the water being returned
3 and injected into the same or a different well.
4
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.
13
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.
24
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.
32
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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.
7
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
27 performed on both fluids being recovered and fluids
28 being injected. Preferred embodiments of the
29 invention enable both recovery and injection to
occur simultaneously in the same well.
31
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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.
8
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.
13
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.
29
Preferably, the method is performed using a diverter
31 assembly according to any aspect of the invention.
32
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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.
12
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.
17
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
21 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.
29
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;
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1 a second well having a second diverter assembly; and
2 a flowpath connecting the first and second diverter
3 assemblies.
4
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.
14
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.
31
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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.
7
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
16
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
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1 fluids are re-injected into the second well via a
2 second diverter assembly.
3
4 Typically, the method also includes the step of
processing the production fluids in a processing
6 apparatus connected between the first and second
7 wells.
8
9 Optionally, the method includes the further step of
returning a portion of the recovered fluids to the
11 first diverter assembly and thereafter recovering
12 that portion of the recovered fluids via the first
13 diverter assembly.
14
According 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 including the step of diverting the fluids between a
19 well bore and a branch outlet whilst bypassing at
least a portion of the branch.
21
22 Such embodiments are useful to divert fluids to a
23 processing 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.
27
28 Optionally, the fluids are diverted via the tree
29 cap.
31 According to a fourteenth aspect of the present
32 invention there is provided a method of injecting
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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.
6
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.
19
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.
29
The diversion of fluids from the first flowpath
31 allows the treatment of the fluids (e.g. with
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1 chemicals) or pressure boosting for more efficient
2 recovery before re-entry into the first flowpath.
3
4 Optionally 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.
8
9 Typically 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 separately, 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 Typically, 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.
24
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.
29
The assembly optionally comprises a conduit capable
31 of insertion into the first flowpath, the assembly
32 having sealing means capable of sealing the conduit
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1 against the wall of the production bore. The
2 conduit 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 entering 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.
14
The assembly and method are typically suited for
16 subsea production wells in normal mode or during
17 well testing, but can also be used in subsea water
18 injection wells, land based oil production injection
19 wells, and geothermal wells.
21 The pump can be powered by high pressure water or by
22 electricity which can be supplied direct from a
23 fixed or floating offshore installation, or from a
24 tethered buoy arrangement, or by high pressure gas
from a local source.
26
27 The cap preferably seals within christmas tree bores
28 above the upper master valve. Seals between the cap
29 and bores of the tree are optionally 0-ring,
inflatable, or preferably metal-to-metal seals. The
31 cap can be retro-fitted very cost effectively with
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1 no disruption to existing pipework and minimal
2 impact on control systems already in place.
3
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.
11
12 The cap is typically capable of retro-fitting to
13 existing 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.
18
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.
22
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.
29
According to a sixteenth aspect of the present
31 invention there is provided a diverter assembly
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1 having a pump according to the fifteenth aspect of
2 the present invention.
3
4 The diverter assembly can be a diverter assembly
according to any aspect of the invention, but it is
6 not limited to these.
7
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.
14
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.
19
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.
26
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 sealed within the bore. Fluid is typically
32 diverted through the bore of the diverter conduit,
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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.
9
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.
21
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 reversed) depending on the design of the embodiment.
28
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.
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1
2 The flow diverter 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 the flow diverter can comprise
12 hydraulic fluid conduits. The pump can optionally
13 be sealed within the conduit.
14
According to a seventeenth aspect of the invention
16 there is provided a method of recovering production
17 fluids from a well having a manifold, the manifold
18 having an integral pump located in a bore of the
19 manifold, and the 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.
23
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 diverter assembly comprises a separator
28 which divides the bore of the tree into two separate
29 regions, and which extends through the tree bore and
into the production zone of the well.
31
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1 Optionally, the at least one diverter assembly
2 comprises a conduit and at least one seal; the
3 conduit optionally comprises a gas injection line.
4
This invention may be used in conjunction with a
6 further diverter 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 bore. Both diverter assemblies may
comprise conduits; one conduit may be arranged
11 concentrically within the other conduit to provide
12 concentric, separate regions within the production
13 bore.
14
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 recovered fluids out of the tree
along an alternative route. The recovered fluids
31 may be diverting the recovered fluids to a
32 processing apparatus and returning at least some of
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these recovered fluids to the tree and recovering these fluids
from a wing branch outlet. The recovered fluids may undergo any
of the processes described in this invention, and may be returned
to the tree for recovery, or not, (e.g. they may be recovered
from a fluid riser) according to any of the described methods and
flowpaths.
In another aspect of the invention a subsea tree assembly is
provided. The subsea tree assembly includes a tree configured to
communicate with a well bore and a pipework with a pipework bore
configured to communicate with the well bore, comprising:
a diverter assembly communicating with the pipework bore via an
access bore in the pipework.
Embodiments of the invention will now be described by way of
example only and with reference to the accompanying drawings in
which: -
Fig. 1 is a side sectional view of a typical production
tree;
Fig. 2 is a side view of the Fig. 1 tree with a diverter
cap in place;
Fig. 3a is a view of the Fig. 1 tree with a second
embodiment of a cap in place;
Fig. 3b is a view of the Fig. 1 tree with a third
embodiment of a cap in place;
Fig. 4a is a view of the Fig. 1 tree with a fourth
embodiment of a cap in place; and
Fig. 4b is a side view of the Fig. 1 tree with a fifth
embodiment of a cap in place.
Fig. 5 shows a side view of a first embodiment of a
diverter assembly having an internal pump; Fig. 6 shows a
similar view of a second embodiment with an internal pump;
Fig. 7 shows a similar view of a third embodiment with an
internal pump;
Fig. 8 shows a similar view of a fourth embodiment with an
internal pump;
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1 Fig. 9 shows a similar view of a fifth
2 embodiment with an internal pump;
3 Figs. 10 and 11 show a sixth embodiment with an
4 internal pump;
Figs. 12 and 13 show a seventh embodiment with
6 an internal pump;
7 Figs. 14 and 15 show 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;
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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;
V 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 production 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 flowpath 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;
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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.
9
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 the 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 production or annulus bores
27 1, 2.
28
29 The flow of fluids through the production and
annulus bores is governed by various valves shown in
31 the typical tree of Fig. 1. The production bore 1
32 has a branch 10 which is closed by a production wing
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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 LPMV 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.
9
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.
17
18 All valves in the tree are typically hydraulically
19 controlled (with the exception of LPMV 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, LPMV 18 and UPMV 17 are opened,
28 PSV 15 is closed, and PWV 12 is opened to open the
29 branch 10 which leads to the pipeline (not shown).
PSV 15 and ASV 32 are only opened if intervention is
31 required.
32
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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.
9
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.
22
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, injecting 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.
31
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1 The processing apparatus 213 could also enable
2 chemicals to be added to the fluids, e.g. viscosity
3 moderators, which thin out the fluids, making them
4 easier to pump, or pipe skin friction moderators,
which minimise the friction between the fluids and
6 the pipes. Further examples of chemicals which
7 could be injected are surfactants, refrigerants, and
8 well fracturing chemicals. Processing apparatus 213
9 could also comprise injection water electrolysis
equipment. The chemicals/injected materials could
11 be added via one or more additional input conduits
12 214.
13
14 Additionally, an additional input conduit 214 could
be used to provide extra fluids to be injected. An
16 additional input conduit 214 could, 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.
21
22 The processing apparatus 213 could 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.
27
28 Alternatively, processing apparatus 213 could
29 comprise separation equipment e.g. for separating
gas, water, sand/debris and/or hydrocarbons. The
31 separated component(s) could be siphoned off via one
32 or more additional process conduits 212.
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1
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 could include injection
water electrolysis equipment.
11
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.
16
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.
21
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 bore 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
29 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
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1 hydraulic control functions from surface or an =
2 intervention vessel.
3
4 This embodiment therefore provides a fluid diverter
for use with a wellhead tree comprising a thin
6 walled diverter conduit and a seal stack 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 or chemical
13 treatment apparatus, with the return flow routed via
14 the tree cap to the bore of the diver-ter conduit and
to the well bore.
16
17 Referring to Fig. 3a, a further embodiment 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 43h 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 bore 1. Seals
43a and 43b are disposed on an area of the conduit
26 42a with reduced diameter in the region 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.
31
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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 open, 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 fairly wide bore for
27 more efficient recovery of fluids at relatively high
28 pressure, thereby reducing pressure drops across the
29 apparatus.
31 This embodiment therefore provides a fluid diverter
32 for use with a manifold such as a wellhead tree
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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.
13
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 seals 73a and
17 73b having the same position and function as seals
18 43a and 43h described with reference to the 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 between the
22 straddle 70 and the production bore 1, through 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.
28
29 This embodiment therefore provides a fluid diverter
30 for use with a manifold such as a wellhead tree
31 which is not connected to the tree cap by a thin
32 walled conduit, but is anchored in the tree bore,
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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.
4
The Fig. 4a embodiment has a different design of cap
6 40c with a wide bore conduit 42c extending down 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 84 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.
18
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 wellhead
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), diverting
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
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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.
4
Referring now to Fig. 4b, a modified embodiment
6 dispenses with the conduit 42c of the Fig. 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.
11
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.
19
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
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1 production branch, and to a production line for
2 recovery as is conventional in the art.
3
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.
14
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 passage
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..
22
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.
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1
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 the
7 annulus 124, 125 formed between the conduit 102 and
8 the bore of the tree.
9
The turbine motor 108 is driven by fluid propelled
11 by a hydraulic power pack H which typically flows 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
26 113 and can be recovered by normal means.
27
28 Another benefit of the present embodiment is that
29 the direction of flow of the hydraulic power pack 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
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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.
8
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.
14
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.
23
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.
29
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
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1 diameters. The embodiments described can also be
2 incorporated into new designs of christmas tree as
3 integral features rather than as retrofit
4 assemblies. Also, the embodiments can be fitted to
other kinds of manifold apart from trees, such as
6 gathering manifolds, on subsea or topside wells.
7
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.
22
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.
29
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
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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.
21
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.
28
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
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1 motor, so as to drive the fluid in the opposite
2 direction of the arrows shown in Fig. 8.
3
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 102
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.
26
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
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1 the fluid is pumped through the production wing
2 valve 113.
3
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 116 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.
12
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. ha. Any other similar switching
31 system could be used, and fluid lines are not
32 essential to the invention.
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1
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
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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.
6
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
12 mechanisms etc.
13
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.
18
19 The check valves shown are ball valves, but can be
substituted for any other known fluid valve. The
21 Figs. 10 and 11 embodiment can be retrofitted to
22 existing trees of varying diameters or incorporated
23 into the design of new trees.
24
Referring now to Figs. 12 and 13, a further
26 embodiment has a similar piston arrangement as the
27 embodiment shown in Figs. 10 and 11, but the piston
28 assembly 115, 116 is housed within a cylinder formed
29 entirely by the bore 103b of the cap 103. As
before, drive fluid is pumped by the hydraulic power
31 pack into the chamber below the upper piston 115,
32 causing it to rise as shown in Fig. 12a, and the
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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.
18
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
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1 120 (valve 119 is closed) and the production wing
2 valve 113.
3
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.
14
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.
21
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.
27
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.
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1
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.
7
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.
24
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
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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.
5
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.
21
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.
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1
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.
13
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.
24
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.
31
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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
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.
21
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
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1 250, and not include either of the booster pumps
2 260, 270.
3
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.
7
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.
17
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
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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 10 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 reference to previous embodiments.
14
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.
18
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.
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1
2 To inject fluids into the well, the embodiments of
3 Figs 20 and 21 can be used with the flow directions
4 reversed.
5
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.
14
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.
21
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.
31
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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.
19
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 21. 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.
32
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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.
9
Referring now to Fig 23, a conventional tree
11 manifold 601 is illustrated having a production bore
12 602 and an annulus bore 603.
13
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.
28
29 Similarly, the tree 601 also has an annulus wing
621, an annulus wing valve 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
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1 lower end. There is no choke inside the annulus
2 choke body 631.
3
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.
9
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 surface 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
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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.
4
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
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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.
8
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
12 Fig 24.
13
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
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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.
12
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.
19
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.
27
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
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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.
14
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.
27
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
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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.
7
8 The pumps 820 are optional.
9
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.
13 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.
18
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.
24
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
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1 Fig 26, the production choke 930 is shown in a fully
2 open position.
3
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 valve 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". Like the Fig 23
11 embodiment, the Fig 26 housing 940 is attached to
12 the production wing branch 920 at a clamp 948.
13
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.
24
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
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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.
4
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'.
16
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.
24
25 The diverter assembly 1004 is sealed within the
26 branch extension 1021 at a seal 1045. A valve 1022
27 is located in the branch extension 1021 below the
28 diverter assembly 1004.
29
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
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1 the valve 1022 and rejoins the primary passage 1060
2 on the other side of the valve 1022.
3
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.
14
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.
23
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.
29
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
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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.
6
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.
19
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).
27
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).
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1
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.
27
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
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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.
8
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.
21
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.
27
28 It should be noted that the tree 601 is a
29 conventional tree but the invention can also be used
with horizontal trees.
31
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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.
5
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.
11
12 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
valve V2 is located in the production wing branch
26 1114.
27
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
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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.
14
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.
29
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
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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.
7
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.
28
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
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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
19 divert fluids flowing into or out from the annulus
bore. An example of a diverter assembly attached to
21 an annulus choke body has already been described
22 with reference to Fig 23.
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,
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1 in this 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).
9
Fig 33 shows a further alternative embodiment of a
11 diverter assembly 1110", and like parts are
12 designated by like numbers having a double prime.
13 This Figure is cut off after the valve V2; the rest
14 of the christmas tree is the same as that of the
previous two embodiments. Again, the christmas tree
16 of this embodiment is the same as those of the
17 previous two embodiments, and so these reference
18 numbers are not primed.
19
The housing 1120" of the Fig 33 embodiment is
21 substantially the same as the housing 1120' of the
22 Fig 32 embodiment. The housing 1120" is
23 cylindrical 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).
27
28 The housing 1120" is provided with an extension
29 portion in the form of a conduit 1132", which
extends 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
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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".
4
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.
27
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
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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".
7
8 In the Fig 32 embodiment, there is the option to
9 divert fluids into or from the well, if the valves
VI, V2 are open, and the option to exclude these
11 fluids by closing at least one of these valves.
12
13 The embodiments of Figs 32 and 33 can be used to
14 recover 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.
19
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.
31
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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.
14
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 diverted into the cap 1140. The fluids pass through
the conduit 1146, 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 axial passage 1122' to the aperture 1118 and are
24 recovered therefrom via a standard outlet line
connected to this aperture.
26
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 processing apparatus 1148, the conduit 1146, the
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1 cap 1140 and from the cap directly into the
2 production bore of the tree and the well bore.
3
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 wells 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 specification, 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.
26
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
header, 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
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1 originally nstalled, and the invention provides the
2 advantage of being able to adapt these existing
3 trees in a low 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 production bore 1 of horizontal christmas tree
400.
21
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 into coil tubing insert 410; the gas mixes
26 with the production 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
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1 cap 40e by plug 408; instead it is diverted into
2 branch 10 for recovery therefrom.
3
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 blocked. 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.
19
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.
23
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
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1 outlet 44 and the inlet 46. The top end of conduit
2 42 is sealingly connected at annular seal 416 to
3 inner axial passage 402 above inlet 46 and below
4 outlet 44. Annular sealing plug 412 of coil tubing
insert 410 lies between outlet 44 and gas inlet 406.
6
7 In use, as in the Fig. 35 embodiment, gas is
8 injected through 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 the coil tubing insert 410, which
12 extends into the 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 inlet 46 draws the "gassed" produced
17 fluids up the annulus between the wall of production
18 bore 1 and coil 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. The fluids are then diverted by annular
22 sealing plug 412 through outlet 44, through the
23 booster pump, and are returned through inlet 46. At
24 this point, the 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 43. As the fluids cannot pass seals
28 416, 43, they are 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
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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 diverter 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 bore. Alternative embodiments may use
9 any of the other 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.
13
14 Modifications and improvements may be incorporated
without departing from the scope of the invention.
16 For example, as stated above, the diverter assembly
17 could be attached to an annulus choke body, instead
18 of to a production choke body.
19
It should be noted that the flow diverters of Figs
21 20, 21, 22, 24, 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.
24
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
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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.
9
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 31.
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 to the diverter assembly of the
31 injection well B, and from there, the fluids pass
32 into the well bore. This embodiment allows
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1 diversion of fluids whilst bypassing the export line
2 which is normally connected to outlets 1118.
3
4 Therefore, with this modification, single flowpath
embodiments could also be used for the production
6 well. This method can therefore be achieved with a
7 diverter assembly located in the production/annulus
8 bore or in a wing branch, and with most of the
9 embodiments of diverter assembly described in this
specification.
11
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 In the annulus bore, similar to
22 the embodiments of Figs 2 to 6 in the production
23 bore.
24
The Fig 23 method, in which recovery and injection
26 occur in the same well, could also be achieved with
27 any of the other diverter 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
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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
V 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 to 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 680.
19
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.
26
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
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1 to an annulus wing branch, or another branch of the
2 tree. The embodiments of Figs 31 to 34 could be
3 connected to 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.
9
