Other related applications include U.S. application Ser. No. 10/415,156 filed on Apr. 25, 2003, now U.S. Pat. No. 6,823,941; U.S. application Ser. No. 10/558,593 filed on Nov. 29, 2005, now U.S. Pat. No. 7,992,643; U.S. application Ser. No. 10/590,563 filed on Dec. 13, 2007, now U.S. Pat. No. 8,066,076; U.S. application Ser. No. 12/441,119 filed on Mar. 12, 2009, now U.S. Pat. No. 8,066,063; U.S. application Ser. No. 12/515,534 filed on May 19, 2009 now U.S. Pat. No. 8,104,541; U.S. application Ser. No. 12/515,729 filed on May 20, 2009, now U.S. Pat. No. 8,297,360; U.S. application Ser. No. 12/541,934 filed on Aug. 15, 2009, now U.S. Pat. No. 8,272,435; U.S. application Ser. No. 12/541,936 filed on Aug. 15, 2009, now U.S. Pat. No. 7,992,633; U.S. application Ser. No. 12/541,937 filed on Aug. 15, 2009, now U.S. Pat. No. 8,281,864; U.S. application Ser. No. 12/541,938 filed on Aug. 15, 2009, now U.S. Pat. No. 8,066,067; U.S. application Ser. No. 12/768,332 filed Apr. 27, 2010, now U.S. Pat. No. 8,091,630; U.S. application Ser. No. 12/768,337 filed on Apr. 27, 2010, now U.S. Pat. No. 8,122,948; U.S. application Ser. No. 13/116,889 filed on May 26, 2011, now U.S. Pat. No. 8,167,049; U.S. application Ser. No. 13/164,291 filed on Jun. 20, 2011, now U.S. Pat. No. 8,469,086; U.S. application Ser. No. 12/768,324 filed Apr. 27, 2010, now U.S. Pat. No. 8,220,535; U.S. application Ser. No. 13/205,284 filed Aug. 8, 2011, now U.S. Pat. No. 8,622,138; U.S. application Ser. No. 13/267,039 filed Oct. 6, 2011; U.S. application Ser. No. 13/405,997 filed Feb. 27, 2012, now U.S. Pat. No. 8,573,306; U.S. application Ser. No. 13/415,635 filed Mar. 8, 2012; U.S. application Ser. No. 13/536,433 filed Jun. 28, 2012, now U.S. Pat. No. 8,540,018; and U.S. application Ser. No. 13/591,443 filed Aug. 22, 2012.
The present invention relates to apparatus and methods for diverting fluids. Embodiments of the invention can be used for recovery and injection. Some embodiments relate especially but not exclusively to recovery and injection, into either the same, or a different well.
Christmas trees are well known in the art of oil and gas wells, and generally comprise an assembly of pipes, valves and fittings installed in a wellhead after completion of drilling and installation of the production tubing to control the flow of oil and gas from the well. Subsea christmas trees typically have at least two bores one of which communicates with the production tubing (the production bore), and the other of which communicates with the annulus (the annulus bore).
Typical designs of christmas tree have a side outlet (a production wing branch) to the production bore closed by a production wing valve for removal of production fluids from the production bore. The annulus bore also typically has an annulus wing branch with a respective annulus wing valve. The top of the production bore and the top of the annulus bore are usually capped by a christmas tree cap which typically seals off the various bores in the christmas tree, and provides hydraulic channels for operation of the various valves in the christmas tree by means of intervention equipment, or remotely from an offshore installation.
Wells and trees are often active for a long time, and wells from a decade ago may still be in use today. However, technology has progressed a great deal during this time, for example, subsea processing of fluids is now desirable. Such processing can involve adding chemicals, separating water and sand from the hydrocarbons, etc. Furthermore, it is sometimes desired to take fluids from one well and inject a component of these fluids into another well, or into the same well. To do any of these things involves breaking the pipework attached to the outlet of the wing branch, inserting new pipework leading to this processing equipment, alternative well, etc. This provides the problem and large associated risks of disconnecting pipe work which has been in place for a considerable time and which was never intended to be disconnected. Furthermore, due to environmental regulations, no produced fluids are allowed to leak out into the ocean, and any such unanticipated and unconventional disconnection provides the risk that this will occur.
Conventional methods of extracting fluid from wells involves recovering all of the fluids along pipes to the surface (e.g. a rig or even to land) before the hydrocarbons are separated from the unwanted sand and water. Conveying the sand and water such great distances is wasteful of energy. Furthermore, fluids to be injected into a well are often conveyed over significant distances, which is also a waste of energy.
In low pressure wells, it is generally desirable to boost the pressure of the production fluids flowing through the production bore, and this is typically done by installing a pump or similar apparatus after the production wing valve in a pipeline or similar leading from the side outlet of the christmas tree. However, installing such a pump in an active well is a difficult operation, for which production must cease for some time until the pipeline is cut, the pump installed, and the pipeline resealed and tested for integrity.
A further alternative is to pressure boost the production fluids by installing a pump from a rig, but this requires a well intervention from the rig, which can be even more expensive than breaking the subsea or seabed pipework.
According to a first aspect of the present invention there is provided a diverter assembly for a manifold of an oil or gas well, comprising a housing having an internal passage, wherein the diverter assembly is adapted to connect to a branch of the manifold.
According to a second aspect of the invention there is provided a diverter assembly adapted to be inserted within a manifold branch bore, wherein the diverter assembly includes a separator to divide the branch bore into two separate regions.
The oil or gas well is typically a subsea well but the invention is equally applicable to topside wells.
The manifold may be a gathering manifold at the junction of several flow lines carrying production fluids from, or conveying injection fluids to, a number of different wells. Alternatively, the manifold may be dedicated to a single well; for example, the manifold may comprise a christmas tree.
By “branch” we mean any branch of the manifold, other than a production bore of a tree. The wing branch is typically a lateral branch of the tree, and can be a production or an annulus wing branch connected to a production bore or an annulus bore respectively.
Optionally, the housing is attached to a choke body. “Choke body” can mean the housing which remains after the manifold's standard choke has been removed. The choke may be a choke of a tree, or a choke of any other kind of manifold.
The diverter assembly could be located in a branch of the manifold (or a branch extension) in series with a choke. For example, in an embodiment where the manifold comprises a tree, the diverter assembly could be located between the choke and the production wing valve or between the choke and the branch outlet. Further alternative embodiments could have the diverter assembly located in pipework coupled to the manifold, instead of within the manifold itself. Such embodiments allow the diverter assembly to be used in addition to a choke, instead of replacing the choke.
Embodiments where the diverter assembly is adapted to connect to a branch of a tree means that the tree cap does not have to be removed to fit the diverter assembly. Embodiments of the invention can be easily retro-fitted to existing trees.
Preferably, the diverter assembly is locatable within a bore in the branch of the manifold.
Optionally, the internal passage of the diverter assembly is in communication with the interior of the choke body, or other part of the manifold branch.
The invention provides the advantage that fluids can be diverted from their usual path between the well bore and the outlet of the wing branch. The fluids may be produced fluids being recovered and travelling from the well bore to the outlet of a tree. Alternatively, the fluids may be injection fluids travelling in the reverse direction into the well bore. As the choke is standard equipment, there are well-known and safe techniques of removing and replacing the choke as it wears out. The same tried and tested techniques can be used to remove the choke from the choke body and to clamp the diverter assembly onto the choke body, without the risk of leaking well fluids into the ocean. This enables new pipe work to be connected to the choke body and hence enables safe re-routing of the produced fluids, without having to undertake the considerable risk of disconnecting and reconnecting any of the existing pipes (e.g. the outlet header).
Some embodiments allow fluid communication between the well bore and the diverter assembly. Other embodiments allow the well bore to be separated from a region of the diverter assembly. The choke body may be a production choke body or an annulus choke body.
Preferably, a first end of the diverter assembly is provided with a clamp for attachment to a choke body or other part of the manifold branch.
Optionally, the housing is cylindrical and the internal passage extends axially through the housing between opposite ends of the housing. Alternatively, one end of the internal passage is in a side of the housing.
Typically, the diverter assembly includes separation means to provide two separate regions within the diverter assembly. Typically, each of these regions has a respective inlet and outlet so that fluid can flow through both of these regions independently.
Optionally, the housing includes an axial insert portion.
Typically, the axial insert portion is in the form of a conduit. Typically, the end of the conduit extends beyond the end of the housing. Preferably, the conduit divides the internal passage into a first region comprising the bore of the conduit and a second region comprising the annulus between the housing and the conduit.
Optionally, the conduit is adapted to seal within the inside of the branch (e.g. inside the choke body) to prevent fluid communication between the annulus and the bore of the conduit.
Alternatively, the axial insert portion is in the form of a stem. Optionally, the axial insert portion is provided with a plug adapted to block an outlet of the christmas tree, or other kind of manifold. Preferably, the plug is adapted to fit within and seal inside a passage leading to an outlet of a branch of the manifold.
Optionally, the diverter assembly provides means for diverting fluids from a first portion of a first flowpath to a second flowpath, and means for diverting the fluids from a second flowpath to a second portion of a first flowpath.
Preferably, at least a part of the first flowpath comprises a branch of the manifold.
The first and second portions of the first flowpath could comprise the bore and the annulus of a conduit.
According to a third aspect of the present invention there is provided a manifold having a branch and a diverter assembly according to the first or second aspects of the invention.
Optionally, the diverter assembly is attached to the branch so that the internal passage of the diverter assembly is in communication with the interior of the branch.
Optionally, the manifold has a wing branch outlet, and the internal passage of the diverter assembly is in fluid communication with the wing branch outlet.
Optionally, a region defined by the diverter assembly is separate from the production bore of the well. Optionally, the internal passage of the diverter assembly is separated from the well bore by a closed valve in the manifold.
Alternatively, the diverter assembly is provided with an insert in the form of a conduit which defines a first region comprising the bore of the conduit, and a second separate region comprising the annulus between the conduit and the housing. Optionally, one end of the conduit is sealed inside the choke body or other part of the branch, to prevent fluid communication between the first and second regions.
Optionally, the annulus between the conduit and the housing is closed so that the annulus is in communication with the branch only.
Alternatively, the annulus has an outlet for connection to further pipes, so that the second region provides a flowpath which is separate from the first region formed by the bore of the conduit.
Optionally, the first and second regions are connected by pipework. Optionally, a processing apparatus is connected in the pipework so that fluids are processed whilst passing through the connecting pipework.
Typically, the processing apparatus is chosen from at least one of: a pump; a process fluid turbine; injection apparatus for injecting gas or steam; chemical injection apparatus; a fluid riser; measurement apparatus; temperature measurement apparatus; flow rate measurement apparatus; constitution measurement apparatus; consistency measurement apparatus; gas separation apparatus; water separation apparatus; solids separation apparatus; and hydrocarbon separation apparatus.
Optionally, the diverter assembly provides a barrier to separate a branch outlet from a branch inlet. The barrier may separate a branch outlet from a production bore of a tree. Optionally, the barrier comprises a plug, which is typically located inside the choke body (or other part of the manifold branch) to block the branch outlet. Optionally, the plug is attached to the housing by a stem which extends axially through the internal passage of the housing.
Alternatively, the barrier comprises a conduit of the diverter assembly which is engaged within the choke body or other part of the branch.
Optionally, the manifold is provided with a conduit connecting the first and second regions.
Optionally, a first set of fluids are recovered from a first well via a first diverter assembly and combined with other fluids in a communal conduit, and the combined fluids are then diverted into an export line via a second diverter assembly connected to a second well.
According to a fourth aspect of the present invention, there is provided a method of diverting fluids, comprising: connecting a diverter assembly to a branch of a manifold, wherein the diverter assembly comprises a housing having an internal passage; and diverting the fluids through the housing.
According to a fifth aspect of the present invention there is provided a method of diverting well fluids, the method including the steps of:
diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath back to a second portion of the first flowpath;
wherein the fluids are diverted by at least one diverter assembly connected to a branch of a manifold.
The diverter assembly is optionally located within a choke body; alternatively, the diverter assembly may be coupled in series with a choke. The diverter assembly may be located in the manifold branch adjacent to the choke, or it may be included within a separate extension portion of the manifold branch.
Typically, the method is for recovering fluids from a well, and includes the final step of diverting fluids to an outlet of the first flowpath for recovery therefrom. Alternatively or additionally, the method is for injecting fluids into a well.
Optionally, the internal passage of the diverter assembly is in communication with the interior of the branch.
The fluids may be passed in either direction through the diverter assembly.
Typically, the diverter assembly includes separation means to provide two separate regions within the diverter assembly, and the method may includes the step of passing fluids through one or both of these regions.
Optionally, fluids are passed through the first and the second regions in the same direction. Alternatively, fluids are passed through the first and the second regions in opposite directions.
Optionally, the fluids are passed through one of the first and second regions and subsequently at least a proportion of these fluids are then passed through the other of the first and the second regions. Optionally, the method includes the step of processing the fluids in a processing apparatus before passing the fluids back to the other of the first and second regions.
Alternatively, fluids may be passed through only one of the two separate regions. For example, the diverter assembly could be used to provide a connection between two flow paths which are unconnected to the well bore, e.g. between two external fluid lines. Optionally, fluids could flow only through a region which is sealed from the branch. For example if the separate regions were provided with a conduit sealed within a manifold branch, fluids may flow through the bore of the conduit only. A flowpath could connect the bore of the conduit to a well bore (production or annulus bore) or another main bore of the tree to bypass the manifold branch. This flowpath could optionally link a region defined by the diverter assembly to a well bore via an aperture in the tree cap.
Optionally, the first and second regions are connected by pipework. Optionally, a processing apparatus is connected in the pipework so that fluids are processed whilst passing through the connecting pipework.
The processing apparatus can be, but is not limited to, any of those described above.
Typically, the method includes the step of removing a choke from the choke body before attaching the diverter assembly to the choke body.
Optionally, the method includes the step of diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath to a second portion of the first flowpath.
For recovering production fluids, the first portion of the first flowpath is typically in communication with the production bore, and the second portion of the first flowpath is typically connected to a pipeline for carrying away the recovered fluids (e.g. to the surface). For injecting fluids into the well, the first portion of the first flowpath is typically connected to an external fluid line, and the second portion of the first flowpath is in communication with the annulus bore. Optionally, the flow directions may be reversed.
The method provides the advantage that fluids can be diverted (e.g. recovered or injected into the well, or even diverted from another route, bypassing the well completely) without having to remove and replace any pipes already attached to the manifold branch outlet (e.g. a production wing branch outlet).
Optionally, the method includes the step of recovering fluids from a well and the step of injecting fluids into the well. Optionally, some of the recovered fluids are re-injected into the same well, or a different well.
For example, the production fluids could be separated into hydrocarbons and water; the hydrocarbons being returned to the first flowpath for recovery therefrom, and the water being returned and injected into the same or a different well.
Optionally, both of the steps of recovering fluids and injecting fluids include using respective flow diverter assemblies. Alternatively, only one of the steps of recovering and injecting fluids includes using a diverter assembly.
Optionally, the method includes the step of diverting the fluids through a processing apparatus.
According to a sixth aspect of the present invention there is provided a manifold having a first diverter assembly according to the first aspect of the invention connected to a first branch and a second diverter assembly according to the first aspect of the invention connected to a second branch.
Typically, the manifold comprises a tree and the first branch comprises a production wing branch and the second branch comprises an annulus wing branch.
According to a seventh aspect of the present invention, there is provided a manifold having a first bore having an outlet; a second bore having an outlet; a first diverter assembly connected to the first bore; a second diverter assembly connected to the second bore; and a flowpath connecting the first and second diverter assemblies.
Typically at least one of the first and second diverter assemblies blocks a passage in the manifold between a bore of the manifold and its respective outlet. Optionally, the manifold comprises a tree, and the first bore comprises a production bore and the second bore comprises an annulus bore.
Certain embodiments have the advantage that the first and second diverter assemblies can be connected together to allow the unwanted parts of the produced fluids (e.g. water and sand) to be directly injected back into the well, instead of being pumped away with the hydrocarbons. The unwanted materials can be extracted from the hydrocarbons substantially at the wellhead, which reduces the quantity of production fluids to be pumped away, thereby saving energy. The first and second diverter assemblies can alternatively or additionally be used to connect to other kinds of processing apparatus (e.g. the types described with reference to other aspects of the invention), such as a booster pump, filter apparatus, chemical injection apparatus, etc. to allow adding or taking away of substances and adjustment of pressure to be carried out adjacent to the wellhead. The first and second diverter assemblies enable processing to be performed on both fluids being recovered and fluids being injected. Preferred embodiments of the invention enable both recovery and injection to occur simultaneously in the same well.
Typically, the first and second diverter assemblies are connected to a processing apparatus. The processing apparatus can be any of those described with reference to other aspects of the invention.
The diverter assembly may be a diverter assembly as described according to any aspect of the invention.
Typically, a tubing system adapted to both recover and inject fluids is also provided. Preferably, the tubing system is adapted to simultaneously recover and inject fluids.
According to a eighth aspect of the present invention there is provided a method of recovery of fluids from, and injection of fluids into, a well, wherein the well has a manifold that includes at least one bore and at least one branch having an outlet, the method including the steps of:
blocking a passage in the manifold between a bore of the manifold and its respective branch outlet;
diverting fluids recovered from the well out of the manifold; and
injecting fluids into the well;
wherein neither the fluids being diverted out of the manifold nor the fluids being injected travel through the branch outlet of the blocked passage.
Preferably, the method is performed using a diverter assembly according to any aspect of the invention.
Preferably, a processing apparatus is coupled to the second flowpath. The processing apparatus can be any of the ones defined in any aspect of the invention.
Typically, the processing apparatus separates hydrocarbons from the rest of the produced fluids. Typically, the non-hydrocarbon components of the produced fluids are diverted to the second diverter assembly to provide at least one component of the injection fluids.
Optionally, at least one component of the injection fluids is provided by an external fluid line which is not connected to the production bore or to the first diverter assembly.
Optionally, the method includes the step of diverting at least some of the injection fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath back to a second portion of the first flowpath for injection into the annulus bore of the well.
Typically, the steps of recovering fluids from the well and injecting fluids into the well are carried out simultaneously.
According to a ninth aspect of the present invention there is provided a well assembly comprising:
a first well having a first diverter assembly;
a second well having a second diverter assembly; and
a flowpath connecting the first and second diverter assemblies.
Typically, each of the first and second wells has a tree having a respective bore and a respective outlet, and at least one of the diverter assemblies blocks a passage in the tree between its respective tree bore and its respective tree outlet.
Typically, an alternative outlet is provided, and the diverter assembly diverts fluids into a path leading to the alternative outlet.
Optionally, at least one of the first and second diverter assemblies is located within the production bore of its respective tree. Optionally, at least one of the first and second diverter assemblies is connected to a wing branch of its respective tree.
According to a tenth aspect of the present invention there is provided a method of diverting fluids from a first well to a second well via at least one manifold, the method including the steps of:
blocking a passage in the manifold between a bore of the manifold and a branch outlet of the manifold; and
diverting at least some of the fluids from the first well to the second well via a path not including the branch outlet of the blocked passage.
Optionally the at least one manifold comprises a tree of the first well and the method includes the further step of returning a portion of the recovered fluids to the tree of the first well and thereafter recovering that portion of the recovered fluids from the outlet of the blocked passage.
According to an eleventh aspect of the present invention there is provided a method of recovery of fluids from, and injection of fluids into, a well having a manifold; wherein at least one of the steps of recovery and injection includes diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath to a second portion of the first flowpath
Optionally, recovery and injection is simultaneous. Optionally, some of the recovered fluids are re-injected into the well.
According to a twelfth aspect of the present invention there is provided a method of recovering fluids from a first well and re-injecting at least some of these recovered fluids into a second well, wherein the method includes the steps of diverting fluids from a first portion of a first flowpath to a second flowpath, and diverting at least some of these fluids from the second flowpath to a second portion of the first flowpath.
Typically, the fluids are recovered from the first well via a first diverter assembly, and wherein the fluids are re-injected into the second well via a second diverter assembly.
Typically, the method also includes the step of processing the production fluids in a processing apparatus connected between the first and second wells.
Optionally, the method includes the further step of returning a portion of the recovered fluids to the first diverter assembly and thereafter recovering that portion of the recovered fluids via the first diverter assembly.
According to a thirteenth aspect of the present invention there is provided a method of recovering fluids from, or injecting fluids into, a well, including the step of diverting the fluids between a well bore and a branch outlet whilst bypassing at least a portion of the branch.
Such embodiments are useful to divert fluids to a processing apparatus and then to return them to the wing branch outlet for recovery via a standard export line attached to the outlet. The method is also useful if a wing branch valve gets stuck shut.
Optionally, the fluids are diverted via the tree cap.
According to a fourteenth aspect of the present invention there is provided a method of injecting fluids into a well, the method comprising diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath into a second portion of the first flowpath.
Optionally, the method is performed using a diverter assembly according to any aspect of the invention. The diverter assembly may be locatable in a wide range of places, including, but not limited to: the production bore, the annulus bore, the production wing branch, the annulus wing branch, a production choke body, an annulus choke body, a tree cap or external conduits connected to a tree. The diverter assembly is not necessarily connected to a tree, but may instead be connected to another type of manifold. The first and second flowpaths could comprise some or all of any part of the manifold.
Typically the first flowpath is a production bore or production line, and the first portion of it is typically a lower part near to the wellhead. Alternatively, the first flowpath comprises an annulus bore. The second portion of the first flowpath is typically a downstream portion of the bore or line adjacent a branch outlet, although the first or second portions can be in the branch or outlet of the first flowpath.
The diversion of fluids from the first flowpath allows the treatment of the fluids (e.g. with chemicals) or pressure boosting for more efficient recovery before re-entry into the first flowpath.
Optionally the second flowpath is an annulus bore, or a conduit inserted into the first flowpath. Other types of bore may optionally be used for the second flowpath instead of an annulus bore.
Typically the flow diversion from the first flowpath to the second flowpath is achieved by a cap on the tree. Optionally, the cap contains a pump or treatment apparatus, but this can be provided separately, or in another part of the apparatus, and in most embodiments of this type, flow will be diverted via the cap to the pump etc and returned to the cap by way of tubing. A connection typically in the form of a conduit is typically provided to transfer fluids between the first and second flowpaths.
Typically, the diverter assembly can be formed from high grade steels or other metals, using e.g. resilient or inflatable sealing means as required.
The assembly may include outlets for the first and second flowpaths, for diversion of the fluids to a pump or treatment assembly, or other processing apparatus as described in this application.
The assembly optionally comprises a conduit capable of insertion into the first flowpath, the assembly having sealing means capable of sealing the conduit against the wall of the production bore. The conduit may provide a flow diverter through its central bore which typically leads to a christmas tree cap and the pump mentioned previously. The seal effected between the conduit and the first flowpath prevents fluid from the first flowpath entering the annulus between the conduit and the production bore except as described hereinafter. After passing through a typical booster pump, squeeze or scale chemical treatment apparatus, the fluid is diverted into the second flowpath and from there to a crossover back to the first flowpath and first flowpath outlet.
The assembly and method are typically suited for subsea production wells in normal mode or during well testing, but can also be used in subsea water injection wells, land based oil production injection wells, and geothermal wells.
The pump can be powered by high pressure water or by electricity which can be supplied direct from a fixed or floating offshore installation, or from a tethered buoy arrangement, or by high pressure gas from a local source.
The cap preferably seals within christmas tree bores above the upper master valve. Seals between the cap and bores of the tree are optionally O-ring, inflatable, or preferably metal-to-metal seals. The cap can be retro-fitted very cost effectively with no disruption to existing pipework and minimal impact on control systems already in place.
The typical design of the flow diverters within the cap can vary with the design of tree, the number, size, and configuration of the diverter channels being matched with the production and annulus bores, and others as the case may be. This provides a way to isolate the pump from the production bore if needed, and also provides a bypass loop.
The cap is typically capable of retro-fitting to existing trees, and many include equivalent hydraulic fluid conduits for control of tree valves, and which match and co-operate with the conduits or other control elements of the tree to which the cap is being fitted.
In most preferred embodiments, the cap has outlets for production and annulus flow paths for diversion of fluids away from the cap.
In accordance with a fifteenth aspect of the invention there is also provided a pump adapted to fit within a bore of a manifold. The manifold optionally comprises a tree, but can be any kind of manifold for an oil or gas well, such as a gathering manifold.
According to a sixteenth aspect of the present invention there is provided a diverter assembly having a pump according to the fifteenth aspect of the present invention.
The diverter assembly can be a diverter assembly according to any aspect of the invention, but it is not limited to these.
The tree is typically a subsea tree, such as a christmas tree, typically on a subsea well, but a topside tree (or other topside manifold) connected to a topside well could also be appropriate. Horizontal or vertical trees are equally suitable for use of the invention.
The bore of the tree may be a production bore. However, the diverter assembly and pump could be located in any bore of the tree, for example, in a wing branch bore.
The flow diverter typically incorporates diverter means to divert fluids flowing through the bore of the tree from a first portion of the bore, through the pump, and back to a second portion of the bore for recovery therefrom via an outlet, which is typically the production wing valve.
The first portion from which the fluids are initially diverted is typically the production bore/other bore/line of the well, and flow from this portion is typically diverted into a diverter conduit sealed within the bore. Fluid is typically diverted through the bore of the diverter conduit, and after passing therethrough, and exiting the bore of the diverter conduit, typically passes through the annulus created between the diverter conduit and the bore or line. At some point on the diverted fluid path, the fluid passes through the pump internally of the tree, thereby minimising the external profile of the tree, and reducing the chances of damage to the pump.
The pump is typically powered by a motor, and the type of motor can be chosen from several different forms. In some embodiments of the invention, a hydraulic motor, a turbine motor or moineau motor can be driven by any well-known method, for example an electro-hydraulic power pack or similar power source, and can be connected, either directly or indirectly, to the pump. In certain other embodiments, the motor can be an electric motor, powered by a local power source or by a remote power source.
Certain embodiments of the present invention allow the construction of wellhead assemblies that can drive the fluid flow in different directions, simply by reversing the flow of the pump, although in some embodiments valves may need to be changed (e.g. reversed) depending on the design of the embodiment.
The diverter assembly typically includes a tree cap that can be retrofitted to existing designs of tree, and can integrally contain the pump and/or the motor to drive it.
The flow diverter preferably also comprises a conduit capable of insertion into the bore, and may have sealing means capable of sealing the conduit against the wall of the bore. The flow diverter typically seals within christmas tree production bores above an upper master valve in a conventional tree, or in the tubing hangar of a horizontal tree, and seals can be optionally O-ring, inflatable, elastomeric or metal to metal seals. The cap or other parts of the flow diverter can comprise hydraulic fluid conduits. The pump can optionally be sealed within the conduit.
According to a seventeenth aspect of the invention there is provided a method of recovering production fluids from a well having a manifold, the manifold having an integral pump located in a bore of the manifold, and the method comprising diverting fluids from a first portion of a bore of the manifold through the pump and into a second portion of the bore.
According to an eighteenth aspect of the present invention there is provided a christmas tree having a diverter assembly sealed in a bore of the tree, wherein the diverter assembly comprises a separator which divides the bore of the tree into two separate regions, and which extends through the tree bore and into the production zone of the well.
Optionally, the at least one diverter assembly comprises a conduit and at least one seal; the conduit optionally comprises a gas injection line.
This invention may be used in conjunction with a further diverter assembly according to any other aspect of the invention, or with a diverter assembly in the form of a conduit which is sealed in the production bore. Both diverter assemblies may comprise conduits; one conduit may be arranged concentrically within the other conduit to provide concentric, separate regions within the production bore.
According to a nineteenth aspect of the present invention there is provided a method of diverting fluids, including the steps of:
providing a fluid diverter assembly sealed in a bore of a tree to form two separate regions in the bore and extending into the production zone of the well;
injecting fluids into the well via one of the regions; and
recovering fluids via the other of the regions.
The injection fluids are typically gases; the method may include the steps of blocking a flowpath between the bore of the tree and a production wing outlet and diverting the recovered fluids out of the tree along an alternative route. The recovered fluids may be diverting the recovered fluids to a processing apparatus and returning at least some of 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.
Embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings in which:—
Referring now to the drawings, a typical production manifold on an offshore oil or gas wellhead comprises a christmas tree with a production bore 1 leading from production tubing (not shown) and carrying production fluids from a perforated region of the production casing in a reservoir (not shown). An annulus bore 2 leads to the annulus between the casing and the production tubing and a christmas tree cap 4 which seals off the production and annulus bores 1, 2, and provides a number of hydraulic control channels 3 by which a remote platform or intervention vessel can communicate with and operate the valves in the christmas tree. The cap 4 is removable from the christmas tree in order to expose the production and annulus bores in the event that intervention is required and tools need to be inserted into the production or annulus bores 1, 2.
The flow of fluids through the production and annulus bores is governed by various valves shown in the typical tree of
The annulus bore is closed by an annulus master valve (AMV) 25 below an annulus outlet 28 controlled by an annulus wing valve (AWV) 29, itself below crossover port 21. The crossover port 21 is closed by crossover valve 30. An annulus swab valve 32 located above the crossover port 21 closes the upper end of the annulus bore 2.
All valves in the tree are typically hydraulically controlled (with the exception of LPMV 18 which may be mechanically controlled) by means of hydraulic control channels 3 passing through the cap 4 and the body of the tool or via hoses as required, in response to signals generated from the surface or from an intervention vessel.
When production fluids are to be recovered from the production bore 1, LPMV 18 and UPMV 17 are opened, PSV 15 is closed, and PWV 12 is opened to open the branch 10 which leads to the pipeline (not shown). PSV 15 and ASV 32 are only opened if intervention is required.
Referring now to
Outlet 46 leads via tubing 216 to processing apparatus 213 (see
Injecting sea water into a well could be useful to boost the formation pressure for recovery of hydrocarbons from the well, and to maintain the pressure in the underground formation against collapse. Also, injecting waste gases or drill cuttings etc into a well obviates the need to dispose of these at the surface, which can prove expensive and environmentally damaging.
The processing apparatus 213 could also enable chemicals to be added to the fluids, e.g. viscosity moderators, which thin out the fluids, making them easier to pump, or pipe skin friction moderators, which minimise the friction between the fluids and the pipes. Further examples of chemicals which could be injected are surfactants, refrigerants, and well fracturing chemicals. Processing apparatus 213 could also comprise injection water electrolysis equipment. The chemicals/injected materials could be added via one or more additional input conduits 214.
Additionally, an additional input conduit 214 could be used to provide extra fluids to be injected. An additional input conduit 214 could, for example, originate from an inlet header (shown in
The processing apparatus 213 could also comprise a fluid riser, which could provide an alternative route between the well bore and the surface. This could be very useful if, for example, the branch 10 becomes blocked.
Alternatively, processing apparatus 213 could comprise separation equipment e.g. for separating gas, water, sand/debris and/or hydrocarbons. The separated component(s) could be siphoned off via one or more additional process conduits 212.
The processing apparatus 213 could alternatively or additionally include measurement apparatus, e.g. for measuring the temperature/flow rate/constitution/consistency, etc. The temperature could then be compared to temperature readings taken from the bottom of the well to calculate the temperature change in produced fluids. Furthermore, the processing apparatus 213 could include injection water electrolysis equipment.
Alternative embodiments of the invention (described below) can be used for both recovery of production fluids and injection of fluids, and the type of processing apparatus can be selected as appropriate.
The bore of conduit 42 can be closed by a cap service valve (CSV) 45 which is normally open but can close off an inlet 44 of the hollow bore of the conduit 42.
After treatment by the processing apparatus 213 the fluids are returned via tubing 217 to the production inlet 44 of the cap 40 which leads to the bore of the conduit 42 and from there the fluids pass into the well bore. The conduit bore and the inlet 46 can also have an optional crossover valve (COV) designated 50, and a tree cap adapter 51 in order to adapt the flow diverter channels in the tree cap 40 to a particular design of tree head. Control channels 3 are mated with a cap controlling adapter 5 in order to allow continuity of electrical or hydraulic control functions from surface or an intervention vessel.
This embodiment therefore provides a fluid diverter for use with a wellhead tree comprising a thin walled diverter conduit and a seal stack element connected to a modified christmas tree cap, sealing inside the production bore of the christmas tree typically above the hydraulic master valve, diverting flow through the conduit annulus, and the top of the christmas tree cap and tree cap valves to typically a pressure boosting device or chemical treatment apparatus, with the return flow routed via the tree cap to the bore of the diverter conduit and to the well bore.
Referring to
Injection fluids enter the branch 10 from where they pass into the annulus between the conduit 42a and the production bore 1. Fluid flow in the axial direction is limited by the seals 43a, 43b and the fluids leave the annulus via the crossover port 20 into the crossover channel 21c. The crossover channel 21c leads to the annulus bore 2 and from there the fluids pass through the outlet 62 to the pump or chemical treatment apparatus. The treated or pressurised fluids are returned from the pump or treatment apparatus to inlet 61 in the production bore 1. The fluids travel down the bore of the conduit 42a and from there, directly into the well bore.
Cap service valve (CSV) 60 is normally open, annulus swab valve 32 is normally held open, annulus master valve 25 and annulus wing valve 29 are normally closed, and crossover valve 30 is normally open. A crossover valve 65 is provided between the conduit bore 42a and the annular bore 2 in order to bypass the pump or treatment apparatus if desired. Normally the crossover valve 65 is maintained closed.
This embodiment maintains a fairly wide bore for more efficient recovery of fluids at relatively high pressure, thereby reducing pressure drops across the apparatus.
This embodiment therefore provides a fluid diverter for use with a manifold such as a wellhead tree comprising a thin walled diverter with two seal stack elements, connected to a tree cap, which straddles the crossover valve outlet and flowline outlet (which are approximately in the same horizontal plane), diverting flow from the annular space between the straddle and the existing xmas tree bore, through the crossover loop and crossover outlet, into the annulus bore (or annulus flowpath in concentric trees), to the top of the tree cap to pressure boosting or chemical treatment apparatus etc, with the return flow routed via the tree cap and the bore of the conduit.
This embodiment therefore provides a fluid diverter for use with a manifold such as a wellhead tree which is not connected to the tree cap by a thin walled conduit, but is anchored in the tree bore, and which allows full bore flow above the “straddle” portion, but routes flow through the crossover and will allow a swab valve (PSV) to function normally.
The
The
Referring now to
This embodiment provides a fluid diverter for use with a manifold such as a wellhead tree which is not connected to the tree cap by a thin walled conduit, but is anchored in the tree bore and which routes the flow through the crossover and allows full bore flow for the return flow, and will allow the swab valve to function normally.
Flow of production fluids through the production bore 123 is controlled by the tree master valve 112, which is normally open, and the tree swab valve 114, which is normally closed during the production phase of the well, so as to divert fluids flowing through the production bore 123 and the tree master valve 112, through the production wing valve 113 in the production branch, and to a production line for recovery as is conventional in the art.
In the embodiment of the invention shown in
The turbine motor 108 is configured with inter-collating vanes 108v and 103v on the shaft and side walls of the bore 103b respectively, so that passage of fluid past the vanes in the direction of the arrows 126a and 126b turns the shaft of the turbine motor 108, and thereby turns the vanes of the turbine pump 107, to which it is directly connected.
The bore of the conduit 102 housing the turbine pump 107 is open to the production bore 123 at its lower end, but there is a seal between the outer face of the conduit 102 and the inner face of the production bore 123 at that lower end, between the tree master valve 112 and the production wing branch, so that all production fluid passing through the production bore 123 is diverted into the bore of the conduit 102. The seal is typically an elastomeric or a metal to metal seal.
The upper end of the conduit 102 is sealed in a similar fashion to the inner surface of the cap body bore 103b, at a lower end thereof, but the conduit 102 has apertures 102a allowing fluid communication between the interior of the conduit 102, and the annulus 124, 125 formed between the conduit 102 and the bore of the tree.
The turbine motor 108 is driven by fluid propelled by a hydraulic power pack H which typically flows in the direction of arrows 126a and 126b so that fluid forced down the bore 103b of the cap turns the vanes 108v of the turbine motor 108 relative to the vanes 103v of the bore, thereby turning the shaft and the turbine pump 107. These actions draw fluid from the production bore 123 up through the inside of the conduit 102 and expels the fluid through the apertures 102a, into the annulus 124, 125 of the production bore. Since the conduit 102 is sealed to the bore above the apertures 102a, and below the production wing branch at the lower end of the conduit 102, the fluid flowing into the annulus 124 is diverted through the annulus 125 and into the production wing through the production wing valve 113 and can be recovered by normal means.
Another benefit of the present embodiment is that the direction of flow of the hydraulic power pack H can be reversed from the configuration shown in
In the
Like the
Like the
Like the preceding embodiments, the
The motor can be any prime mover of hollow shaft construction, but electric or hydraulic motors can function adequately in this embodiment. The pump design can be of any suitable type, but a moineau motor, or a turbine as shown here, are both suitable.
Like previous embodiments, the direction of flow of fluid through the pump shown in
Referring now to
One advantage of the
Referring now to
The piston 115 is moved up from the lower position shown in
As the piston is moving up as shown in
The fluid driven by the hydraulic power pack can be driven by other means. Alternatively, linear oscillating motion can be imparted to the lower piston assembly 116 by other well-known methods i.e. rotating crank and connecting rod, scotch yolk mechanisms etc.
By reversing and/or re-arranging the orientations of the check valves 119 and 120, the direction of flow in this embodiment can also be reversed, as shown in
The check valves shown are ball valves, but can be substituted for any other known fluid valve. The
Referring now to
A further embodiment is shown in
It should be noted that the pump does not have to be located in a production bore; the pump could be located in any bore of the tree with an inlet and an outlet. For example, the pump and diverter assembly may be connected to a wing branch of a tree/a choke body as shown in other embodiments of the invention.
The present invention can also usefully be used in multiple well combinations, as shown in
The injection well 330 can be any of the capped production well embodiments described above. The production well 230 can also be any of the abovedescribed production well embodiments, with outlets and inlets reversed.
Produced fluids from production well 230 flow up through the bore of conduit 42, exit via outlet 244, and pass through tubing 232 to processing apparatus 220, which may also have one or more further input lines 222 and one or more further outlet lines 224.
Processing apparatus 220 can be selected to perform any of the functions described above with reference to processing apparatus 213 in the
Tubing 233 connects processing apparatus 220 back to an inlet 246 of a wellhead cap 240 of production well 230. The processing apparatus 220 could also be used to inject gas into the separated hydrocarbons for lift and also for the injection of any desired chemicals such as scale or wax inhibitors. The hydrocarbons are then returned via tubing 233 to inlet 246 and flow from there into the annulus between the conduit 42 and the bore in which it is disposed. As the annulus is sealed at the upper and lower ends, the fluids flow through the export line 210 for recovery.
The horizontal line 310 of injection well 330 serves as an injection line (instead of an export line). Fluids to be injected can enter injection line 310, from where they pass via the annulus between the conduit 42 and the bore to the tree cap outlet 346 and tubing 235 into processing apparatus 220. The processing apparatus may include a pump, chemical injection device, and/or separating devices, etc. Once the injection fluids have been thus processed as required, they can now be combined with any separated water/sand/debris/other waste material from production well 230. The injection fluids are then transported via tubing 234 to an inlet 344 of the cap 340 of injection well 330, from where they pass through the conduit 42 and into the wellbore.
It should be noted that it is not necessary to have any extra injection fluids entering via injection line 310; all of the injection fluids could originate from production well 230 instead. Furthermore, as in the previous embodiments, if processing apparatus 220 includes a riser, this riser could be used to transport the processed produced fluids to the surface, instead of passing them back down into the christmas tree of the production bore again for recovery via export line 210.
In use, produced fluids from production well 230 exit as previously described via conduit 42 (not shown in
The separated water is transferred via tubing 234 to the wellbore of injection well 330 via inlet 344. The separated water enters injection well through inlet 344, from where it passes directly into its conduit 42 and from there, into the production bore and the depths of injection well 330.
Optionally, it may also be desired to inject additional fluids into injection well 330. This can be done by closing a valve in tubing 234 to prevent any fluids from entering the injection well via tubing 234. Now, these additional fluids can enter injection well 330 via injection line 310 (which was formerly the export line in previous embodiments). The rest of this procedure will follow that described above with reference to
Typically, fluids are injected into injection well 330 from tubing 234 (i.e. fluids separated from the produced fluids of production well 230) and from injection line 310 (i.e. any additional fluids) in sequence. Alternatively, tubings 234 and 237 could combine at inlet 344 and the two separate lines of injected fluids could be injected into well 330 simultaneously.
In the
Although only two connected wells are shown in
Two further embodiments of the invention are shown in
Diverter assembly 502 comprises a housing 504, a conduit 542, an inlet 546 and an outlet 544. Housing 504 is substantially cylindrical and has an axial passage 508 extending along its entire length and a connecting lateral passage adjacent to its upper end; the lateral passage leads to outlet 544. The lower end of housing 504 is adapted to attach to the upper end of choke body 500 at clamp 506. Axial passage 508 has a reduced diameter portion at its upper end; conduit 542 is located inside axial passage 508 and extends through axial passage 508 as a continuation of the reduced diameter portion. The rest of axial passage 508 beyond the reduced diameter portion is of a larger diameter than conduit 542, creating an annulus 520 between the outside surface of conduit 542 and axial passage 508. Conduit 542 extends beyond housing 504 into choke body 500, and past the junction between branch 10 and its perpendicular extension. At this point, the perpendicular extension of branch 10 becomes an outlet 530 of branch 10; this is the same outlet as shown in the
The diverter assembly 502 can be used to recover fluids from or inject fluids into a well. A method of recovering fluids will now be described.
In use, produced fluids come up the production bore 1, enter branch 10 and from there enter annulus 520 between conduit 542 and axial passage 508. The fluids are prevented from going downwards towards outlet 530 by seal 532, so they are forced upwards in annulus 520, exiting annulus 520 via outlet 544. Outlet 544 typically leads to a processing apparatus (which could be any of the ones described earlier, e.g. a pumping or injection apparatus). Once the fluids have been processed, they are returned through a further conduit (not shown) to inlet 546. From here, the fluids pass through the inside of conduit 542 and exit though outlet 530, from where they are recovered via an export line.
To inject fluids into the well, the embodiments of
It is very common for manifolds of various types to have a choke; the
A further embodiment is shown in
Outlet 544 is coupled via a conduit (not shown) to processing apparatus 550, which is in turn connected to an inlet of choke 540. Choke 540 is a standard choke, having an inner passage with an outlet at its lower end and an inlet 541. The lower end of passage 540 is aligned with inlet 546 of axial passage 508 of housing 504; thus the inner passage of choke 540 and axial passage 508 collectively form one combined axial passage.
A method of recovering fluids will now be described. In use, produced fluids from production bore 1 enter branch 10 and from there enter annulus 520 between conduit 542 and axial passage 508. The fluids are prevented from going downwards towards outlet 530 by seal 532, so they are forced upwards in annulus 520, exiting annulus 520 via outlet 544. Outlet 544 typically leads to a processing apparatus (which could be any of the ones described earlier, e.g. a pumping or injection apparatus). Once the fluids have been processed, they are returned through a further conduit (not shown) to the inlet 541 of choke 540. Choke 540 may be opened, or partially opened as desired to control the pressure of the produced fluids. The produced fluids pass through the inner passage of the choke, through conduit 542 and exit though outlet 530, from where they are recovered via an export line.
The
Conduit 542 does not necessarily form an extension of axial passage 508. Alternative embodiments could include a conduit which is a separate component to housing 504; this conduit could be sealed to the upper end of axial passage 508 above outlet 544, in a similar way as conduit 542 is sealed at seal 532.
Embodiments of the invention can be retrofitted to many different existing designs of manifold, by simply matching the positions and shapes of the hydraulic control channels 3 in the cap, and providing flow diverting channels or connected to the cap which are matched in position (and preferably size) to the production, annulus and other bores in the tree or other manifold.
Referring now to
The tree has a production wing 620 and associated production wing valve 610. The production wing 620 terminates in a production choke body 630. The production choke body 630 has an interior bore 607 extending therethrough in a direction perpendicular to the production wing 620. The bore 607 of the production choke body is in communication with the production wing 620 so that the choke body 630 forms an extension portion of the production wing 620. The opening at the lower end of the bore 607 comprises an outlet 612. In prior art trees, a choke is usually installed in the production choke body 630, but in the tree 601 of the present invention, the choke itself has been removed.
Similarly, the tree 601 also has an annulus wing 621, an annulus wing valve 611, an annulus choke body 631 and an interior bore 609 of the annulus choke body 631 terminating in an inlet 613 at its lower end. There is no choke inside the annulus choke body 631.
Attached to the production choke body 630 of the production wing 620 is a first diverter assembly 604 in the form of a production insert. The diverter assembly 604 is very similar to the flow diverter assemblies of
The production insert 604 comprises a substantially cylindrical housing 640, a conduit 642, an inlet 646 and an outlet 644. The housing 640 has a reduced diameter portion 641 at an upper end and an increased diameter portion 643 at a lower end.
The conduit 642 has an inner bore 649, and forms an extension of the reduced diameter portion 641. The conduit 642 is longer than the housing 640 so that it extends beyond the end of the housing 640.
The space between the outer surface of the conduit 642 and the inner surface of the housing 640 forms an axial passage 647, which ends where the conduit 642 extends out from the housing 640. A connecting lateral passage is provided adjacent to the join of the conduit 642 and the housing 640; the lateral passage is in communication with the axial passage 647 of the housing 640 and terminates in the outlet 644.
The lower end of the housing 640 is attached to the upper end of the production choke body 630 at a clamp 648. The conduit 642 is sealingly attached inside the inner bore 607 of the choke body 630 at an annular seal 645.
Attached to the annular choke body 631 is a second diverter assembly 605. The second diverter assembly 605 is of the same form as the first diverter assembly 604. The components of the second diverter assembly 605 are the same as those of the first diverter assembly 604, including a housing 680 comprising a reduced diameter portion 681 and an enlarged diameter portion 683; a conduit 682 extending from the reduced diameter portion 681 and having a bore 689; an outlet 686; an inlet 684; and an axial passage 687 formed between the enlarged diameter portion 683 of the housing 680 and the conduit 682. A connecting lateral passage is provided adjacent to the join of the conduit 682 and the housing 680; the lateral passage is in communication with the axial passage 687 of the housing 680 and terminates in the inlet 684. The housing 680 is clamped by a clamp 688 on the annulus choke body 631, and the conduit 682 is sealed to the inside of the annulus choke body 631 at seal 685.
A conduit 690 connects the outlet 644 of the first diverter assembly 604 to a processing apparatus 700. In this embodiment, the processing apparatus 700 comprises bulk water separation equipment, which is adapted to separate water from hydrocarbons. A further conduit 692 connects the inlet 646 of the first diverter assembly 604 to the processing apparatus 700. Likewise, conduits 694, 696 connect the outlet 686 and the inlet 684 respectively of the second diverter assembly 605 to the processing apparatus 700. The processing apparatus 700 has pumps 820 fitted into the conduits between the separation vessel and the first and second flow diverter assemblies 604, 605.
The production bore 602 and the annulus bore 603 extend down into the well from the tree 601, where they are connected to a tubing system 800a, shown in
The tubing system 800a is adapted to allow the simultaneous injection of a first fluid into an injection zone 805 and production of a second fluid from a production zone 804. The tubing system 800a comprises an inner tubing 810 which is located inside an outer tubing 812. The production bore 602 is the inner bore of the inner tubing 810. The inner tubing 810 has perforations 814 in the region of the production zone 804. The outer tubing has perforations 816 in the region of the injection zone 805. A cylindrical plug 801 is provided in the annulus bore 603 which lies between the outer tubing 812 and the inner tubing 810. The plug 801 separates the part of the annulus bore 803 in the region of the injection zone 805 from the rest of the annulus bore 803.
In use, the produced fluids (typically a mixture of hydrocarbons and water) enter the inner tubing 810 through the perforations 814 and pass into the production bore 602. The produced fluids then pass through the production wing 620, the axial passage 647, the outlet 644, and the conduit 690 into the processing apparatus 700. The processing apparatus 700 separates the hydrocarbons from the water (and optionally other elements such as sand), e.g. using centrifugal separation. Alternatively or additionally, the processing apparatus can comprise any of the types of processing apparatus mentioned in this specification.
The separated hydrocarbons flow into the conduit 692, from where they return to the first diverter assembly 604 via the inlet 646. The hydrocarbons then flow down through the conduit 642 and exit the choke body 630 at outlet 612, e.g. for removal to the surface.
The water separated from the hydrocarbons by the processing apparatus 700 is diverted through the conduit 696, the axial passage 687, and the annulus wing 611 into the annulus bore 603. When the water reaches the injection zone 805, it passes through the perforations 816 in the outer tubing 812 into the injection zone 805.
If desired, extra fluids can be injected into the well in addition to the separated water. These extra fluids flow into the second diverter assembly 631 via the inlet 613, flow directly through the conduit 682, the conduit 694 and into the processing apparatus 700. These extra fluids are then directed back through the conduit 696 and into the annulus bore 603 as explained above for the path of the separated water.
The outer tubing 822, which generally extends round the circumference of the inner tubing 820, is split into a plurality of axial tubes in the region of the production zone 824. This allows fluids from the production zone 824 to pass between the axial tubes and through the perforations 836 in the inner tubing 820 into the production bore 602. From the production bore 602 the fluids pass upwards into the tree as described above. The returned injection fluids in the annulus bore 603 pass through the perforations 834 in the outer tubing 822 into the injection zone 825.
The
The pumps 820 are optional.
The tubing system 800a, 800b could be any system that allows both production and injection; the system is not limited to the examples given above. Optionally, the tubing system could comprise two conduits which are side by side, instead of one inside the other, one of the conduits providing the production bore and the second providing the annulus bore.
A diverter assembly 904 in the form of a production insert is located in the production wing branch 920 between the production wing valve 910 and the production choke 930. The diverter assembly 904 is the same as the diverter assembly 604 of the
The lower end of the conduit 942 is sealed inside the production wing branch 920 at a seal 945. The production wing branch 920 includes a secondary branch 921 which connects the part of the production wing branch 920 adjacent to the diverter assembly 904 with the part of the production wing branch 920 adjacent to the production choke 930. A valve 922 is located in the production wing branch 920 between the diverter assembly 904 and the production choke 930.
The combination of the valve 922 and the seal 945 prevents production fluids from flowing directly from the production bore 902 to the outlet 912. Instead, the production fluids are diverted into the axial annular passage 947 between the conduit 942 and the housing 940. The fluids then exit the outlet 944 into a processing apparatus (examples of which are described above), then re-enter the diverter assembly via the inlet 946, from where they pass through the conduit 942, through the secondary branch 921, the choke 930 and the outlet 912.
The diverter assembly 1004 is sealed within the branch extension 1021 at a seal 1045. A valve 1022 is located in the branch extension 1021 below the diverter assembly 1004.
The branch extension 1021 comprises a primary passage 1060 and a secondary passage 1061, which departs from the primary passage 1060 on one side of the valve 1022 and rejoins the primary passage 1060 on the other side of the valve 1022.
Production fluids pass through the choke 1030 and are diverted by the valve 1022 and the seal 1045 into the axial annular passage 1047 of the diverter assembly 1004 to an outlet 1044. They are then typically processed by a processing apparatus, as described above, and then they are returned to the bore 1049 of the diverter assembly 1004, from where they pass through the secondary passage 1061, back into the primary passage 1060 and out of the outlet 1012.
The embodiments of
A first diverter assembly 704 is connected to a branch of a first production well A. The diverter assembly 704 comprises a conduit (not shown) sealed within the bore of a choke body to provide a first flow region inside the bore of the conduit and a second flow region in the annulus between the conduit and the bore of the choke body. It is emphasised that the diverter assembly 704 is the same as the diverter assembly 604 of
The bore of the conduit has an inlet 712 and an outlet 746 (inlet 712 corresponds to outlet 612 of
The annular passage between the conduit and the choke body is in communication with the production wing branch of the tree of the first well A, and with the outlet 744 (which corresponds to the outlet 644 in
Likewise, a second diverter assembly 714 is connected to a branch of a second production well B. The second diverter assembly 714 is the same as the first diverter assembly 704, and is located in a production wing branch in the same way. The bore of the conduit of the second diverter assembly has an inlet 756 (corresponding to the inlet 646 in
The annular passage between the conduit and the inside of the choke body connects the production wing branch to an outlet 754 (which corresponds to the outlet 644 of
The outlets 746, 744 and 754 are all connected via tubing to the inlet of a pump 750. Pump 750 then passes all of these fluids into the inlet 756 of the second diverter assembly 714. Optionally, further fluids from other wells (not shown) are also pumped by pump 750 and passed into the inlet 756.
In use, the second diverter assembly 714 functions in the same way as the diverter assembly 604 of the
The first diverter assembly 704 functions differently because the produced fluids from the first well 702 are not returned to the first diverter assembly 704 once they leave the outlet 744 of the annulus. Instead, both of the flow regions inside and outside of the conduit have fluid flowing in the same direction. Inside the conduit (the first flow region), fluids flow upwards from the inlet header 701 straight through the conduit to the outlet 746. Outside of the conduit (the second flow region), fluids flow upwards from the production bore of the first well 702 to the outlet 744.
Both streams of upwardly flowing fluids combine with fluids from the outlet 754 of the second diverter assembly 714, from where they enter the pump 750, pass through the second diverter assembly into the outlet header 703, as described above.
It should be noted that the tree 601 is a conventional tree but the invention can also be used with horizontal trees.
One or both of the flow diverter assemblies of the
The processing apparatus 700 could be one or more of a wide variety of equipment. For example, the processing apparatus 700 could comprise any of the types of equipment described above with reference to
The above described flow paths could be completely reversed or redirected for other process requirements.
The choke body 1112 is a standard subsea choke body from which the original choke has been removed. The choke body 1112 has a bore which is in fluid communication with the production wing branch 1114. The upper end of the bore of the choke body 1112 terminates in an aperture in the upper surface of the choke body 1112. The lower end of the bore of the choke body communicates with the bore of the production wing branch 1114 and the outlet 1118.
The diverter assembly 1110 has a cylindrical housing 1120, which has an interior axial passage 1122. The lower end of the axial passage 1122 is open; i.e. it terminates in an aperture. The upper end of the axial passage 1122 is closed, and a lateral passage 1126 extends from the upper end of the axial passage 1122 to an outlet 1124 in the side wall of the cylindrical housing 1120.
The diverter assembly 1110 has a stem 1128 which extends from the upper closed end of the axial passage 1122, down through the axial passage 1122, where it terminates in a plug 1130. The stem 1128 is longer than the housing 1120, so the lower end of the stem 1128 extends beyond the lower end of the housing 1120. The plug 1130 is shaped to engage a seat in the choke body 1112, so that it blocks the part of the production wing branch 1114 leading to the outlet 1118. The plug therefore prevents fluids from the production wing branch 1114 or from the choke body 1112 from exiting via the outlet 1118. The plug is optionally provided with a seal, to ensure that no leaking of fluids can take place.
Before fitting the diverter assembly 1110 to the tree 1116, a choke is typically present inside the choke body 1112 and the outlet 1118 is typically connected to an outlet conduit, which conveys the produced fluids away e.g. to the surface. Produced fluids flow through the bore of the christmas tree 1116, through valves V1 and V2, through the production wing branch 1114, and out of outlet 1118 via the choke.
The diverter assembly 1110 can be retrofitted to a well by closing one or both of the valves V1 and V2 of the christmas tree 1116. This prevents any fluids leaking into the ocean whilst the diverter assembly 1110 is being fitted. The choke (if present) is removed from the choke body 1112 by a standard removal procedure known in the art. The diverter assembly 1110 is then clamped onto the top of the choke body 1112 by the clamp 1119 so that the stem 1128 extends into the bore of the choke body 1112 and the plug 1130 engages a seat in the choke body 1112 to block off the outlet 1118. Further pipework (not shown) is then attached to the outlet 1124 of the diverter assembly 1110. This further pipework can now be used to divert the fluids to any desired location. For example, the fluids may be then diverted to a processing apparatus, or a component of the produced fluids may be diverted into another well bore to be used as injection fluids.
The valves V1 and V2 are now re-opened which allows the produced fluids to pass into the production wing branch 1114 and into the choke body 1112, from where they are diverted from their former route to the outlet 1118 by the plug 1130, and are instead diverted through the diverter assembly 1110, out of the outlet 1124 and into the pipework attached to the outlet 1124.
Although the above has been described with reference to recovering produced fluids from a well, the same apparatus could equally be used to inject fluids into a well, simply by reversing the flow of the fluids. Injected fluids could enter the diverter assembly 1110 at the aperture 1124, pass through the diverter assembly 1110, the production wing branch 14 and into the well. Although this example has described a production wing branch 1114 which is connected to the production bore of a well, the diverter assembly 1110 could equally be attached to an annulus choke body connected to an annulus wing branch and an annulus bore of the well, and used to divert fluids flowing into or out from the annulus bore. An example of a diverter assembly attached to an annulus choke body has already been described with reference to
The housing 1120′ in the diverter assembly 1110′ is cylindrical with an axial passage 1122′. However, in this embodiment, there is no lateral passage, and the upper end of the axial passage 1122′ terminates in an aperture 1130′ in the upper end of the housing 1120′, so that the upper end of the housing 1120′ is open. Thus, the axial passage 1122′ extends all of the way through the housing 1120′ between its lower and upper ends. The aperture 1130′ can be connected to external pipework (not shown).
The housing 1120″ of the
The housing 1120″ is provided with an extension portion in the form of a conduit 1132″, which extends from near the upper end of the housing 1120″, down through the axial passage 1122″ to a point beyond the end of the housing 1120″. The conduit 1132″ is therefore internal to the housing 1120″, and defines an annulus 1134″ between the conduit 1132″ and the housing 1120″.
The lower end of the conduit 1132″ is adapted to fit inside a recess in the choke body 1112, and is provided with a seal 1136, so that it can seal within this recess, and the length of conduit 1132″ is determined accordingly.
As shown in
In use, the embodiments of
In the
The embodiments of
In the
To recover fluids from a well, the fluids travel up through the production bore of the tree; they cannot pass into through the wing branch 1114 because of the V2 valve which is closed, and they are instead diverted into the cap 1140. The fluids pass through the conduit 1146, through the processing apparatus 1148 and they are then conveyed to the axial passage 1122′ by the conduit 1150. The fluids travel down the axial passage 1122′ to the aperture 1118 and are recovered therefrom via a standard outlet line connected to this aperture.
To inject fluids into a well, the direction of flow is reversed, so that the fluids to be injected are passed into the aperture 1118 and are then conveyed through the axial passage 1122′, the conduit 1150, the processing apparatus 1148, the conduit 1146, the cap 1140 and from the cap directly into the production bore of the tree and the well bore.
This embodiment therefore enables fluids to travel between the well bore and the aperture 1118 of the wing branch 1114, whilst bypassing the wing branch 1114 itself. This embodiment may be especially in wells in which the wing branch valve V2 has stuck in the closed position. In modifications to this embodiment, the first conduit does not lead to an aperture in the tree cap. For example, the first conduit 1146 could instead connect to an annulus branch and an annulus bore; a crossover port could then connect the annulus bore to the production bore, if desired. Any opening into the tree manifold could be used. The processing apparatus could comprise any of the types described in this specification, or could alternatively be omitted completely.
These embodiments have the advantage of providing a safe way to connect pipework to the well, without having to disconnect any of the existing pipework, and without a significant risk of fluids leaking from the well into the ocean.
The uses of the invention are very wide ranging. The further pipework attached to the diverter assembly could lead to an outlet header, an inlet header, a further well, or some processing apparatus (not shown). Many of these processes may never have been envisaged when the christmas tree was originally installed, and the invention provides the advantage of being able to adapt these existing trees in a low cost way while reducing the risk of leaks.
In use, inlet 406 is connected to a gas injection line 414. Gas is pumped from gas injection line 414 into christmas tree cap 40e, and is diverted by plug 408 down into coil tubing insert 410; the gas mixes with the production fluids in the well. The gas reduces the density of the produced fluids, giving them “lift”. The mixture of oil well fluids and gas then travels up production bore 1, in the annulus between production bore 1 and coil tubing insert 410. This mixture is prevented from travelling into cap 40e by plug 408; instead it is diverted into branch 10 for recovery therefrom.
This embodiment therefore divides the production bore into two separate regions, so that the production bore can be used both for injecting gases and recovering fluids. This is in contrast to known methods of inject fluids via an annulus bore of the well, which cannot work if the annulus bore becomes blocked. In the conventional methods, which rely on the annulus bore, a blocked annulus bore would mean the entire tree would have to be removed and replaced, whereas the present embodiment provides a quick and inexpensive alternative.
In this embodiment, the diverter assembly is the coil tubing insert 410 and the annular sealing plug 412.
A booster pump (not shown) is connected between the outlet 44 and the inlet 46. The top end of conduit 42 is sealingly connected at annular seal 416 to inner axial passage 402 above inlet 46 and below outlet 44. Annular sealing plug 412 of coil tubing insert 410 lies between outlet 44 and gas inlet 406.
In use, as in the
This embodiment is therefore similar to the
Modifications and improvements may be incorporated without departing from the scope of the invention. For example, as stated above, the diverter assembly could be attached to an annulus choke body, instead of to a production choke body.
It should be noted that the flow diverters of
Likewise, the methods shown in
The method of
Therefore, with this modification, single flowpath embodiments could also be used for the production well. This method can therefore be achieved with a diverter assembly located in the production/annulus bore or in a wing branch, and with most of the embodiments of diverter assembly described in this specification.
Likewise, the method of
The
Therefore, as illustrated by the examples in
All of the diverter assemblies shown and described can be used for both recovery of fluids and injection of fluids by reversing the flow direction.
Any of the embodiments which are shown connected to a production wing branch could instead be connected to an annulus wing branch, or another branch of the tree. The embodiments of
Number | Date | Country | Kind |
---|---|---|---|
0312543.2 | May 2003 | GB | national |
0405454.0 | Mar 2004 | GB | national |
0405471.4 | Mar 2004 | GB | national |
This application is a divisional of U.S. application Ser. No. 13/687,290 filed Nov. 28, 2012, which is a divisional of U.S. application Ser. No. 13/164,291 (now U.S. Pat. No. 8,469,086) filed Jun. 20, 2011, which is a divisional of U.S. application Ser. No. 10/558,593 (now U.S. Pat. No. 7,992,643) filed Nov. 29, 2005, which is a U.S. National Phase Application of PCT/GB2004/002329 filed Jun. 1, 2004, which is a continuation-in-part of U.S. application Ser. No. 10/651,703 (now U.S. Pat. No. 7,111,687) filed Aug. 29, 2003, which is a continuation-in-part of U.S. Ser. No. 10/009,991 filed Jul. 16, 2002 (now U.S. Pat. No. 6,637,514), and claims the benefit of British Application No. 0312543.2 filed May 31, 2003, U.S. Provisional Application No. 60/548,727 filed Feb. 26, 2004, British Application No. 0405471.4 filed Mar. 11, 2004, and British Application No. 0405454.0 filed Mar. 11, 2004, all of which are incorporated herein by reference in their entireties for all purposes.
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Number | Date | Country | |
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20140238687 A1 | Aug 2014 | US |
Number | Date | Country | |
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60548727 | Feb 2004 | US |
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Child | 14266936 | US | |
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Child | 13687290 | US | |
Parent | 10558593 | US | |
Child | 13164291 | US |
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Parent | 10651703 | Aug 2003 | US |
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Parent | 10009991 | Jul 2002 | US |
Child | 10651703 | US |