U.S. patent application number 10/239910 was filed with the patent office on 2003-09-11 for riser with retrievable internal services.
Invention is credited to Abraham, William Eric, Herd, Brendan Paul, Seymour, Ben.
Application Number | 20030170077 10/239910 |
Document ID | / |
Family ID | 26243968 |
Filed Date | 2003-09-11 |
United States Patent
Application |
20030170077 |
Kind Code |
A1 |
Herd, Brendan Paul ; et
al. |
September 11, 2003 |
Riser with retrievable internal services
Abstract
Systems are described for raising production fluid from a source
(1) on the seabed comprising a riser (4) having a first, lower, end
for connection or connected to the source; a top end support for
supporting the riser at or in the vicinity of the sea surface; and
an operating device (11) mounted inside the riser (4) for
displacement within the riser so that the pump is accessible to an
operator for replacement or repair. The operating device (11) may
be displaced on a pipe (12) which extends within the riser (4) and
to a lower end of which the device (11) is attached. The device
(11) may be inter alia an electric pump, a hydraulic pump, a gas
injector, a heater or a cleaning device.
Inventors: |
Herd, Brendan Paul;
(Middlesex, GB) ; Seymour, Ben; (Surrey, GB)
; Abraham, William Eric; (Surrey, GB) |
Correspondence
Address: |
Leopold Presser
Scully Scott Murphy & Presser
400 Garden City Plaza
Garden City
NY
11530
US
|
Family ID: |
26243968 |
Appl. No.: |
10/239910 |
Filed: |
February 11, 2003 |
PCT Filed: |
March 26, 2001 |
PCT NO: |
PCT/EP01/03405 |
Current U.S.
Class: |
405/224.2 ;
166/350; 166/367; 405/224 |
Current CPC
Class: |
E21B 43/128 20130101;
E21B 17/015 20130101; E21B 43/01 20130101 |
Class at
Publication: |
405/224.2 ;
405/224; 166/350; 166/367 |
International
Class: |
E02D 005/54; E21B
007/12 |
Foreign Application Data
Date |
Code |
Application Number |
Mar 27, 2000 |
GB |
00074606.2 |
Oct 11, 2000 |
GB |
0024931.8 |
Claims
1. A system for raising production fluid from a source on the
seabed, comprising:--a riser having an internal passageway for
conveying said production fluid and having a first, lower, end for
connection to or a top end support for supporting the riser at its
second end at or in the vicinity of the sea surface; and an
operating device mounted inside the riser for displacement within
the riser between a first, operating, position in the riser remote
from its second end, and a second, access, position, at the second
end of the riser, so that the device is accessible for replacement
or repair, the operating device being a pump or a gas injector.
2. A system according to claim 1 and further comprising means for
displacing the device in the riser between the operating and access
positions.
3. A system according to claim 2, wherein the displacing means
includes a pipe which extends within the riser and to a lower end
of which the device is attached.
4. A system according to claim 3, wherein the device is an electric
pump and an electric power supply cable for the pump passes through
the pipe.
5. A system according to claim 3, wherein said pipe is connected to
supply fluid from the upper end of the riser down to the operating
device.
6. A system according to claim 5, wherein a further pipe is
provided within the riser and is connected to function as a return
pipe for conveying fluid from the operating device to the upper end
of the riser.
7. A system according to claim 6, wherein the supply and return
pipes form a nested pipe arrangement.
8. A system according to claim 5, wherein the device is a hydraulic
pump and the pipe is arranged to convey hydraulic fluid down to the
pump, which is arranged to discharge the hydraulic fluid into the
production fluid passing up the riser.
9. A system according to claim 6 or 7, wherein the device is a
hydraulic pump, the supply pipe being arranged for delivering
hydraulic fluid down to the pump and the return pipe being arranged
for conveying hydraulic fluid from the pump back up the riser.
10. A system according to any one of claims 5 to 9, wherein the
operating device is a hydraulic pump and means are provided for
delivering heated fluid through the supply pipe for heating
production fluid in the riser.
11. A system according to any one of claims 3 to 9, wherein there
is associated with said device a heater for heating said production
fluid in the riser.
12. A system according to claim 10, wherein a heater is provided in
the region of the hydraulic pump, the heater being arranged to be
supplied by said heated fluid delivered through said pipe.
13. A system according to any one of claims 3 to 12, wherein the
displacing means includes a pipe dispensing and retrieving
apparatus on the top end support or an attendant service vessel,
such apparatus comprising a rotatable pipe storage device on which
the or each pipe is wound, a pipe straightener and drive means for
the storage device, selectively operable for straightening a length
of pipe and driving it downwardly into the riser to lower the
device to said first position and to wind in the or each pipe to
raise the device to said second position.
14. A system according to any preceding claim, wherein a pig
introducing device is provided for introducing a pig into the riser
at a position below the operating device when in said second
position.
15. A system according to any preceding claim, further comprising a
locating device which is mounted on the operating device, and is
selectively operable for (i) engaging with the inner surface of the
riser and (ii) disengaging therefrom so that the operating device
can be repositioned in the riser.
16. A system according to claim 15, wherein the operating device is
a pump and the locating device is a sealing device which is
operable for both engaging and sealing with the inner surface of
the riser so that the pump can pump production fluid in the riser
from a low pressure side of the sealing device to a high pressure
side.
17. A system according to claim 16, wherein the sealing device
comprises a packer mounted on the pump and an inflatable sealing
element operable for forming sealing contact with the inner surface
of the riser.
18. A system according to any preceding claim, wherein in addition
to said passageway for carrying the production fluid, a second
passageway is provided in the riser for connection to a low
pressure region in the vicinity of the upper end of the riser and
means are provided for expelling production fluid from the first
passageway to said low pressure region, so as to reduce the
pressure in the first passageway to a lower value than the existing
under interrupted on shutdown conditions, thereby inhibiting
formation of solid hydrates in the first passageway.
19. A system according to claim 18, wherein the production fluid
expelling means comprises a one-way valve providing fluid
communication from the first passageway to the second passageway, a
source of pressure gas operable for introducing gas under pressure
to the first passageway to expel production fluid therefrom through
the one-way valve, and means for venting the gas pressure in the
first passageway to said region of lower pressure.
20. A system according to claim 18, wherein the production fluid
expelling means is said pump.
21. A system according to any one of claims 4 to 10, further
comprising a cyclone separator mounted on the pipe for positioning
within the riser and having inlet means for imparting swirl to
production fluid entering the separator from the riser to effect
separation of the fluid into a liquid-rich underflow and a gas-rich
overflow, the operating device being a pump, said pump being
arranged to receive the separator underflow and pump it up to the
top of the riser through said pipe.
22. A system according to claim 8 or 9 or any dependent claim
thereof, wherein said hydraulic pump comprises a pump section,
turbine section and a packer section, the packer section being
articulated relative to the pump section.
23. A system according to claim 22, wherein the articulation
comprises a universal drive coupling or a flexible coupling.
24. A system according to claims 3 to 13, further comprising a
traction device on the pipe operable for applying traction to the
pipe to drive the operating device down inside the riser.
25. A system according to claim 24, wherein the traction device is
selectively operable from the remote end of the pipe for applying
traction to the pipe in either direction for lowering or raising
the operating device.
26. A system according to claim 24 or claim 25 as dependent on any
of claims 4 to 10, wherein the operating device is a pump and a
sealing device is mounted on the pump and is arranged to provide a
sliding seal with the inner surface of the riser, the pump being
arranged to pump between a low pressure and a high pressure side of
the sealing device so as to generate a traction force for driving
the down-riser pump longitudinally within the riser, the pump and
sealing device together constituting said traction device.
27. A system according to any one of claims 3 to 13, comprising a
motor mounted on a lower end of the pipe and arranged to be powered
electrically or hydraulically from an upper end of the riser, and a
rotary cleaning device.
28. A system according to claim 27, as dependent on any of claims 4
to 10, wherein a sealing device on the motor is arranged to form a
sliding seal with the inner surface of the riser.
29. A system according to claim 28, as dependent on any of claims 4
to 10 wherein said pump is arranged to provide differential
pressure between a low pressure side and a high pressure side of
the sealing device.
30. A system according to claim 28 or 29, wherein the rotary
cleaning device is arranged to generate a differential pressure
between one side and the other side thereof when it is
rotating.
31. A system according to any one of claims 27 to 30, wherein the
cleaning device comprises at least one of a rotary cutter and a
rotary brush.
32. A system according to any one of claims 27 to 31, wherein the
motor is an electric motor which is arranged to be powered by an
electrical cable passing through said pipe.
33. A system according to any one of the preceding claims, wherein
said riser has a lazy-S, steep wave or steep-S configuration.
34. A system according to any one of claims 1 to 32, wherein said
riser has a substantially vertical complaint section, leading from
the sea bed to the surface, a substantially horizontal section on
the sea bed, and a bend section connecting the substantially
vertical and horizontal riser sections.
35. A system according to any one of claims 3 to 11, wherein said
device comprises a gas injector for introducing pressure gas into
the riser when in said first position.
36. A method of installing an operating device in a riser
connecting a source of production fluid on the seabed to a top end
support supporting the riser at or in the vicinity of the sea
surface, the operating device being a pump or a gas injector, the
method comprising:--(a) introducing the device into the riser at
the upper end thereof; and (b) driving the device downwardly into
the riser to a desired operating position in the riser remote from
its end at the top end support.
37. A method according to claim 36, wherein the device is attached
to the lower end of a rigid pipe and the pipe is driven downwardly
into the riser to displace the device to its desired operating
position.
38. A method according to claim 36 or claim 37 comprising the
further steps of:--(c) driving the pipe upwardly to raise the
device within the riser to the top end support; (d) removing the
device from the riser; (e) disconnecting the device from the pipe,
for maintenance or replacement, and (f) repeating steps (a) and (b)
with the maintained or replaced device.
39. A method according to claim 37, comprising the further steps
of:--(c) driving the pipe upwardly to raise the device within the
riser to the top end support; (d) removing the device from the
riser; (e) disconnecting the device from the pipe; (f) removing an
end section of the pipe or attaching a new section of pipe to the
existing pipe in order to define a new length of pipe; (g)
attaching the device to the end of the new length of pipe; and (h)
driving the device down the riser to its new operative position in
the riser.
40. A method according to any one of claims 36 to 39, further
comprising at least partially expelling the production fluid from
the riser interior, so as to reduce the pressure acting there, in
order to inhibit formation of solid hydrates in the production
fluid flowing from the source under interrupted flow or shut down
conditions.
41. A method according to claim 40, wherein said operating device
is a pump and said pump is used for at least partially expelling
the production fluid.
42. A method according to claim 40, wherein gas is introduced under
pressure into the riser to at least partially expel the production
fluid and the gas pressure acting in the riser is reduced to a
value lower than its initial value while preventing the expelled
production fluid from returning to the space occupied by the
gas.
43. A method according to claim 42, wherein a hydrate formation
inhibitor is introduced into the riser along with the gas under
pressure.
Description
[0001] This invention relates to riser systems and methods for
raising production fluid within the riser system downstream of a
subsea source or plurality of sources.
[0002] Various techniques are known for raising hydrocarbon
production fluids, typically crude oil, gas and water forming a
three-phase fluid, from an undersea source on the seabed.
Situations where this need exists are the lifting of production
fluid from an offshore well to the surface of the sea for
separation into different constituents of the production fluids, or
from a seabed pipeline coming from a remote well or storage
facility. It is known to use a riser for this purpose, the riser
extending from the subsea source to the surface of the sea, to an
elevated position above the surface of the sea, or to a submerged
location at a relatively small distance below the sea surface. The
riser may extend generally upwardly or vertically from the subsea
source. Alternatively, it may comprise a section (known as a
flowline) running along the sea bed from the source, a riser
section extending upwardly and a bend section connecting the
flowline and riser sections. A subsea drilling system using a
tensioned riser is described in U.S. Pat. No. 5,474,601. The riser
comprises a tubular conductor within which passes a tubing string
for conveying oil to the surface from a dummy well.
[0003] In many cases, there is initially sufficient pressure at the
foot of the riser to overcome the static head of the fluid column
in the production riser used to convey the fluid to the surface of
the sea. However, with the passage of time, the pressure in the
well decreases and may reach a point at which it alone is
insufficient. In some cases, the pressure at the riser base may be
inadequate from the outset.
[0004] Where the pressure is insufficient, gas under pressure is
used extensively to provide lift to enable heavy liquids to be
raised from the base of the riser. This is common practice in
relatively shallow water depths whose riser temperature loss and
pressure reduction are not excessive. However, for deepwater fields
(such as 350 metres and beyond) and/or where the reservoir is
shallow and cold and the reservoir fluid is inherently gassy or
multiphase, gas injection can give rise to operational difficulties
such as "slugging" (the formation of "slugs" of liquid separated by
gas bubbles), temperature loss during gas expansion, hydrate
formation and high fluid velocities in upper regions of the riser
due to the reduced fluid head there, which can cause erosion or
corrosion of the material of the riser wall.
[0005] To address these problems, it is known to use a subsea pump,
either a hydraulic-driven submersible pump (HSP) or
electrically-driven submersible pump (ESP), which is connected in
series with the lower inlet end of the riser to add pressure energy
to the production fluids coming from the well, to drive the fluids
up the riser to the facility such as top end buoyancy unit,
floating production platform or free-standing platform, connected
to the upper end of the riser. This offers the advantages not only
of lifting fluids that would otherwise not flow but also of
reducing the free gas in the hydrocarbon fluids raised to the
production facility, the heat loss from the hydrocarbon fluids and
the fluid delivery velocity from the riser. It also avoids having
to provide a source of high pressure gas and an external gas
injection riser.
[0006] For a conventional arrangement, the or each subsea pump is
positioned externally of and to one side of the riser. However,
this siting is undesirable for the following reasons. Firstly,
external facilities are required to install the pump near to the
seabed, and installation becomes increasingly difficult when
working at large sea depths. Secondly, it is time-consuming to
repair or replace the pump, since it is not readily accessible. In
practice, a maintenance vessel with trained crew has to be called,
which travels to the offshore site. Then the crew have to repair or
replace the pump by remote handling from the surface, where this is
possible. Although this is a time-consuming operation, it is used
where possible, but only a limited number of relatively
straightforward repairs are feasible in this way. In many cases,
the crew have to remotely disconnect the subsea pump and hoist it
up in the sea to the maintenance vessel, where it can be repaired
or replaced (if a second redundant pump is not incorporated in the
system). The new or repaired pump is then lowered to the sea bed
and reconnected to the riser. Whilst the described operations can
be done satisfactorily, the time taken can be significant because
of working with a pump located under water at a comparatively great
depth. The relatively high time factor involved is very undesirable
and, when no redundant pump has been incorporated, results in lost
production time and therefore lost revenue.
[0007] U.S. Pat. No. 5,474,601 describes a system in which an
electric pump is located near the lower end of a dummy well in the
ocean floor. The pump is supplied by a power cable passing up the
dummy well, then up the riser to a floating production
platform.
[0008] U.S. Pat. No. 4,705,114 describes a tubular steel riser
connected between the ocean surface and a sump embedded in the
ocean floor and containing a downhole pump. Concentric pipes pass
up the riser to convey liquid and gas separately to a manifold cap
at the top of the riser. The installation of the pump is not
discussed.
[0009] In subsea production systems, the hydrocarbon fluids are
transported from one or more seabed located wellheads to the
receiving facility located at the sea surface by one or more seabed
flowlines and risers. During periods when flow is interrupted and
flow ceases, the fluids come to rest and are subjected to pressure
generated by the shut-in pressure at the riser top and the
hydrostatic head resulting from the liquid held in the riser
column. This `residual pressure` when combined with decreasing
temperature as the fluids cool, leads to the formation of solid
hydrates which in turn can result in blockage and an inability to
produce fluids at restart. To cope with flow interruptions, active
conventional methods available to control hydrates include addition
of chemicals and active heat addition (electrical or fluid heating
tubes). Passive methods include very low heat loss insulation and
depressurisation.
[0010] The active methods require the continuous availability of
chemicals and/or heat. Use of low heat loss insulation extends coot
down time, but on its own is not a sufficient guarantee against
blockage if the system cools down completely, unless combined with
active methods. Depressurisation below a pressure appropriate to
the fluid head at the riser top requires a second access conduit
located between the riser tubing head and the wellhead end. This is
normally an external pipeline with external crossovers into the
hydrocarbon flowline. Such equipment adds to cost and
complexity.
[0011] In conventional riser systems, transportation of multiphase
fluids from a wellhead via a flowline and riser results in the
generation of gas and liquid slugs which, when received at the
destination facility, can result in process system interruption and
damage to pipework and related mechanical components. The severity
of slugging becomes worse as the transport distance increases
and/or where large elevation changes occur, as are found in
deepwater production systems. It is known that retrieval of the
produced fluids as separate liquid and gas phases at the
destination facility can remove these risks and permit a less
complex processing system.
[0012] To date, subsea systems aimed at separating the liquid and
gas phases downstream of the wellhead have generally included
components external to the riser and flowline, requiring the
mobilisation of surface vessels to effect their
installation/maintenance. Mobilisation of these specialised vessels
is expensive, particularly in remote areas where there is minimal
local infrastructure. In addition, there is a need to construct and
install external mechanical interfaces for this equipment.
[0013] U.S. Pat. No. 5,285,204 describes a borehole system for
operating a downhole generator on a composite coiled tubing string,
which is dispensed from a powered spool on the earth's surface.
[0014] It is also known from U.S. Pat. No. 4,336,415 to employ
composite flexible coiled tubing to convey electrical and/or
hydraulic power to a drive motor for a downhole pump.
[0015] U.S. Pat. No. 5,503,014 describes a system using coaxial
coiled tubing to supply fluids to a wellbore for performing a drill
stem test.
[0016] U.S. Pat. No. 5,638,904 describes a type of nested coiled
tubing in which the individual pipes adopt a helical
configuration.
[0017] In this specification, the expression "coiled tubing" means
tubing which is supplied in coiled form on a drum and dispensed
from the drum to pass down a riser.
[0018] According to a first aspect of the invention, there is
provided a system for raising production fluid from a source on the
seabed, comprising:--a riser having an internal passageway for
conveying said production fluid and having a first, lower, end for
connection to or connected to the source; a top end support for
supporting the riser at its second end at or in the vicinity of the
sea surface; and an operating device mounted inside the riser for
displacement within the riser between a first, operating, position
in the riser remote from its second end, and a second, access,
position, at the second end of the riser, so that the device is
accessible for replacement or repair.
[0019] The operating device may be a pump, a heater, a gas
injector, or a cutting or cleaning tool. These aspects will be
discussed in more detail hereinafter.
[0020] It will be appreciated that the riser serves as a transport
path for displacement of the operating device initially from the
top end support, which is readily accessible to operating crew
since it will generally be located in the vicinity of the sea
surface (e.g. on board a support vessel or just below the sea
surface) or at the sea surface, to the down-riser operating
position. This makes the initial installation of the device simple
to implement. Similarly, repair or replacement of the device can
easily be effected by essentially a reversal of this operation.
This avoids having to repair or replace the device in situ,
adjacent the sea bed, using a support vessel and highly trained
personnel, following a malfunction, and the consequent downtime and
loss of revenue through lost production. In addition, the time
involved both in the initial installation of the device and also in
raising the device within the riser so that the necessary work can
be carried out and then lowering the repaired or new device to its
former position can be relatively small.
[0021] As already explained, the top end support for the riser may
be in the form of a floating support vessel. In another preferred
form, it comprises a buoyancy unit tethered to the sea floor and
located below the sea surface, to minimise the effect of the
surface waves. An ideal depth for the buoyancy unit is
substantially 60 metres below the surface, so that the wave action
has negligible effect but the buoyancy unit can nevertheless be
readily accessed by crew members, for example on an attendant
vessel, using conventional handling techniques. The 60 metre depth
however is purely an example, and it will be appreciated that the
buoyancy unit may be tethered at greater or lesser depths.
[0022] Generally, the source of production fluid will be a subsea
wellhead, a seabed flowline from a remote subsea wellhead or groups
of wellheads, or a seabed flowline from a remote storage
facility.
[0023] The fluid raising system may further comprise means
including a pipe, e.g. coiled tubing, which extends within the
riser and to a lower end of which the operating device is attached.
The pipe may then serve the dual functions of being itself drivable
down and up to lower and raise the device for the required initial
installation and subsequent repair or maintenance, and serving as a
carrier for the device when it is in its operating position.
[0024] As already mentioned, the operating device may be a pump for
pumping production fluid from the source.
[0025] In one arrangement, the pump is an electric pump and an
electric power supply cable for the pump passes through the pipe.
Therefore, the space necessarily provided within the pipe is used
to accommodate the power supply cable. This contributes to a
compact construction for the riser.
[0026] In another arrangement, the pump is a hydraulic pump,
typically a turbine-driven pump, and the pump displacing means
includes a supply pipe which extend within the riser and to the
lower end of which the hydraulic pump is attached, the supply pipe
being arranged for delivering hydraulic fluid down to the pump,
which then discharges it into the production fluid passing up the
riser.
[0027] In some cases however, especially where only limited mixing
of the hydraulic fluid (e.g. pump lubricant) with the production
fluid is permissible, a closed hydraulic pressure circuit is
needed. Preferably, therefore, the pump is a hydraulic pump
attached to lower ends of supply and return pipes extending within
the riser, the supply pipe being arranged for delivering hydraulic
fluid down to the pump to drive it and the return pipe being
arranged for conveying hydraulic fluid from the pump back up the
riser.
[0028] Although separate supply and return pipes can be provided in
the riser running side-by-side, it is preferred, for compactness,
that the two pipes form a nested, pipe arrangement, e.g. a
collinear arrangement or an arrangement where one or both pipes
adopt a helical configuration. Furthermore, a nested pipe
arrangement lends itself to being driven into, and withdrawn from,
the riser by a single conventional pipe dispensing and retrieving
apparatus. Thus, the pump displacing means may include a pipe
dispensing and retrieving apparatus on the top end support or an
attendant service vessel, such apparatus comprising a rotatable
pipe storage device on which the nested pipes are wound, a pipe
straightener and drive means for the storage device, selectively
operable for straightening a length of the nested pipes and driving
them downwardly into the riser to lower the hydraulic pump to said
first position and to wind in the nested pipes to raise the pump to
said second position.
[0029] It is particularly preferred that means are provided for
delivering heated hydraulic fluid through the supply pipe for
heating production fluid in the riser by heat transfer through the
walls of the supply and return pipes. Here either the inner or the
outer pipe of a nested pair may form the supply pipe. In this way,
the possibility of freeze-ups in adverse operating temperature
conditions, or following temporary shutdown, can be avoided.
Furthermore, the hydraulic fluid may then be used not only for
driving the down-riser pump, but also for conveying heat to the
production fluid, thereby avoiding the need for separate means for
providing these two functions. In the prior art, it is known in the
industry to specify long cool down time to minimise the risk of
freeze-ups, but this necessitates designing a number of components
to have high thermal capacity and/or adding inhibitors to prevent
hydrate formation, and, in any event, there can be no guarantee of
avoiding freeze-ups in this way. Therefore, the measures described
represent an advantage over the prior art.
[0030] A heater is preferably mounted in the riser between the
first end thereof and the pump, the heater being connected to
receive heated hydraulic fluid from the supply pipe and to return
the fluid to the return pipe. In this way, heat is supplied to the
regions in the riser where a freeze-up is most likely to occur. The
heater can be a separate component, or it may be provided by
intercommunicating bottom end sections of the supply and return
pipes.
[0031] Depending on operating conditions and the nature of the
production fluid to be raised from the sea bed, waxy deposits may
form in the riser and need to be removed periodically. Therefore, a
pig introducing device may be provided for introducing a pig into
the riser at a position below the pump when in said second
position. Displacing the pump along the riser from one axial
position to another one is also available to provide
scraping/cleaning of the riser wall.
[0032] In the embodiments described above having a hydraulic pump
in the riser, the supply and return pipes serve to deliver
hydraulic pressure fluid for driving the pump. However, instead,
these pipes may serve solely or principally for supplying heat, to
avoid a freeze-up in the riser. If a pump, electric or hydraulic,
is needed to raise the production fluid in the riser, it may be
positioned externally of the riser and connected in a flowline
delivering production fluid to the bottom end of the riser. The
pump would then be powered independently of the supply and return
pipes.
[0033] According to another embodiment of the invention, the
operating device may be a heater mounted inside the riser for
displacement within the riser between a first, operating, position
in the riser remote from its second end, for heating production
fluid in the riser, and a second, access position, at the second
end of the riser, so that the heater is accessible to an operator
for replacement or repair.
[0034] Again, the two pipes could be placed side-by-side in the
riser, but suitably they can form a nested, preferably collinear or
helical, pipe arrangement. The heater displacing means may include
a pipe dispensing and retrieving apparatus on the top end support
or an attendant service vessel, such apparatus further comprising a
rotatable pipe storage device on which the nested pipes are wound,
a pipe straightener and drive means for the storage device,
selectively operable for straightening a length of the nested pipes
and driving them downwardly into the riser to lower said heater to
said first position and to wind in the nested pipes to raise the
heater to said second position.
[0035] In accordance with another embodiment of the invention, the
operating device is a gas injector and rigid pipe may comprise a
supply pipe for delivering gas under pressure to the gas injector,
for providing lift to the production fluid in the riser.
[0036] The system may further comprise means for displacing the gas
injector in the riser between the operating and access
positions.
[0037] The gas injector displacing means may include a rigid supply
pipe extending downwardly within the riser and carrying said gas
injector.
[0038] The rigid supply pipe may itself carry the pressure gas or
it may carry a separate gas delivery pipe.
[0039] It will be appreciated that it is possible to provide a
system complying with two or three of the above-defined embodiments
at the same time. For example, the rigid supply pipe may be used to
supply heating fluid to a heater, but also include a separate gas
supply line used for injecting lift gas into the riser for use with
a gas injector.
[0040] In another embodiment, a locating device is mounted on the
operating device, and is selectively operable for (i) engaging with
the inner surface of the riser and (ii) disengaging therefrom so
that the operating device can be repositioned in the riser. This
permits the down-riser operating device to be moved between one
desired position in the riser and another one in the riser or its
flowline component merely by disengaging the locating device,
displacing the down-riser operating device to the desired new
position, and re-engaging the locating device. If desired, the
down-riser operating device can be withdrawn through the riser back
to the surface for maintenance or repair. Since the locating device
is withdrawn from within the riser, there is no need for an
attendant vessel or specialised equipment, which would be required
in the conventional arrangement where a sub-sea operating device
such as a pump is located externally of the riser.
[0041] In another embodiment, the operating device is a pump and
the locating device is a sealing device which is operable for both
engaging and sealing with the inner surface of the riser so that
the pump can pump production fluid in the riser from a low pressure
side of the sealing device to a high pressure side.
[0042] Since the sealing device then not only serves for engaging
with the riser inner wall but also for sealing with it, the need to
compartmentalise the riser interior into low pressure and high
pressure sides (so that the pump can pump from low pressure to high
pressure) can be achieved without needing a sealing element
separate from the riser wall engaging function.
[0043] In a further embodiment, the sealing device comprises a
packer mounted on the pump and an inflatable sealing element
operable for forming sealing contact with the inner surface of the
riser. This is a structurally simple and effective arrangement for
achieving the necessary engagement and sealing with the riser
wall.
[0044] It will be appreciated that a hydraulic pump can more
readily cope with sharp bends inside the riser without jamming than
an electric pump.
[0045] According to another embodiment, in addition to said
passageway for carrying the production fluid, a second passageway
is provided in the riser for connection to a low pressure region in
the vicinity of the upper end of the riser and means are provided
for expelling production fluid from the first passageway to said
low pressure region, so as to reduce the pressure in the first
passageway to a lower value than that existing under interrupted or
shutdown conditions, thereby inhibiting formation of solid hydrates
in the first passageway.
[0046] The production fluid expelling means may comprise a one-way
valve providing fluid communication from the first passageway to
the second passageway, a source of pressure gas operable for
introducing gas under pressure to the first passageway to expel
production fluid therefrom through the one-way valve, and means for
venting the gas pressure in the first passageway to said region of
lower pressure. This is one convenient way of achieving the
required pressurised gas introduction and subsequent pressure
reduction.
[0047] Expediently, the production fluid expelling means comprises
a pump in the riser arranged for pumping production fluid from the
first passageway to the second passageway. The pump may be used to
avoid hydrate formation instead of gas pressure control. According
to a further development, a cyclone separator mounted on the pipe
for positioning within the riser and having inlet means for
imparting swirl to production fluid entering the separator from the
riser to effect separation of the fluid into a liquid-rich
underflow and a gas-rich overflow, the pump being arranged to
receive the separator underflow and pump it up to the top of the
riser through said pipe. This avoids formation of (air and
production fluid) slugs.
[0048] Where the pump is held at a low point of the riser, it can
be arranged that hydrostatic pressure at the pump inlet ensures
that the bulk of, or all of, the gas included in the hydrocarbon
fluid rich underflow is held in solution by the time that the
hydrocarbon fluid enters the pump.
[0049] In a modification, said hydraulic pump comprises a pump
section, turbine section and an articulated or flexible coupling
section to the packer or drive mandrel.
[0050] The articulated or flexible couplings between the turbine or
pump section and the packer or drain mandrel enables the hydraulic
pump to pass around tight bends within the riser.
[0051] Preferably, the coupling section comprises a universal drive
coupling or an articulation incorporating a flexible coupling, in
each case with a torque reaction device between the casings of the
pump and turbine sections.
[0052] A universal drive coupling is a convenient form of element
for maintaining drive as the pump and turbine sections articulate
relative to one another.
[0053] Expediently, a heater is provided in the region of the
hydraulic pump, the heater being arranged to be supplied by heating
medium conveyed through said pipe. The heater avoids the formation
of freeze-ups.
[0054] Due to the provision of the coupling section the hydraulic
pump can be passed through a riser having relatively sharp bends,
such as the mentioned lazy-S, steepwave and steep-S
configuration.
[0055] In some embodiments, the riser has a substantially vertical
compliant section, leading from the sea bed to the surface a
substantially horizontal section on the sea bed, and a bend section
connecting the substantially vertical and horizontal riser
sections. This is a further typical pipeline configuration for
which the provision of the hydraulic pump including articulated
linking between the turbine and pump sections enables the pump to
be advanced around the approximately 90.degree. bend section where
the radius of curvature is small, connecting the vertical riser
section and horizontal flowline section of the riser.
[0056] In a further embodiment, a traction device on the pipe is
operable for applying traction to the pipe to drive the operating
device down inside the riser. The traction device enables the
down-riser operating device to travel through a riser extending a
long way, typically across the sea bed, from the surface access
location to the top of the riser.
[0057] In a preferred embodiment, the traction device is
selectively operable from the remote end of the pipe for applying
traction to the pipe in either direction for lowering or raising
the operating device. This enables the traction device to apply
traction in either axial direction of the riser.
[0058] In another embodiment, where a down-riser pump is provided,
a sealing device is mounted on the pump and arranged to provide a
sliding seal with the inner surface of the riser, the pump being
arranged to pump between a low pressure and a high pressure side of
the sealing device so as to generate a traction force for driving
the down-riser pump longitudinally within the riser, the pump and
sealing device together constituting said traction device.
[0059] The down-riser pump together with its sealing device serves
not only to provide down-riser pumping but also to generate the
required traction force for driving the pump through the riser or
flowline.
[0060] According to another embodiment, said operating device
comprises a motor mounted on a lower end of the pipe and arranged
to be powered by an electrical cable passing through said pipe, and
a rotary cleaning device arranged to be driven by the motor. The
rotary cleaning device is able to achieve cleaning (active or
passive) of deposits on the inside surface of the riser wall.
Furthermore, the motor is powered from the upper end of the riser
via the pipe on which the motor is mounted, which is a convenient
manner of powering the motor with ready access to the powering
means at the riser upper end.
[0061] Preferably, a sealing device on the motor is arranged to
form a sliding seal with the inner surface of the riser. Where a
pump is provided, it may be arranged to provide differential
pressure between a low pressure side and a high pressure side of
the sealing device.
[0062] The differential pressure acts on the motor to create a
force acting on it to drive it along the riser.
[0063] Alternatively, the rotary cleaning device is arranged to
generate a differential pressure between one side and the other
side thereof when it is rotating. The differential pressure
generated by the rotary cleaning device serves to advance it within
the riser or, where a pump is additionally provided, the force
generated by the rotary cleaning device supplements the driving
force acting on the pump itself.
[0064] A rotary cutter is able to provide active removal of hard
scale build-up on the inside of the flow line/riser wall, a rotary
brush provides less aggressive cleaning, whilst a combined rotary
cutter/brush provides aggressive cutting for removing hard scale
and more gentle cleaning for removing more readily removable
deposits.
[0065] Corresponding to the system according to the first aspect of
the invention are methods of installing a riser operating
device.
[0066] In accordance then with a further aspect of the invention,
there is provided a method of installing an operating device in a
riser connecting a source of production fluid on the seabed to a
top end support supporting the riser at or in the vicinity of the
sea surface, comprising:--
[0067] introducing the device into the riser at the upper end
thereof; and
[0068] driving the device downwardly into the riser to a desired
operating position in the riser remote from its end at the top end
support.
[0069] Preferably, the device is attached to the lower end of a
rigid pipe and the pipe is driven downwardly into the riser to
displace the device to its desired operating position.
[0070] According to a method of maintaining or replacing an
operating device installed in accordance with the present method,
the following steps are carried out:--
[0071] driving the pipe upwardly to raise the device within the
riser to the top end support;
[0072] removing the device from the riser; and
[0073] disconnecting the device from the pipe, for maintenance or
replacement.
[0074] For adjusting the position of the pump, heater or gas
injector (as the case may be) in the riser, it is preferred to
carry out the following steps:--the pump, heater or gas injector is
retrieved from the riser through its upper end and disconnected
from the pipe, an end section of the pipe is removed or a new
section attached to its end to define a new length of pipe, and the
pump, heater or gas injector attached to the end of the new length
of pipe and driven down the riser to its new operative
position.
[0075] In a further development, the method comprises at least
partially expelling the production fluid from the riser interior,
so as to reduce the pressure acting there, in order to inhibit
formation of solid hydrates in the production fluid flowing from
the source under interrupted flow or shut down conditions.
[0076] Since the pressure acting in the riser and flowline interior
can be reduced, particularly under no flow condition, the formation
of solid hydrates in the riser can be inhibited at any given
temperature. Of course, the pressure reduction must be sufficient
to be below the hydrate formation pressure at the local
temperature.
[0077] A pump is a simple and effective device for achieving the
required expulsion of production fluid from the riser.
[0078] According to an alternative method, gas is introduced under
pressure into the riser to at least partially expel the production
fluid and the gas pressure acting in the riser is reduced to a
value lower than its initial value while preventing the expelled
production fluid from returning to the space occupied by the gas.
This represents a simple and effective way of reducing the pressure
in the riser. In fact, this arrangement also offers the advantage
that the equipment needed for supplying the gas under pressure and
then reducing its pressure does not need to be located at
down-riser but, conveniently, can be located at the surface or top
end of the riser.
[0079] A hydrate formation inhibitor may be introduced along with
the gas. The inhibitor serves to augment the inhibition of solid
hydrate formation.
[0080] It should be noted that where the term "rigid" is used in
this specification to describe the nature of the pipe (or pipes)
deployed within the riser, such pipe is able to follow the
anticipated deviations from linear of the riser, by elastic
deformation of the material, (typically steel or suitable composite
plastics material) used to form the rigid pipe, such as occurs even
in the case of the embodiments to be described below, in which the
riser is also made of rigid material which is compliant to vertical
and horizontal displacements of an attendant vessel supporting the
upper end of the riser. It is alternatively possible for the riser
to be made of flexible material rather than rigid material (while
the pipe remains of rigid material), but then suitable positioning
means has to be provided to position the top end support suitably
relative to the lower end such that the rigid pipe is not deformed
beyond its elastic limit. The rigid pipe needs to be sufficiently
rigid to support the pump, heater or gas injector adequately when
held in the desired position in the riser. Alternatively, the
internal pipe may also be of flexible material.
[0081] The top end support for the riser may be simply an
attendant, floating, support vessel. It will be appreciated that
the system may include a submerged buoyancy unit as the top end
support, whether a down-riser pump, heater or gas injector is used.
In addition, a surface breaking extension (i.e. through the
air/water interface) may be provided for access to the riser top
end. This has the advantage that at the time of installation, the
pump, heater or gas injector can readily be inserted into the upper
end of the riser, since even when the top end support is a
submerged buoyancy unit, the upper end of the riser is still
readily accessible to crew members attendant an site.
[0082] Although the pump, heater or gas injector will normally be
positioned in the riser in the vicinity of its bottom end, it is
not necessary for it to be positioned there. For example it could
be located at a mid-position or elsewhere within the riser or
flowline, when desired.
[0083] For a better understanding of the invention and to show how
the same may be carried into effect, reference will now be made, by
way of example, to the accompanying drawings, in which:--
[0084] FIG. 1 is a general schematic view of a first system for
raising hydrocarbon fluid from a subsea source, forming a first
embodiment of the invention;
[0085] FIG. 2 is a more detailed side view of the riser of the
system;
[0086] FIGS. 2a and 2b show respective modifications;
[0087] FIG. 3 is a schematic view of a second embodiment;
[0088] FIG. 4 is a side view showing in more detail the
construction of the riser at a time when a hydraulic pump is being
installed down-riser;
[0089] FIG. 4a is a side view of the buoyancy unit and maintenance
stack of the system shown in FIG. 4;
[0090] FIG. 4b shows a piggable wye junction which can be used for
pigging the system or for providing a radius suitable for pump
insertion;
[0091] FIG. 5 is a schematic view of a third embodiment, differing
in certain respects from that according to FIGS. 1 and 2;
[0092] FIG. 6 shows the arrangement in more detail;
[0093] FIG. 7 is a schematic side elevation of a fourth embodiment
resembling that shown in FIG. 4 but differing in certain
details;
[0094] FIGS. 8 to 10 show a schematic side elevation of a fifth
embodiment of the invention showing evacuation of the riser by gas
displacement or gas/methanol displacement;
[0095] FIG. 11 a shows a schematic side elevation of a sixth
embodiment of the invention for use in slug suppression or
separation;
[0096] FIGS. 11b and 11c are cross-sectional views along the planes
11b-11b and 11c-11c of FIG. 11a;
[0097] FIG. 12 shows a schematic side elevation of a further
embodiment of the invention for use in pressure boosting or
provision of artificial lift in an S-configuration riser;
[0098] FIG. 12a is a partial schematic sectional view through the
wall of a riser having a coiled spiral inner construction;
[0099] FIGS. 12b, 12c and 12d show schematic side elevational views
of various riser configurations;
[0100] FIG. 13 is a schematic side elevational view of a system
according to the invention for providing pressure boosting or
artificial lift from one or more subsea well in a rigid or
compliant riser;
[0101] FIG. 14a shows a schematic side elevational view of a system
according to the invention employing a first method for
transporting an operating device to or from a location remote from
the riser top, using a coiled tubing delivery system;
[0102] FIG. 14b is a schematic side elevational view of a part of
the system of FIG. 14a at an enlarged scale;
[0103] FIG. 14c is a schematic side elevational view of a part of
the system of FIG. 14a showing a modification using a derrick
system for tubing deployment;
[0104] FIG. 15a shows a schematic side elevational view of a system
according to the invention employing an alternative method for
transporting an operating device to or from a location remote from
the riser top using a coiled tubing delivery system;
[0105] FIG. 15b is a schematic side elevational view of a part of
the system of FIG. 15a at an enlarged scale;
[0106] FIG. 15c is a schematic side elevational view of a part of
the system of FIG. 15a showing a modification using a derrick
system for tubing deployment;
[0107] FIG. 16a shows a closed loop production mode cleaning
apparatus for cleaning the inside of a riser;
[0108] FIG. 16b shows an open loop production mode cleaning
apparatus for cleaning the inside of a riser;
[0109] FIG. 16c shows the use of shutdown mode annular fluid flow
for driving a cutter for cleaning the inside of a riser; and
[0110] FIG. 16d shows the use of shutdown mode coaxial fluid flow
for driving a cutter for cleaning the inside of a riser.
[0111] The invention defined hereinafter in various aspects
thereof, as well as the following embodiments, concerns a
vertically accessed riser with retrievable internal services
(referred to herein as VARRIS for short) and was conceived to
provide energy addition (thermal or pressure) to fluids transported
from the seabed to a production facility at, or a relatively short
distance below, the sea surface, by inserting services into the
riser/flowline at the topside interface rather than by external
installation using a deepwater intervention vessel. VARRIS is based
on the core concept of placing services into a riser and its
flowline, the riser/flowline being either an existing installation
or a new build. Further capabilities have been identified which use
similar deployment philosophy but with different equipment to
achieve new features and extend functional capability.
[0112] While VARRIS was developed for deepwater installations it is
equally valid for shallow applications.
[0113] Further applications of the invention to be described below
include installing a down-riser slug suppressor, separator,
equipment tug or tractor, and scale/wax removal equipment.
[0114] Further applications of VARRIS cover the following
areas:
[0115] 1. Using VARRIS as a slug suppressor/separator (FIG.
11);
[0116] 2. Using VARRIS to evacuate the riser/flowline (FIGS. 9 to
10);
[0117] 3. Using VARRIS in existing risers (shallow or deepwater,
rigid or flexible) for pressure boosting/provision of artificial
lift (FIGS. 12a to 12d and 13);
[0118] 4. Assistance in deployment/retrieval of the internal
services towards/from the subsea production facility (manifolded
production system or an individual well) along the seabed flowline
section using a mechanical self-driven tractor (FIGS. 14a, 14b and
14c), or using self drive by generation of an axial differential
pressure and driving force across the end remote from the riser
entry point at the top (FIGS. 15a, 156 and 15c); and
[0119] 5. As for 3 but using a pig to assist in
deployment/retrieval of the internal services (FIGS. 16a to
16d).
[0120] Referring to FIGS. 1 and 2, there is shown a first
embodiment of the invention in the form of a system for raising,
from the seabed or mudline 2, hydrocarbon production fluid in a
flowline 1 from one or more subsea wells (not shown), the flowline
running along the seabed or mudline 2. The flowline, may be
connected directly to the lower end of a riser 4, which extends up
from the mudline to the sea surface 5, where the flowline is
supported by a floating support vessel 6. If necessary or desired,
as shown in FIG. 1, the flowline may optionally be provided with a
homogeniser 3 for homogenising the three-phase production fluid
generally consisting essentially of crude oil, natural gas and
water, and suitable valving, such as on-off valves 40, 41 and 42.
When valves 41 and 42 are closed and valve 40 opened, the
production fluid passes directly to the riser 4. However, on
opening valves 41 and 42 and closing valve 40, the production fluid
is routed via the homogeniser 3.
[0121] The riser 4 extends initially in a horizontal direction,
forming an extension of flowline 1, and then curves upwardly,
eventually becoming vertical. Although the curvature of the riser
is depicted as relatively sharp, in fact this is due to the scale
of the Figure and the actual curvature would be much more gentle
since the system is installed at a large depth (which might
typically be 100 to 500 metres or more) and the curvature of the
riser is accommodated by elastic deformation of the material of
which it is made. However, the riser 4 could be of flexible
material with bend radius <100 m, for example.
[0122] The support vessel 6 is provided with a pipe delivery and
retrieving apparatus, including a powered drum 7 on which a length
of coaxial pipe 19 is wound. The pipe delivery and retrieving
apparatus will generally include a pipe straightener for removing
the residual "curl" of the pipe resulting from its being wound onto
the powered drum 7, and also a tensioner for assisting in drawing
the pipe from the drum and forcing it through the straightener. One
suitable form of pipe delivery and retrieving apparatus is
disclosed in U.S. Pat. No. 3,982,402.
[0123] An optional standard pipe lubricator or injector 8 is
mounted on the vessel 6 and connected to the upper end of the riser
4, a length of pipe 19 paid out from the powered drum 7 passing
downwardly through the lubricator or injector 8 and into the upper
end of the riser 4, and extending to a position within the riser
remote from its upper end, for a reason to be explained below. The
lubricator or injector 8 provides a fluid-tight seal with the outer
surface of the pipe 19. A crane 9 on the vessel serves for lifting
and supporting pipe 19 dispensed from the powered drum 7. Since the
riser has an undulating configuration between the seabed 2 and
support vessel 6 as shown, it can be referred to as a compliant
vertical access riser. The riser may also be of a simple catenary
or S configuration. The purpose of the riser configuration is to
accommodate vertical and horizontal vessel motion relative to the
seabed 2 (such as due to wave action and sea currents), without
placing any undue strain on the riser 4. As shown, there may be one
or more additional riser 4 with corresponding equipment at the
lower end thereof.
[0124] FIG. 1 also shows a pump 14 and an optional heater 15, whose
purposes are described below.
[0125] FIG. 2 shows in some detail the structure at the lower end
of the riser 4. The riser itself is of tubular construction.
Mounted within the riser 4, for example centrally, by means of a
packer 10, which is operable for forming a seal with the riser
wall, is a hydraulic submersible pump or HSP 11, having an inlet
11.sub.1 for receiving production fluid in the flowline to be
pumped, and a pumped production fluid outlet 11.sub.2 in the form
of a plurality of exit openings arranged circumferentially around
the HSP 11, discharging into the riser 4 at the opposite side of
the packer 10 to the fluid entry point. The pump also has a
hydraulic fluid inlet 11.sub.3 and a hydraulic fluid outlet
11.sub.4 or 11'.sub.4. The packer 10 is sealed to the riser wall,
by means of an inflatable seal 10a of the packer 10, shown
diagrammatically in FIG. 2. In this case, hydraulic fluid is
supplied to the seal 10a along an umbilical or inflation line 100,
to inflate the seal and cause it to sealingly engage the inside of
the riser wall. Alternatively, suitable-ducting with control valves
or a retrievable internal diverter in the supply pipe 12 may be
provided between the HSP 11 and the inflatable seal 10a, so that
hydraulic fluid from the pump may be used to inflate the seal. In
both cases, the seal 10a may be deflated, to break the seal with
the riser wall, by releasing the hydraulic pressure acting on the
inflatable seal 10a.
[0126] In another form, the seal may be mechanically operated or
electro-mechanically operated. Various forms of seal which would be
suitable for the intended purpose are known to those skilled in the
art. By way of example, one such seal would be in the form of a
sealing member operative (for example by a biasing or latching
action) to sealingly engage in a groove formed in the riser inner
wall surface. In this example, a groove would need to be provided
at each location in which the seal is to be made operative.
[0127] The length of rigid pipe 19 extending downwardly through the
lubricator 8 (FIG. 1) and along the length of the riser is
preferably a nested arrangement of hydraulic supply and return
pipes 12, 13. The pipe 19 may preferably have a construction such
as shown in U.S. Pat. No. 5,638,904 in which the supply and return
pipes 12, 13 are formed into a helical configuration which may lock
it firmly within the riser 4. The supply pipe 12 is normally the
central pipe and is connected to supply hydraulic fluid to pump
inlet 11.sub.3, thereby driving the pump 11 to increase the
pressure of the production fluid entering the pump through inlet
11.sub.1 and drive it from pumped fluid outlet 11.sub.2 up through
the riser 4 to the support vessel 6. The hydraulic fluid outlet
11.sub.4 can be connected directly to the return hydraulic pipe 13,
but may alternatively be connected indirectly through a further
short length of coaxial pipe 29 comprising central supply pipe 12a
and surrounding return pipe 13a interconnecting at their remote
ends. This coaxial stub pipe 29 constitutes a heater or "stinger"
which permits the production fluid to be heated in a region of the
riser 4 beyond the pump 11 by supplying hydraulic fluid heated on
the vessel 6 by heater 15. The return pipe 13a either passes via
the pump internally, or passes externally of the pump but within
the riser, and is connected to return pipe 13. In a modified
arrangement, part of the pump outlet hydraulic pressure is
connected directly to the return hydraulic pipe 13, the remainder
being bled off to feed central supply pipe 12a. In this way, a
total or partial hydraulic circulation circuit is provided from the
support vessel 6 through supply pipe 12, HSP 11, supply pipe 12a,
and back through return pipes 13, 13a to the vessel 6. The
hydraulic pressure circuit can be a closed circuit or it may be an
open circuit with the recirculated fluid stored in a tank or
separated and discharged overboard, which would be appropriate if
the hydraulic medium is water, for example. In another
configuration, the hydraulic supply from pipe 12 is partially
discharged into the outlet 112 of the pump 11.
[0128] Hydraulic pressure fluid is circulated around this circuit
by pump 14 in order to drive HSP 11, which in turn pumps production
fluid up the riser 4 to the support vessel 6, where the production
fluid can be treated (such as in a separator to separate the
components, principally crude oil, water and gas), stored, pumped
to an attendant tanker or pumped ashore via a suitable pipeline.
The heater 15 is preferably provided, so that the circulating
hydraulic fluid can be heated, to raise the temperature of the
hydrocarbon fluid in the riser through heat conduction through the
walls of the supply and return pipes 12, 13 and convection into the
hydrocarbon fluid. The optional "stinger" or heater 29 serves to
heat up the production fluid entering the riser 4 from the flowline
1 or to unfreeze solids formed in the riser 4 following extended
shut-downs. The heating provided by the circulating hydraulic fluid
avoids the risk of freeze-ups when operating in particularly cold
environments or when the system is to be taken out of operation
temporarily.
[0129] The coaxial pipes 12, 13 serve not only to circulate
hydraulic pressure fluid through HSP 11 to drive it, but also to
physically carry the HSP at their end remote from the vessel 6.
Furthermore, the packer 10 on which the HSP is mounted can be
operated to break its seal with the riser wall, under which
condition the packer 10 can slide within the riser over its whole
length. Therefore, by winding in the coaxial arrangement 19 onto
the powered drum 7, the HSP can be raised to the upper end of the
riser for maintenance or repair. This operation is described in
detail below.
[0130] The installation of the flowline 1, deployment of the riser
4 from the support vessel and connection of the riser 4 to the
flowline 1 can be carried out in accordance with well-known
techniques, which will therefore not be described herein. At this
stage, the length of coaxial pipe 19 is stored on powered drum 7
and the lubricator/injector 8 is disconnected from the upper end of
the riser 4. To install the HSP 11 in the riser 4 adjacent its
lower end, an initial length of the coaxial pipe 19 is passed
through the lubricator/injector 8, or riser top end hang-off, by
the pipe laying and retrieving apparatus and the HSP 11 is attached
to the free end of the coaxial pipe, after which the HSP 11 is
inserted into the open upper end of the riser 4 with packer 10 set
in its non-sealing condition and the lubricator/injector 8
connected to the upper end of the riser 4. Then, the pipe laying
and retrieving apparatus discharges the remainder of the coaxial
pipe 19 stored on powered drum 7, to displace the HSP 11 down the
riser 4 until it reaches its desired final position remote from the
upper end of the riser 4. The seal 10a of the packer 10 is then
engaged with the riser wall and the upper end of the coaxial pipe
is disconnected from the pipe laying and retrieving apparatus, and
then connected to the pump 14 and heater 15, ready for operation.
It will be appreciated that the length of coaxial pipe 19 needed
has to be determined beforehand and the appropriate length stored
on the powered drum 7 beforehand, so that when the HSP 11 reaches
its required final position in the riser, the appropriate length of
pipe 19 has been dispensed. Additional pipe sections can be stored
on the drum as required to be used as extensions. The coiled pipe
19 may alternatively be driven into the riser by the injector 8
such that it adopts a helical form within the riser 4, thereby
locking it in position within the riser 4.
[0131] If the HSP 11 needs servicing or malfunctions, it can be
retrieved to the vessel 6 by essentially a reversal of the
above-described operations. Accordingly, the upper end of the
coaxial pipe 19 is disconnected from the hydraulic pressure circuit
and reconnected to the pipe delivering and retrieving apparatus,
for example with assistance from the crane 9. The coaxial pipe in
turn re-wound onto the powered drum 7 to raise the HSP to the upper
end of the riser 4, the lubricator/injector 8 disconnected from the
riser, the HSP 11 removed from the riser and disconnected from the
coaxial pipe 19, and the coaxial pipe 19 withdrawn from the
lubricator 8 and wound fully onto the drum 7. The HSP 11 can then
be repaired or replaced, before being deployed in the riser 4 in
the manner described for the initial installation.
[0132] FIG. 2a shows a modification in which a single, delivery
pipe 12 is provided inside the riser 4, but no return pipe 13.
Instead, the hydraulic fluid discharged from the outlet 11.sub.2 of
HSP 11 is released directly into the flow of production fluid
pumped up the riser 4. In this embodiment, the hydraulic fluid must
be one which it is acceptable to mix with the production fluid. One
such example is water, since the production fluid usually has a
water content, for which a separator will normally need to be
provided on the support vessel 6.
[0133] In another modification shown in FIG. 2b, the down-riser
pump 11 is an electric pump carried on the end of a single pipe 12,
through which a power supply cable 16 passes, connected between a
power source on the vessel 6 and the electric pump 11. Although the
electric pump 11 is shown to be similar in size to the hydraulic
pump 11 of FIG. 2a, it will be appreciated that in a practical
embodiment it will be much longer. If it is desired to provide
heating for the production fluid, an electric heater 18 may be
provided, such as at a position between the lower inlet end of the
riser 4 and the electric pump 11. A further power cable 16a,
connected to main power supply cable 16 and passing through a short
section of rigid pipe 12a on an end of which heater 18 is mounted,
supplies electric power to the heater 18.
[0134] Referring to FIG. 3, there is shown a schematic diagram of
another embodiment. Where the same reference numerals are used as
in the previous Figures, they denote the same or equivalent
elements and the description of them is not repeated here. This
embodiment differs from the preceding ones principally in that the
top of the riser 4 is connected to a buoyancy unit 20 tethered to
the sea floor and positioned just below sea level 5. Since there is
no need to accommodate any vertical motion of the buoyancy unit,
the riser 4 takes the form of a rigid tubular element and it
extends vertically upwardly from a riser base 21 secured to the
seabed 2. The riser base 21 is connected to receive production
fluids from a well via flowline 1. The buoyancy unit 20 is provided
with a flexible take-off hose 22 suspended in the sea between the
buoyancy unit and an attendant service vessel 6, for conveying
hydrocarbon fluid from the top of the riser 4 to the vessel 6 for
processing or onward transportation.
[0135] As shown in FIG. 4, when provided, the homogeniser 3 is
located in the riser base 21. The production fluids in flowline 1
leave the homogeniser 3 (when provided) and enter the riser 4 at
its bottom end. Situated a short distance above the riser bottom
end inside the riser is the HSP 11 carried on the bottom end of
coaxial pipes 12, 13. The internal arrangement of the HSP, its
packer 10 and heating "stinger" 29 is identical to that shown in
FIG. 2.
[0136] The manner in which the riser base 21, riser buoyancy unit
20 and flexible hose 22 are installed is conventional in itself and
therefore will not be described herein. However, in order to
install the HSP on the lower end of coaxial pipe 19 in the riser,
the buoyancy unit 20 is provided with a detachable maintenance
stack 24 connected to a wye ("Y") junction 25 which is mounted on
the buoyancy unit 20. This wye junction 25 is either of piggable or
non-piggable configuration. The wye junction 25 serves for routing
the production fluid from the riser 4 to the flexible hose 22. The
maintenance stack 24 includes a lubricator 8 extending over most of
the height of the stack, and vertically spaced blowout preventer
valves 26 and 27 with isolation facilities. To install the HSP 11,
the support vessel 6 or another service vessel is positioned over
the buoyancy unit 20. At this time, the maintenance stack 24 is
on-board the vessel 6. The free end of the coaxial pipe 19 wound on
the powered drum 7 on the vessel 6 is passed into the stack 24 from
above, through the lubricator 8, blowout preventer valves 26, 27
and emerges through the bottom end of the stack 24. The HSP 11,
together with its packer 10 (with its seal inoperative), is then
attached to the projecting end of the pipe 19 and withdrawn fully
upwardly inside the stack, after which the maintenance stack 24 is
lowered from the vessel 6 into the sea, and connected to the wye
junction 25 by remote control. The powered drum 7 is then operated
to drive the pipes downwardly into the riser 4 until the HSP 11
reaches its required lower position in the riser. The packer seal
10a is made operative to seal with the riser wall.
[0137] Shortly before the HSP 11 reaches its final position, the
upper end of coaxial pipe 19 comes off the powered drum 7, the
weight of the pipe and pump 11 in the riser 4 being supported by
the tensioner of the pipe delivery and retrieving apparatus, which
grips the upper end section of outer pipe 13. Then a conventional
so-called "hang-off" device (not shown) is attached to the pipe
end, followed by another short length of auxiliary pipe 49 which,
can be wound on the powered drum 7 or may already be wound on the
drum, or carried by the crane 9 on the support vessel 6. The drum
or crane, as the case may be, then lowers the auxiliary pipe 49
until the hang-off device has passed through the lubricator 8 and
the pump 11 is just very slightly above its final position. The
hang-off device is now actuated and the auxiliary pipe 49 lowered
the final short distance to engage the hang-off device with the
buoyancy unit 20 and support the weight of the coaxial pipes 12, 13
and pump 11 in-the riser 4. FIG. 4 shows the system at this stage.
Following this, the maintenance stack 24 is disconnected from the
wye junction 25 and raised, together with the auxiliary pipe 49,
back to the support vessel 6. Finally, as shown in FIG. 4a, a
pressure cap 50 is fitted by means of a running tool to complete
the necessary hydraulic connections between hydraulic pipes 45, 47
and the coaxial pipes 12, 13 and provide operating and
environmental seals.
[0138] As shown in FIG. 4a, a hose 43 for hydraulic fluid 43
supplied from the support vessel 6 conveys hydraulic fluid to the
buoyancy unit 20, where it passes through connecting line 44,
including an isolator 45, to supply line 12, down to HSP 11 and
back up return line 13 to the buoyancy unit 20 through connecting
line 46, including isolator 47, from where the hydraulic fluid is
returned to the support vessel 6 by hose 48. In this way, the HSP
11 is hydraulically powered, to pump hydrocarbon fluid up the riser
4.
[0139] Retrieval of the HSP 11 back to the vessel 6 for maintenance
or replacement is essentially a reversal of the above step's, just
as in the preceding embodiments. Therefore, no description is given
of this retrieval procedure.
[0140] As shown in FIG. 4b, if the riser 4 is to be piggable, the
wye junction 25 can be replaced by a wye junction 28 turned the
opposite way up. Conveniently, a gooseneck pipe 23 is connected to
the wye junction 28, for supplying pigs to be introduced into the
riser 4. The HSP 11 has to be raised to a position above the wye
junction 28, before the pigging operation can begin. Where the size
of the HSP permits, the gooseneck may allow deployment of the HSP
from the vessel 6 by insertion through the take-off hose 22 down t6
its operating position.
[0141] The system of FIGS. 4, 4a and 4b for raising hydrocarbon
fluid can be modified in accordance with the modifications
according to FIGS. 2a and 2b, in corresponding fashion. In the
former case, the riser will include a single rigid pipe, that is
the hydraulic supply pipe 12 supplied from hose 43. In the latter
case, the power supply line for the electric pump 11 runs inside
hose 43 and down inside pipe 12. Of course, the HSP can be replaced
by an electric pump in the other embodiments as well.
[0142] In the preceding embodiments, the down-riser pump, whether
hydraulic or electric, is mounted inside the riser. However, in the
modification of FIGS. 5 and 6 to the system according to FIGS. 1
and 2, the coaxial pipe arrangement 19 is used solely for
circulating heating fluid to a heating "stinger" or heater 30,
positioned adjacent the lower end of riser 4, and one pump of a
pair of electric pumps 31, 32 mounted externally of the riser 4 in
series with it is used for driving the production fluid up the
riser. Two pumps are provided for redundancy and in view of the
difficulty of repairing a pump in situ or recovering it to the
surface of the sea. If one fails, the other can be brought into
service using the switchgear 33, to take over from the first pump.
The power supply line 34 for the electrically driven pumps is
carried on the outside of the riser 4 and connected to the
switchgear 33 via power connector 35. This system does not offer
the above described advantages that would arise if the pump were
mounted inside the riser and retrievable to the support vessel or
buoyancy unit, but it does avoid the risk of freeze-ups due to the
delivery heat to the lower end region of the riser. It also enables
the heater to be retrieved to the top end support, i.e. the support
vessel 6, for repair or replacement. As an alternative to the
electrically driven pumps, there may be used hydraulic pumps.
Furthermore, if the production fluid pressure in flowline 1 is
large enough, the external pumps are not required.
[0143] In accordance with another embodiment shown in FIG. 7, the
single pipe 12 such as included in FIG. 2b or in the FIG. 4
embodiment as modified in FIG. 2b is used solely for supplying gas
under pressure to a gas injector in the riser, for creating gas
lift for raising the hydrocarbon fluid in the riser. FIG. 7 shows a
system with buoyancy unit 20 similar to that shown in FIG. 4. In
FIG. 7, the injector or poker is shown diagrammatically at 36. The
pressure gas is supplied to the injector 36 via a hose from the
support vessel to the buoyancy unit 20 and down to the injector.
This system exhibits the advantage that, where it is appropriate to
use gas lift, the need to supply the lift gas via an external pipe
is avoided. This also avoids having to form an aperture in the wall
of the riser 4, so that the pressure gas supply line can pass
through the riser wall. Again, the gas injector 36 can be raised
for maintenance or replacement and a heater and/or HSP in the riser
is optional, according to needs.
[0144] In the embodiments of FIGS. 5, 6 and 7, the heater 30 and
gas poker 36 in each case are preferably guided in the riser 4 by
an element similar to the packer 10, with the difference that, when
actuated, it engages with the riser wall but it does not need to
seal with it.
[0145] In all of the above-described embodiments and modifications,
the pipe arrangement 19, which may comprise two or more nested
pipes or a single pipe, is preferably made of steel or suitable
composite material, so as to have a sufficient degree of rigidity
such that as the pipe delivery and retrieval apparatus drives the
pipe arrangement 19 down the riser 4, the riser will not flex
significantly or buckle, such as to cause jamming or damage to any
part of the system, particularly the pipe arrangement 19 itself. It
is also pointed out that since the pipe arrangement 19 is
relatively heavy due to its large size (for example a coaxial pipe
might typically have an outside diameter of 7.5 cm to 12.5 cm) and
large wall thickness (for example for steel coaxial pipes, the wall
thickness of each pipe might suitably be some 9 mm thick), as more
of the pipe length is deployed down the riser the deployed weight
increasingly assists in pulling the pipe length off the powered
drum 7. The tensioner of the pipe laying and retrieving apparatus
can then serve to support part of the weight of the pipe
arrangement.
[0146] It is also mentioned that a standard lubricator also
generally has drive tracks which assist the deployment of the pipe
length.
[0147] It is also considered that a steel pipe, for example, will
also have sufficient elasticity to bend slightly to follow any
non-linearity in the riser 4 itself resulting from its compliance
to accommodate motion of the top end support, such as support
vessel 6 or buoyancy unit 20, relative to the flowline 1 on the sea
bed. However, whilst it is preferred to use a pipe delivery and
retrieval apparatus such as described, nevertheless another
workable option would be to use coaxial pipes (or a single pipe),
which are flexible. In that event, the means for conveying the pump
down-riser would suitably take the form of a pig or towing gland
that slideably closes the annulus between pump and riser/flowline
attached to the pump itself or to a lower part of the pipe, which
is then driven down the riser by introducing hydraulic pressure
into the upper end of the riser above the pig. One possible way of
implementing this teaching is to design the packer fitted on the
HSP to function as a pig.
[0148] Reference is now made to further embodiments according to
FIGS. 8 to 11, 11a to 11c, 12 and 12a to 12d, 13 to 15 and 16a to
16d. These embodiments bear similarities in a number of respects to
the preceding embodiments, and where possible corresponding
reference numerals are used. Accordingly, the following description
is confined mainly to differences in construction or operation.
[0149] Reference is now made to FIGS. 8 to 10 for a description of
using VARRIS as a means of evacuating the riser/flowline by gas
displacement or combined gas/methanol displacement, or by action of
the pump.
[0150] In order to avoid the problem of hydrate formation, a
solution can be afforded by a method of using coiled tubing 19
(either a single or coaxial tube) inserted inside the riser 4, or
the riser and flowline, via the tubing head at the top of the riser
to remove the fluids (and hence the residual head from the riser 4
and its flowline 1) to a point where the remaining fluid static
head in the riser/flowline is lower than the hydrate formation
pressure. By using this technique another method of hydrate control
is available that can be used either on its own or in combination
with other methods and offers greater security against blockage.
Furthermore as the location of the drain/venting system is within
the riser 4 there is no requirement for external intervention as in
conventional techniques.
[0151] In the embodiments to be described with reference to FIGS. 8
to 10, at least one conduit internal to the riser and flowline
enables evacuation of fluids thereby reducing the static head in
the riser/flowline system on flow interruptions/shutdowns below the
hydrate formation pressure. The or each conduit may comprise coiled
tubing 19 or multiple pipe lengths inserted at the riser top end.
The lowest point of fluid evacuation is at any point in the
riser/flowline between the riser top and subsea wellhead. The
conduit 19 may be used as part of a separate system, e.g. as part
of a pump power fluid supply or liquid heating line. In FIGS. 8 to
10, the coiled tubing 19 comprises an outer tube 118 and an inner
coaxial tube 115.
[0152] FIG. 8 shows a closed-loop variant implementing concepts as
outlined above. A flowline 1 is connected via a check valve 125,
providing limited leakage, to the inlet of a hydraulic pump 11,
which is sealed to the inner surface of the flowline 1 by a packer
10 having a releasable seal. The check valve 125 may alternatively
form part of the pump inlet tract or packer 10. Following isolation
of the flowline 1, a means of removing the fluid contents of a
riser 4 and its flowline section downstream of the VARRIS barrier
provided by the pump 11, or packer 10, is provided by the injection
of gas via an inlet valve 129 into the annulus 105 between the
inner wall of riser 4 and the coiled tubing 19. This causes the
fluids to be forced through a riser evacuation port 126 and back to
the surface via the annulus 114 between the outer tubing 118 and
the inner tubing 115 exiting via a valve 130. On completion of
fluid removal, the annulus 105 is depressurised resulting in
equalisation of pressure across check valve 125, and ultimately
providing a pressure in the flowline 1 immediately upstream of the
packer 10 equal to the gas pressure in the riser annulus 105.
[0153] The operating method will now be described in detail. In the
no flow condition, the system settles down such that there is
negligible differential pressure across check valve 125.
[0154] In normal productions, the pump 11 is operated by hydraulic
fluid supplied via value 131 and exhausted via valve 130. To remove
fluids from the riser 4 following a cessation of production, the
main production valve 128 and drive fluid inlet valve 131 are shut.
Gas is added to the annulus 105 between the outer tubing 118 and
the riser 4 via gas access valve 129 until the differential
pressure, or flow back towards the flowline 1, causes check valve
125 to close. Alternatively, fluid may fall back in the annulus 105
which will close check valve 125. Further addition of gas via gas
access valve 129 increases the pressure in annulus 105 until the
check valve in the riser evacuation port 126 opens. Still further
addition of gas via valve 129 results in the fluids flowing via the
riser evacuation port 126 into the annulus 114 between the inner
and outer tubings 115 and 118 and back up to the surface to exit
via the drive fluid exhaust valve 130.
[0155] Evacuation is continued until the fluid level in the riser
annulus 105 has reached a predefined level.
[0156] The gas in annulus 105 is now vented or recompressed and
stored under reduced pressure at the top of the riser, thereby
reducing the differential pressure across the check valve 125 until
it opens. A higher upstream pressure in the flowline 1 may deliver
a small volume of fluid through the pump 11 into the annulus 105.
This fluid can be removed by re-application of the above cycle one
or more times, until the pressure in the annulus 105 ideally
approaches atmospheric pressure. On completion, the check valve 125
remains open and the pressure in the riser annulus 105 is bled to a
low value (or vacuum). The resulting residual pressure in the
flowline 1 upstream of the check valve 125 is then purely a
function of the head of fluid in the flowline 1. Due to the
substantially complete removal of hydrocarbon production fluid in
annulus 105 and the relatively low pressure achieved in this
annulus, hydrate formation in the riser during production
interruption can be avoided.
[0157] The production fluid now vented from the riser annulus 105
into the annulus 114 between the inner and outer tubing 115 and
118, is circulated to topside for processing or storage. The fluid
may be completely evacuated from annular space 114 by circulating
pump drive fluid via drive fluid inlet valve 131.
[0158] An open-loop variant is shown in FIG. 9. The principal
difference from the closed loop variant of FIG. 8 is that the pump
drive fluid is exhausted into the riser annulus 105 along with the
boosted product from the flowline 1 and there is a single drive
fluid conduit 115 between the surface and the pump 11. Operation
will now be described in detail.
[0159] In the no flow condition the system settles down such that
there is negligible differential pressure across check valve
125.
[0160] To remove fluids from the riser 4 following a cessation of
production, the main production valve 128 is shut. Methanol (or
other hydrate formation inhibiter) and gas are added to the annulus
105 between the tubing 19 and the riser 4 via gas access valve 129
until the differential pressure, or flow back towards the flowline
1, causes check valve 125 to close. Further addition of gas via gas
access valve 129 increases annulus 105 pressure until the check
valves in the riser evacuation port 126 opens. Further addition of
gas via valve 129 then results in the fluids flowing via the riser
evacuation port 126 into the tubing 115 and back up to the surface
to exit via the drive fluid valve 131. Check valve 176 closes to
prevent flow through the turbine section of the pump.
[0161] Evacuation is continued by further addition of gas/methanol
until a predefined volume of total liquid is retrieved to the
surface. The gas in the annulus 105 is now bled to store at reduced
pressure reducing the differential pressure across the check valve
125 until it opens. A higher upstream pressure in the flowline 1
may deliver a small volume of fluid through the pump into the
annulus 105; this fluid can be removed by re-application of the
above cycle. On completion the check valve 125 remains open and the
annulus pressure in the riser 4 is bled to a low value (or vacuum).
The resulting residual pressure in the flowline 1 upstream of the
check valve 125 is then purely a function of the head of fluid in
the flowline 1. The small residual volume of product, methanol and
gas remains within the tubing 115 and is circulated back to the
riser annulus 105 on restart.
[0162] FIG. 10 shows the use of VARRIS as a means of evacuating the
riser flowline by use of pump 11.
[0163] Following isolation of the flowline the internal riser
services incorporate a means of removing the fluid contents of the
riser 4, and its flowline section 1 downstream of the VARRIS
barrier provided by the pump 11, or packer 10, by using internal
valving 132, 133 within the pump 11 to drain the riser 4 and
utilising the power fluid exhaust route 114.
[0164] The operation will now be described. In the no-flow
condition, the system settles such that there is negligible
differential pressure across check valve 125.
[0165] To remove fluids from the riser 4 following a cessation of
production, the main production valve 128 is shut and the pump's
riser evacuation valve 132 is opened, together with an annulus
by-pass valve 133. This operation may also include operation of
internal valves within the pump casing to bias check valve 125
shut. The pump 11 is now driven in the conventional manner.
However, fluid in the riser 4 is now delivered to the annulus 114
between the inner and outer tubing, and is then exhausted via the
fluid outlet valve 130. Normally, drive fluid will be supplied via
valve 131 and exhausted through valve 130 to drive the pump 11 in
the forward direction. However, the same result could be achieved
by reversing the direction of drive fluid flow (i.e. in via valve
130 and out via valve 131), thus driving the pump in reverse, and
by suitable valving within the pump to cause evacuation of riser
4.
[0166] Evacuation continues until a predetermined volume of fluid
has been retrieved, at which point either circulation continues to
flush the VARRIS inner and other tubing, or an inhibitor (e.g.
methanol) is fed into the riser 4 via gas access valve 129 and
circulated into the drive fluid return annulus 114.
[0167] FIG. 11a relates to VARRIS as a slug
suppresser/separator.
[0168] Instead of using external slug suppression/separation
equipment, the embodiment of FIG. 11a is based on the principle of
installing this equipment within the riser 4 or its flowline, thus
avoiding the need for additional surface vessels, as installation
and maintenance is conducted from the riser tubing head interface
at the destination facility.
[0169] For the purpose of this description, the riser 4 may be
considered to include a flowline 1 on the sea bed, a transition
zone 107 and a separation zone 108.
[0170] Such system operates by using the energy lost in the riser's
separation zone 108, to assist in separating the liquid and gas
phases using a series of three, nested, e.g. collinear, tubular
pipes 103, 118 and 115. The separation is cyclonic and preferably
incorporates a cyclonic, or helical, insert, to assist in
partitioning the gas and liquid phases. The gas' phase is directed
upwards from this separation zone 108 while the liquid phase is
driven downwards from the separation zone 108 towards the pump 11,
by a combination of gravity and pump suction. The pump 11 is
preferably set sufficiently low that the bulk of any remaining gas
bubbles are re-absorbed by the liquid prior to entry into the pump
11 from where the liquid is boosted and transported to the surface
via a tubing annulus.
[0171] Referring to FIG. 11a, the VARRIS services are intended to
divide the riser 4 or flowline into discreet zones in which the
products phases can be separated and recovered by different
flowpaths. Transportation of each phase will utilise internal
energy, and added energy combinations. Any liquid phase (which may
incorporate one or more gas phases or gases in solution) is
anticipated to be lifted by one or more pump located within the
riser or flowline.
[0172] Product in the flowline 1 enters the VARRIS zone via the
packer 10 that is attached to the outer VARRIS tubing 103 at its
lowest end. (Note: the arrangement is shown in the horizontal
section on the seabed. The description is exactly the same should
the system be installed in the vertical riser section 4). The
product flows via the annulus 105, between the riser 4 or flowline
1 and tubing 103. As the fluid rises towards the riser packer 106,
there is an increase in gas breakout and slug formation (successive
gas and liquid slugs) over the transition zone 107. The mixed phase
flow enters the base of the separation zone 108, where a perforated
tubing section 109, directs the fluid into the separator. The
height `H` above seabed of the riser packer 106, perforated tubing
109, and separation zone 108, is set to achieve the desired flow
characteristics and is expected to be varied as the produced fluid
characteristics (e.g. water cut, flowrate, viscosity, temperature
and pressure) change with time. Normally, this height will be
reduced as the wellhead pressure reduces. This can be done by
withdrawing the entire VARRIS apparatus from the riser 4,
repositioning the packer 106 (such as by releasing its securing
bolts (or other fastening means), resecuring them in the desired
new position on the outer VARRIS tubing 103, and then reinstalling
the device inside the riser 4 or flowline 1. If the position of the
pump 11 is to be altered in the horizontal section, this can be
done while the device is withdrawn from the riser, by resetting the
relative positions of the middle tubing 118 and the middle tubing
hanger 120.
[0173] Reference is now made to FIGS. 11b and 11c, which are
horizontal sectional views taken along the lines 11b-11b and
11c-11c respectively in FIG. 11a. As shown in FIG. 11c, positioned
inside the perforated tubing 109 is a cyclone insert 123, defining
substantially tangential inlet passages 1231 so as to create
swirling of the fluid entering the separator zone. As is well
known, this swirling or cyclonic separation causes denser, liquid
rich, fluid 1232 to sink and leave the separation zone 108 as
underflow and less dense, gas rich, fluid to rise in the separation
zone 108 and leave as overflow. Other constructions, well known per
se, for creating cyclonic separation can be used instead of the
specifically described arrangement.
[0174] Therefore, within the separation zone 108 the production
fluid enters the separator, which operates such that liquids will
be directed to travel circumferentially downwards whilst a gas rich
mixture migrates upwards. The upper section of the perforated
tubing 109 allows the gas to flow at 110 into the upper annulus 111
between the riser 4 and the outer VARRIS tubing 103. Liquid carried
over into the upper section is free to return to the lower riser
section via perforations located at the lower end of tubing 109
above the packer 106. Gas continues to rise to the tubing head 124
where it exits at gas outlet 112.
[0175] Liquid in the separation zone 108 descends towards the pump
11 via the annulus 114 between the VARRIS outer tubing 103 and
VARRIS middle tubing 118, where it enters the pump at 116. The
boosted liquid is exhausted from the pump at 117 into the annulus
119 between the VARRIS middle tubing 118 and the pump power supply
tubing 115. The boosted liquid is then driven up the riser to the
tubing head where it exits at 121.
[0176] Locating the pump 11 in the horizontal flowline section 1,
which is the low point of the riser, encourages the hydrostatic
pressure to force any gas in the liquid underflow back into
solution.
[0177] The pump drive may be either hydraulic (HSP) or electrical
(ESP). In the former case the power fluid enters via the tubing 115
and is fed to the pump turbine where it will be either exhausted
into the annulus 119 together with the boosted product (this is
referred to as open loop), or returned via a coaxial return line
115A external to the pump power supply tubing 115 (this is referred
to as closed loop). In the ESP case the power cable would be run
inside the pump power supply tubing 115.
[0178] As shown, the apparatus incorporates measures, similar to
that disclosed with reference to FIGS. 8, 9 and 10, to inhibit
solid hydrate under flow interruption or shutdown conditions by
removal of the liquid head in the riser annulus 105 into annulus
119 using gas displacement. In particular, pump 11 operates to
expel production fluid in the riser, via one-way pressure valve
126, to the low pressure region at the upper end of the riser,
thereby reducing the pressure acting in the region of the riser 4
formerly occupied by the production fluid.
[0179] Therefore, the separation device according to FIGS. 11a to
11c comprises integral artificial lift that is installable in a
riser or its associated flowline and incorporates a plurality of
nested or un-nested tubings run from the top end of the riser using
combinations of coiled tubing or jointed straight pipe sections.
The device may be installed and operated in an existing riser or a
newly installed riser. Furthermore, it may be operated in a
vertical riser, buoyant tower riser, catenary riser, compliant
vertical access riser, S-configured riser or wave configured riser.
The riser may be constructed from continuous steel tubing,
composite pipe (metallic and non metallic materials and hose) or
combinations of these. The riser may also be dynamic and freely
suspended from a buoyant body, or rigidly attached to a
structure.
[0180] The device may be able either in part or in its entirety to
enable maintenance or reconfiguration of the separation
elements.
[0181] The device offers the facility to evacuate production fluids
from the flowline/riser and remove the residual pressure head or
the contents left within the flowline.
[0182] In conventional systems, successive slugs of gas and liquid
in transition zone 107 are brought to the upper end of the riser
and separated by a slug catcher, followed by multi-stage
separation. The integral slug suppressor separator included in the
riser system according to FIGS. 11a to 11c in effect performs the
function of the slug catcher and the first stage separator of the
conventional system and represents a simpler, cheaper, yet
effective slug separator/suppressor.
[0183] It will be appreciated that, when functioning as a slug
separator/suppressor, the function of the pump, primarily, is to
pump the liquid underflow from the cyclone separator up to the
surface at the top of the riser. When positioned low down in the
riser, it can also function to maintain gas dissolved in the liquid
underflow in solution right up to the surface. It also has the
further function of assisting in inhibiting solid hydrate
formation, as described above.
[0184] FIG. 12 shows the use of VARRIS in an existing riser
(shallow or deep water, rigid or flexible) for pressure
boosting/provision of artificial lift. A problem for installing
VARRIS in an existing riser arises where the riser includes
relatively sharply bending sections. A hydraulic pump for a given
pumping capacity will generally be preferred to a similarly rated
electric pump since it is typically much shorter, e.g. 4-5 m long
as compared with 30-50 m long for an electric pump, and can
therefore pass through a sharper bend in the riser. For this
reasons, an electric pump would typically be used only in vertical
risers, and hydraulic pumps would be employed in risers having
bends.
[0185] Some risers are of coiled spiral inner construction, with an
outer reinforced casing, or other similar form (see FIG. 12a),
enabling the riser to undergo sharper bends than would otherwise be
possible. Even a hydraulic pump has difficulty passing around sharp
bends because of the risk of getting stuck. The embodiment
according to FIG. 12 is designed to overcome this problem.
[0186] FIG. 12 shows a system for boosting or providing artificial
lift from a subsea well in a flexible riser hung from a floating
surface body or via tubing head 122. Casing flexibility and torque
reaction are achieved by mechanical and/or elastomer means, as will
be described below.
[0187] The pump packer 102 and check valve 125 are located within
the homogeneous bore section of the end termination 142 of the
composite riser 4 and the riser base/manifold spool 143. Fluid from
the flowline 1 enters the pump 11, powered via hydraulic power
supply 115, and, in corresponding manner to that occurring in the
embodiments according to FIGS. 8 to 10 described above, is
exhausted into the riser annulus 105, where it flows to the
surface. Riser evacuation is achieved by the same process as
described above with reference to FIGS. 8 to 10.
[0188] The pump 11 comprises a hydraulic pumping section 113a, a
turbine section 113b for powering the pump section and where
required, a flexible coupling section 113c.
[0189] It will be appreciated that the articulation between the
pumping section 113a and the packer 102 enables the pump 11 to
encounter and negotiate relatively tight bends in the riser, and
significantly tighter than if the articulation was not provided,
without becoming jammed. Furthermore, the fact that a hydraulic
pump is used, which is typically much shorter than an equivalently
rated electric pump, contributes to the ability of the equipment to
negotiate relatively sharp bends.
[0190] For installation the pump is passed on its hydraulic power
supply pipe 115 down into the riser 4, and articulates around the
composite riser bends by means of flexible coupling 113c. The power
supply pipe 115 is optionally supported as required by intermittent
spacers 144.
[0191] Evacuation of the riser annulus uses the same techniques as
described with reference to FIGS. 8 to 10 above.
[0192] The above system is also applicable to various riser
configurations, e.g. the so-called lazy-S (FIG. 12b), steep wave,
(FIG. 12c) and steep S (FIG. 12d) configurations.
[0193] It will be appreciated therefore that this embodiment finds
particular application to shallow water applications.
[0194] Referring now to FIG. 13, there is shown a system for
boosting or providing artificial lift from at least one subsea well
or at least one subsea field in a rigid or compliant riser
suspended from a fixed platform shown schematically at 151.
[0195] In this embodiment, the riser 4 is a rigid tube suspended
from a static hang off point on the fixed platform 151, and
guided/supported by the platform at intermediate points, 152, along
the length of the riser. Although the pump 11 is shown in the
vertical section it can be installed past the base bend 153 of the
vertical riser section leading to the horizontal section lying on
the sea bed, by virtue of the flexible coupling 113c that permits
articulation. Where the pressure boost/artificial lift afforded by
the pump 11 is not required, a heating line and heater can be used
as in embodiments such as according to FIG. 2b. Of course, the
present embodiment may include such heating line and heater in
addition to the pump assembly, where artificial lift and heating
are both required.
[0196] Reference will now be made to FIGS. 14 and 15, which show
embodiments capable of transporting VARRIS equipment to from a
location remote from the top insertion point on a riser.
[0197] In general, to position permanent components axially along a
riser/flowline, motive force can be provided by:--
[0198] 1. gravity acting on the vertical elements of a deployment
string;
[0199] 2. a pushing force applied at the riser entry point of the
deployment string (according to VARRIS);
[0200] 3. flow within the riser/flowline driving a towing pig;
[0201] 4. an electrically driven tractor unit; or
[0202] 5. combinations of these methods.
[0203] 1/. & 2/. are limited by the ability of the string to
accommodate buckling forces, 3/. requires a circulation path (i.e.
a flowline loop), and the towing pig must not offer undue
resistance during normal production operations. 4/. requires an
umbilical to be run with the tractor unit. Generally the difficulty
lies in transporting heavy components significant distances in a
single, non-looped, flowline laterally, e.g. to the location of the
subsea wellhead, manifold or production centre, from the bottom of
the riser section, where there is a relatively sharp bend section
connecting the riser section and flowline.
[0204] FIG. 14 is a first embodiment designed to solve these
problems. It uses a tractor unit powered by VARRIS power supply
coiled tubing 19 to install a tool or other down-riser operating
device.
[0205] A tractor unit, as used for automated drilling using coiled
tubing for down-riser deployment is powered by hydraulic fluid
provided from VARRIS power supply tubing 19. The tractor
tows/pushes the VARRIS pump 11 until it reaches a predefined
location in the riser 4 or flowline 1 determined by the length of
power supply tubing 19 inserted into the riser/flowline. Once at
its location, pressure set valving within the tractor is used to
set the packer that locates the VARRIS tool in position (e.g. as a
pump), and the tractor function is disabled. Power fluid is now
directed to the VARRIS pump which operates in the manner described
in preceding embodiments.
[0206] To retrieve the pump, pressure set valving within the pump
disconnects the packer. The pump and its tractor can now be
retrieved by applying a tension on the power supply tubing from a
tensioner located at the riser tubing head entry point. If needed,
additional drive is available by controlled operation of the
tractor in the reverse direction.
[0207] A specific implementation of this method will be described
below with reference to FIGS. 14a, 14b and 14c.
[0208] A second technique to be described with reference to FIGS.
15a, 15b and 15c uses the principle of the VARRIS pump which
provides self drive along a flowline.
[0209] In this second method, the VARRIS pump is provided with
drive fluid during installation. This drives the pump and produces
a low pressure area in front of the pump relative to the pump
discharge. This is maintained as a differential pressure across the
pump by virtue of a lip seal type gland (the towing gland) which
permits the force generated by this differential pressure to pull
the pump and VARRIS power supply tubing along the flowline. A
controlling back tension is provided by the tensioner located at
the riser's tubing head. Once at its location pressure set valving
within the pump is used to set the packer that locates the VARRIS
tool in position in common with previous descriptions. Retrieval of
the pump is achieved by deactivating the packer as described above
and applying a tension on the power supply tubing from the
tensioner described above.
[0210] Reference is now made to a specific implementation of the
first method shown in FIGS. 14a, 14b and 14c, where the
installation distance from the riser base exceeds the ability of
the coiled tubing deployment drum 7, or derrick system 160, to
place the VARRIS components into position, due to buckling of the
tubing 19. This problem is overcome by a tractor unit 158 used to
haul the VARRIS components (e.g. pump assembly 11, and VARRIS
tubing 19) into position.
[0211] The function of the tractor unit 158 is to drive the pump
assembly 11 down-riser and also to retrieve the pump assembly to
the top of the riser, for repair or maintenance. The tractor unit
has a drive arrangement which comprises essentially a forward pair
and a rearward paid of inflatable grippers 158a, 158b mounted on
respective parts of a telescopic chassis. On inflating the forward
grippers 158b so as to grip the inner surface of the riser wall and
deflating the rearward grippers 158a so as to release them from
riser inner surface, the rear telescopic part is retracted relative
to the now stationary forward one. Then, the forward grippers 158b
are deflated, the rearward ones 158a inflated and the front
telescopic part extended forwardly relative to the rear part. By
repeating the above sequence of operations, the tractor unit can
advance insider the riser. With appropriate action on the grippers
and telescopic chassis in a corresponding fashion, the tractor unit
158 can also retreat in the opposite direction within the
riser.
[0212] On completion, the tractor unit 158 may either remain in
position as the grippers are arranged so as not to seal the
annulus, allowing fluids to flow past it via the annulus 105, or it
may form a permanent part of the packer 10. Retrieval of the system
follows disengagement of the packer 10, and application of tension
to the VARRIS tubing 19 via the dispensing drum 7 located at the
tubing head 122.
[0213] A preferred method of operation will now be described
starting with installation. The system as described above according
to various disclosed embodiments is installable from the tubing
head 122 down to a remote subsea facility (e.g. subsea manifold
processing centre/junction 156, or subsea well 157), by use of a
tractor unit 158, which derives its power from the VARRIS power
supply tubing 19, differential head across the tractor unit 158 or
electrical supply umbilical 164. It is envisaged that the most
likely power option for the tractor unit 158 will utilise hydraulic
drive supplied via the VARRIS power supply tubing 19.
[0214] The VARRIS power supply tubing 19, may be either of open
loop (i.e. single coiled tubing) or closed loop (coaxial tubing
format). The pump assembly 11, will correspondingly be of open loop
(i.e. power fluid exhaust into the product in the flowline 1), or
closed loop (power fluid exhaust and returned to surface via
coaxial return line).
[0215] Once in its operating position the tractor unit drive is
disengaged and the packer 10 is set, so as to engage with the inner
wall surface of the riser. The grippers 158a, 158b on the tractor
are deflated/retracted such that maximum local annulus area can be
achieved for the packer 10. It is envisaged that for the powered
option these grippers 158a, 158b will not encompass the full cross
section of the annulus 105 in a single plane at right angles to the
major axis of the flowline, but will occupy sectors of the annulus
105 spaced at intervals along the major axis. This provides a fluid
path between both sides of the tractor unit for the passage of
product or other fluids in the flowline 1.
[0216] The VARRIS power supply tubing 19 may be deployed from a
coiled tubing drum 7 (FIG. 14a), or derrick 160 (FIG. 14c).
Hydraulic power fluid is provided to the VARRIS power supply tubing
19 via at least one integral coupling 161, for the coiled tubing
drum 7 with its pipe straightener 135, or via removeable power
fluid hose 162 for the derrick method. Retrieval of the down-riser
operating device will now be described. Following disengagement of
the packer 10, the VARRIS components are retrieved by applying a
hauling tension via the tensioner 163, located above the riser
tubing head 122. For the closed loop power fluid supply method,
additional retrieval effort may be achieved by reversing the
turbine drive fluid and supply fluid routes and re-energising the
tractor unit 158, to operate in the reverse direction. This would
be performed under limited input flow to prevent buckling of the
VARRIS tubing.
[0217] An example of the second method referred to above will now
be described (see FIGS. 15a, 15b and 15c) in which the system is as
described above but which operates to haul the VARRIS components
into place by using differential pressure generated across the pump
11. This is achieved by driving the pump 11 via the power supply
tubing 19, thus providing the motive force.
[0218] The method of operation for a closed loop option according
to FIGS. 15a, 15b and 15c is as follows. For the closed loop option
the drive fluid returns to the tubing head 122 via the coaxial
return of the VARRIS power supply tubing 19. Thus, there is at most
very minor net addition of fluid into the riser annulus 105.
Differential pressure across the pump assembly 11, and towing gland
166, is generated by circulation of drive fluid that drives the
pump 11, thus displacing fluid from the flowline 1, upstream of the
pump 11 and creating a low pressure zone relative to the pressure
in down stream annulus 105. This differential pressure energizes
the towing gland 166 forming a sliding seal and the resulting
differential pressure on the pump casing and towing gland 166,
provides the motive force to haul the system into position.
[0219] For retrieval, the equalisation of differential pressure, or
a differential pressure acting in the opposite direction
de-energises the towing gland 166, and enables the VARRIS
components to retrieved by applying a hauling tension via the
tensioner 163, located above the riser tubing head 122.
[0220] The method of operation for an open loop option will be
described. This option is the same as shown in FIGS. 15a-15c,
except that no return hydraulic flow line is provided in power
supply tubing 19. For the open loop drive fluid option both the
drive fluid and any liquid displaced upstream of the pump are
dumped into the annulus 105. The higher pressure in the annulus 105
relative to the lower pressure upstream of the pump cause the
towing gland 166, to be biased to seal. The resulting differential
pressure on the pump-casing and towing gland provides the motive
force to haul the system into position. The net additional fluid
provided by the drive fluid entering the system is drawn off at the
tubing head 122. For retrieval, the lack of differential pressure
across towing gland 166 (achieved by the leaky nature of biased
check valve 125) enables the VARRIS components to be retrieved by
applying a hauling tension via the tensioner 163, located above the
riser tubing head 122.
[0221] Another application of VARRIS is to the removal of
scale/wax.
[0222] In a single flowline with no circulation capability, or
where a blockage (partial or total) prevents establishment of a
circulation route, it is not possible to access or clean along the
flowline unless the device providing this function is self-powered.
Also if the build up on a flowline or riser wall comprises hard
scale, this is likely to need to be removed by active means (e.g. a
cutter) rather than passive means (scraper pig). At present,
available active cutting means are of very limited
effectiveness.
[0223] In keeping with the basic configuration of running internal
service tools on coiled tubing as described in previous VARRIS
examples, a turbine driven cutter/brush module complete with a low
throughput high internal clearance pump 11, is located at the end
of the VARRIS power supply tubing. Using similar operating
principles to those of the embodiment of FIG. 15a above, the cutter
which is forward of the pump is driven by a common shaft/reduction
unit. As above a differential pressure is achieved across the tool
which provides motive force to pull the cutters along the flowline.
Cuffing retrieval may be achieved by a variety of methods:--
[0224] 1. Where there is no flow in the flowline either from
production or from open loop power fluid discharge, the cuttings
can be retrieved as the tool is hauled back to the riser entry
point;
[0225] 2. Where there is no flow in the flowline, cuttings are
known to be pulverised, and a closed loop system is used, the pump
can ingest the cuttings and deliver these back to the surface via
the closed loop return line;
[0226] 3. Where there is an open loop return, the cuttings are
driven back to the surface using the power fluid discharge; and
[0227] 4. Where it is required to perform the cleaning operation
under conditions where product flows continuously (i.e. continuous
production), the VARRIS tubing and its cutting tool are run from
the tubing head using a conventional coiled tubing
lubricator/injector assembly. Cuttings retrieval would use any of
the above options 1 to 3.
[0228] Although a cutter is mentioned for cleaning the inside of
the riser, other forms of cleaning device e.g. a brush or brush
cutter, can be used. The type of cleaning device selected will
depend on how harsh or gentle the cleaning action needs to be.
[0229] The system principle is similar to that described above for
previous embodiments and uses the power turbine or electric motor
drive to rotate a cutter/brush module 171 (see FIGS. 16a-d), for
the purpose of cleaning deposits from the inside wall of a pipeline
1 or riser 4. Insertion and retrieval uses the principles described
above. The previously described VARRIS combination of closed and
open loop systems are applicable for the case when it is required
to travel within the pipeline whilst cutting and simultaneously
boosting flow. Hence, when not actuated the pump packer is required
to be a sliding fit within the pipeline/riser inner wall and a
small percentage of leakage or forward flow reflux from the
discharge of the pump back to its suction is permissible. In
addition to cutting whilst there is a flow in the pipeline, it is
possible to cut under no-flow conditions by providing a transport
fluid down the annulus 105, to the vicinity of the cutters (or via
the VARRIS power supply tubing 115). This fluid is returned to the
surface with the ingested cuttings 172, through the pumping section
113a, and from there via the return annulus of the VARRIS power
supply tubing. A variation on the transport fluid concept is to
provide this fluid in the form of excess turbine drive, the surplus
transport fluid being dumped into the vicinity of the cutters 171,
and thence returned to the surface via the annulus 105. In all
cases the cutter/brush module 171, may be in the form of a rigid
extension of the VARRIS turbine shaft or pump shaft or a dedicated
remote unit driven by extensions of the shaft of the VARRIS turbine
113b. A gearbox 173 may be used to optimise the cutter speed.
[0230] Various embodiments will now be described.
[0231] A closed loop production mode cleaning apparatus is shown in
FIG. 16a. In this mode, the propulsion drive is provided
principally by the pressure differential over the towing gland 166,
which is a sliding sealing fit in the riser. The rotating cutter
171 will generally produce a pressure differential across it which
will tend to draw the tool down inside the riser 4 but its driving
effect is small compared with that produced by the pumping unit
113a/packer 166.
[0232] The power turbine drive fluid, both supply and return, is
entirely contained within the co-axial coiled tubing 19 attached to
the end of the turbine 113b. The boosted production flows
separately to the surface via annulus 105.
[0233] On the return movement the boost power may be reduced to
allow the well fluid pressure acting on the towing gland 166 to
assist the pull of the coiled tubing.
[0234] In open loop production mode cleaning (FIG. 16b), a single
VARRIS hydraulic power supply tubing 19 is utilised to power the
turbine and provide traction for the tool. The turbine exhaust is
commingled with the boosted flow and returns to the surface via
annulus 105.
[0235] In shutdown mode using annular cutting fluid flow (FIG.
16c), the transport fluid 175 for the cuttings 172 is pumped down
annulus 105 to the pump inlet where it picks up the cuttings and is
boosted in the pump to commingle with the turbine exhaust and
thence to the surface via the VARRIS power supply tubing 19. In
this embodiment, traction is provided solely by the cutter or with
thrust assistance from the power supply tubing 19. Therefore, the
cutter has to be designed such that its rotating cutter blades
produce sufficient traction as required.
[0236] FIG. 16d shows schematically an embodiment using shutdown
mode co-axial tubing cutting fluid flow. In this mode, excess
turbine drive fluid is provided. As shown in the Figure, the excess
is bled off (at 134) into the vicinity of the cuttings and,
provides the fluid transportation system for the chipping via
annulus 105 to the surface. As in FIG. 16c, the movement within the
flowline/riser is provided by the thrust/pull forces applied by the
cutter brush module and VARRIS power supply tubing. In this
embodiment, moreover, no pumping section is provided, so that the
turbine 113b drives the cutter 171 directly.
[0237] In the embodiments according to FIGS. 16a and 16b (as in the
preceding embodiments having sliding seals) the sliding seal does
not have to provide complete sealing with the inner surface of the
riser wall. Rather, some leakage is permissible and even desirable
so as to minimise sliding friction.
[0238] Furthermore, the pipe will usually be a rigid pipe drawn
from a coil on a drum, using a pipe straightener and tensioner to
deploy straightened pipe. However, it could be a flexible pipe
where a sufficient differential pressure can be generated by the
tool itself.
[0239] Although the boost/lift pump in FIGS. 16a-c is a hydraulic
pump, it could instead be an electric pump.
[0240] It is also possible to use the described systems for
adjusting the position of the pump, heater or gas injector within
the riser. For example, if the component in question is to be moved
to a position nearer the top of the riser, it would be retrieved
completely from the riser, disconnected from the pipe, an
appropriate length of pipe cut off the end, and the component
re-connected and re-deployed down the riser in the new position.
If, alternatively, the component is to be lowered, then it would be
withdrawn from the riser, disconnected from the pipe, an additional
length of pipe attached to the end of the main pipe, the component
reattached and then driven back down into the riser to the final,
required position.
[0241] It will be appreciated that the described embodiments all
take advantage of existing developed technology for dispensing
(laying) rigid pipes, by using at least one rigid pipe to carry a
pump, heater, gas injector, cutter or other equipment and deploy it
at a desired position within the riser by driving the or each pipe
downwardly into the riser. Furthermore, since the top end support
for the riser, which can be an attendant service vessel or a
submerged buoyancy unit, is positioned at or in the vicinity of the
sea surface, the pump, heater, gas injector or cutter can be
retrieved to the top end support, where it is readily accessible to
crew members from overhead, for replacement or maintenance
purposes.
[0242] The attendant vessel may itself include a production tower
for producing hydrocarbon fluid from a well supplying the flowline
leading to the riser. It is also possible for the top end support
to be a drilling platform anchored on the sea bed.
[0243] In the Figures, individual items are provided with reference
numerals according to the following Table:
1 1 flowline 2 sea bed/mud line 3 homogeniser (optional) 4 riser 5
sea surface 6 support vessel 7 powered drum 8 pipe
lubricator/injector (Lubrication element optional) 9 crane 10
packer 10a seal 11 HSP 11' ESP 11.sub.1 inlet for HSP 11.sub.2
outlet for HSP 11.sub.3 hydraulic fluid inlet 11.sub.4 hydraulic
fluid outlet 12 supply pipe 12a supply pipe 13 return pipe 13a
return pipe 14 pump 15 heater 16 power suppfy cable 18 heater 19
coiled pipe 20 buoyancy unit 21 riser base 22 take-off
hose/flexible hose 23 gooseneck pipe 24 maintenance stack 25 Y
junction 26 preventer valve 27 preventer valve 28 Y junction 29
coaxial stub 30 heater 31 electric pump 32 electric pump 33
switchgear 34 power supply line 35 power connector 36
injector/poker 40 valve (on-of) 41 valve (on-off) 42 valve (on-off)
43 hose/hydraulic fluid 44 connecting line 45 isolator/hydraulic
pipe 46 connecting line 47 isolator/hydraulic pipe 49 auxiliary
pipe 50 pressure cap 100 inflation line/umbilical 101 product in
the flowline 103 outer tubing 105 annulus between the
riser/flowline and the tubing 107 transition zone 108 separation
zone 109 perforated tubing section 111 the upperannulus 112 gas
outlet 113a pumping unit 113b drive turbine 113c flexible coupling
114 annulus between outer tubing and inner tubing 115 power supply
tubing 115a power return tubing 116 pump entry point 117 pump
exhaust 118 fluid return tubing 119 annulus between the inner
tubing and the pump power supply tubing 115 120 tubing hanger 121
separated liquid exit 122 tubing head 123 Cyclone insert 124 tubing
head 125 biased check valve (permits limited leakage) 126 riser
evacuation port 128 main production valve 129 gas inlet valve 130
drive fluid exhaust valve 131 drive fluid inlet valve 132 pump
located riser evacuation valve 133 annulus bypass valve 134 drive
fluid bleed off 135 pipe straightener 141 composite riser 142 riser
end termination 143 riser base/manifold spool 144 spacers
(optional) 156 subsea manifold processing centre/junction 157
subsea well 158 tractor unit 160 derrick 161 coiled tubing drum
integral supply couplings 162 removeable power fluid hose 163
tensioner unit 164 electrical umbilical 166 towing gland 171 cutter
brush module 173 gearbox 175 transport fluid 176 check valve
* * * * *