Note: Descriptions are shown in the official language in which they were submitted.
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RISER WITH RETRIEVABLE INTERNAL SERVICES
This invention relates to riser systems and methods for raising production
fluid
within the riser system downstream ofia subsea source or plurality of sources.
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 US-A-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.
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 m.ay reach a point at which it alone is
insufficient. In some cases, the pressure at the riser base may be inadequate
from the outset.
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
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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 velocifiies 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.
To address fihese 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 ofi 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.
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 wifih trained crew
has to
be called, which travels to the offshore site. Then the crew have to repair or
replace fihe 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
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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.
US-A-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.
US A-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.
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 colurrin. 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.
The active methods require the continuous availability of chemicals and/or
heat.
Use of low heat loss insulation extends cool down fiime, but on its own is not
a
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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.
In convenfiional riser systems, transportation of multiphase fluids from a
wellhead
via a filowline arid 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
afi
the destination facility can remove these risks and permit a less complex
processing system. ,.
To' date, subsea systems aimed of 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/mainfienance. 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
fihis
equipment.
US A-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.
It is also known from US-A-4,336,415 to employ composite flexible coiled
tubing to
convey electrical and/or hydraulic power to a drive motor for a downhole pump.
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US-A-5,503,014 describes a system using coaxial coiled tubing to supply fluids
to
a wellbore for performing a drill stem test.
US-A-5,638,904 describes a type of nested coiled tubing in which the
individual
pipes adopt a helical configuration.
In fihis 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.
According to a first aspect of fihe 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 remofie 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 may be a pump, a heater, a gas injector, or a cutting or
cleaning tool. These aspects will be discussed in more detail hereinafter.
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
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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.
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, fio 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.
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 remofie storage facility.
. 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.
As already mentioned, the operating device may be a pump for pumping
production fluid from the source.
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 fihe pipe is used to accommodate the power supply cable. This
contributes to a compacfi construction for the riser.
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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,
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.
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 fihe
hydraulic
pump to said first position and to wind in the nested pipes to raise the pump
to
said second position.
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
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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, ifi 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.
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.
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 posifiion to
another
one is also available to provide scraping/cleaning of the riser wall.
tn 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.
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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 ifs 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.
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 fio
raise the heater to said second position.
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
fihe riser.
The system may further comprise means for displacing the gas injector in the
riser
between the operating and access positions.
The gas injector displacing means may include a rigid supply pipe extending
downwardly within the riser and carrying said gas injector.
The rigid supply pipe may itself carry the pressure gas or it may carry a
separate
gas delivery pipe.
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
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separate gas supply line used for injecting lift gas into the riser for use
with a gas
injector.
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 wifihin 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.
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 fhe
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.
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
info 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.
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.
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J
It will be appreciated that a hydraulic pump can, more readily cope with sharp
bends inside the riser without jamming than an electric pump.
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 filuid 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.
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 fiirst passageway to said region of
lower
pressure. This is one convenient way of achieving the required pressurised gas
introduction and subsequent pressure reduction.
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.
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
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included in the hydrocarbon fluid rich underflow is held in solution by the
time that
the hydrocarbon fluid enters the pump.
In a modification, said hydraulic pump comprises a pump section, turbine
section
and an articulated. or flexible coupling section to fihe packer or drive
mandrel.
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 fihe riser.
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.
A universal drive coupling is a convenient form of element for maintaining
drive as
the pump and turbine sections articulate relative to one another.
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.
Due to the provision of the coupling section, the hydraulic pump can be passed
fihrough a riser having relatively sharp bends, such as the mentioned lazy-S,
steepwave and steep-S configuration.
In some embodiments, the riser has a substantially vertical compliant section,
leading from the sea bed to the surtace, 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 finking between fihe
turbine
and pump sections enables the pump to be advanced around the approximately
90° bend section where the radius of curvature is small, connecting the
vertical
riser section and horizontal flowline section of the riser.
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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.
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
firaction in either axial direction of the riser.
(n 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.
The down-riser pump together with its sealing device serves not only to
provide
down-riser pumping buff also to generate fihe required traction force for
driving the
pump through the riser or flowline.
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
mofior is
mounted, which is a convenient manner of powering the motor with ready access
to the powering means at the riser upper end.
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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.
The difFerential pressure acts on the motor to create a force acting on it to
drive it
along the riser.
Alternatively, the rotary cleaning device is arranged tv 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 fio
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.
A rotary cutfier 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.
Corresponding to the system according to the first aspect of the invention are
methods of installing a riser operating device.
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
producfiion fluid on the seabed to a top end support supporting the riser at
or in the
vicinity of the sea surface, comprising:-
- introducing the device into the riser at the upper end thereof; and
- driving the device downwardly into the riser to a desired operating
position in the riser remote from its end at the top end support.
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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.
According to a method of maintaining or replacing an operating device
installed in
accordance with the present method, the following steps are carried out:-
- driving the pipe upwardly to raise the device within the riser to fihe
top end support;
removing the device from the riser; and
- disconnecting the device from the pipe, for maintenance or
replacement.
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
injecfior is retrieved from the riser through ifis 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.
In a further development, the method comprises at least partially expelling
the
production filuid from the riser interior, sows 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.
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.
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A pump is a simple and effective device for achieving the required expulsion
of
production fluid from the riser.
According to an alternative method, gas is introduced under pressure into the
riser
to at least partially expel the production fluid and fihe 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. w
A hydrate formation inhibitor may be introduced along with the gas. The
inhibitor
serves to augment the inhibition of solid hydrate formation.
It should be noted that where the term "rigid" is used in this specification
to
descr°ik~e the nature of the pipe (or pi~e~) rJepioyed vuithiri the
Miser, 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.
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17
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 exte~hsion (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 on site.
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.
For a better understanding of the invention and to show how the same may be
carried into effect, reference will now be ri~ade, by way of example, to the
accompanying drawings, in which:-
Figure 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;
Figure 2 is a more detailed side view of the riser of the system;
Figures 2a and 2b show respective modifications;
Figure 3 is a schematic view of a. second embodiment;
Figure 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;
Figure 4a is a side view of the buoyancy unit and maintenance stack of the
system
shown in Figure 4;
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18
Figure 4b shows a piggable wye junction which can be used for pigging the
system or for providing a radius suitable for pump insertion;
Figure 5 is a schematic view of a third embodiment, differing in certain
respects
from that according to Figures 1 and 2;
Figure 6 shows the arrangement in more detail;
Figure 7 is a schematic side elevation of a fourth embodiment resembling that
shown in Figure 4 but differing in certain details;
Figures 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
displacemerit;
Figure 11 a shows a schematic side elevation of a sixth embodiment of the
invention for use in slug suppression or separation;
Figures 11 b and 11 c are cross-sectional views along the planes 11 b-11 b and
11 c-
11c of Figure 11a;
Figure 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;
Figure 12a is a partial schematic sectional view through the wall of a riser
having a
coiled spiral inner construction;
Figures 12b, 12c and 12d show schematic side elevational views of various
riser
configurations;
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19
Figure 13 is a schematic side elevational view of a system according to the
invention for providing. pressure boosting or arfiificial !ift from one or
more subsea
well in a rigid or compliant riser;
Figure 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;
Figure 14b is a schematic side elevational view of a part of the system of
Figure
14a at an enlarged scale;
Figure 14c is a schematic side elevational view of a part of the system of
Figure
14a showing a modification using a derrick system for tubing deployment;
Figure 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;
Figure 15b is a schematic side elevational view of a part of the system of
Figure
15a at an enlarged scale; ' -
Figure 15c is a schematic side elevational view of a part of the system of
Figure
15a showing a modification using a derrick system for tubing deployment;
Figure 16a shows a closed loop production mode cleaning apparatus for cleaning
the inside of a riser;
Figure 16b shows an open loop production mode cleaning apparatus for cleaning
the inside of a riser;
Figure 16c shows the use of shutdown mode annular fluid flow for driving a
cutter
for cleaning the inside of a riser; and .,
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Figure 16d shows the use of shutdown mode coaxial fluid flow for driving a
cutter
for cleaning the inside of a riser.
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
fihan 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.
While VARR1S was developed for deepwater installations it is equally valid for
shallow applications.
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.
Further applications of VARRIS cover the following areas:
1. Using VARRIS as a slug suppressor/separator (Fig. 11 );
2. , Using VARRiS to evacuafie the riser/flowline (Figures 9 to 10);
3. Using VARRIS in existing risers (shallow or deepwater, rigid or flexible)
for
pressure boosting/provision of artificial lift (Figures 12a to 12d and 13);
4. Assistance in deployment/retrieval of the internal services towards/from
the
subsea production facilifiy (manifolded production system or an individual
well)
along the seabed flowline section using a mechanical self driven tractor
(Figures
14a, 14b and 14c), or using self drive by generation of an axial differential
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21
pressure and driving force across the end remote from the riser entry point at
the
top (Figures 15a, 15b and 15c); and . a
5. As for 3 but using a pig to assist in deployment/retrieval of the internal
services (Figures 16a to 16d).
Referring to Figures 1 and 2, there is shown a first embodimenfi 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 fihe~ mudline to
the sea
surface 5, where the flowline is supported by a floating support vessel 6. If
necessary or desired, as shown in Figure 1, the flowline may optionally be
provided with a homogenises 3 for homogenising the three-phase production
fluid
generally consisting essentially of crude oil, natural gas and water, and
suitable
valuing, 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 homogenises 3. '
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 relafiively 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 < 100m, for example.
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
fihe
powered drum 7, and also a tensioner for assisting in drawing the pipe from
the
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22
drum and forcing it through the straightener. One suitable form of pipe
delivery
and retrieving apparatus is disclosed in US-A-3,982,402.
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 aurface 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.
Figure 1 also shows a pump 14 and an optional heater 15, whose purposes are
described below.
Figure 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~ for
receiving production fluid in the flowline to be pumped, and a pumped
production
fluid outlefi 112 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
to the fluid entry point. The pump also has a hydraulic fluid inlet 113 and a
hydraulic fluid outlet 114 or 11'4. The packer 10 is sealed to the riser wall,
by
means of an inflatable seal 10a of the packer 10, shown diagrammatically in
Figure 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
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w 23
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 fihe inflatable seal
1 Oa.
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.
The length of rigid pipe 19 extending dawnwardly through the lubricator 8
(Figure
1 ) and along the length of fihe riser is preferably a nested arrangemenfi of
hydraulic
supply and return pipes 12, 13. The pipe 19 may preferably have a construction
such as shown in US-A-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 113, thereby driving the pump 11 to increase the pressure
of the
production fluid entering the pump through inlet 11 ~ and drive it from pumped
fluid
outlet 11~ up through the riser 4 to the support vessel 6. The hydraulic fluid
outlet
114 can be connected directly to the return hydraulic pipe 13, buff 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
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24
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 1'3, 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 wauld 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.
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 fihe 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 fianker 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 fiowline 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.
The coaxial pipes 72, 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 wail, under which condition the
packer
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.
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The installation of the flowline 1, deployment of the riser 4 from the
supportvessel
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 ifis 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
lengfih 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 fihe
riser 4, thereby locking it in position within the riser 4.
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 re-connected to the pipe delivering and retrieving apparatus, far
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
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26
from the lubricafior 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. '
Figure 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 112 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.
In another modification shown in Figure 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 Figure 2a, it will be appreciated that in a practical
embodiment it will be much longer, tf 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.
Referring to Figure 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 elemenfi 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
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27
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.
As shown in Figure 4, when provided, 'the homogeniser 3 is located in the
riser
base 21. The production fluids in flowline 1 leave the homogenises 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 Figure 2.
The manner in which the riser base 21, riser buoyancy unit 20 and flexible
hose 22
are installed is conventional in itself and therefore wit( 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, fihe
mainfienance 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 fihe stack 24
from
above, through the lubricator 8, blowout preventer valves 26, 27 and emerges
through fihe 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 fio seal with the riser wall.
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28
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. Figure 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 Figure 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.
As shown in Figure 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.
Retrieval of the HSP 11 back to the vessel 6 for maintenance or replacement is
essentially a reversal of the above steps, just as in the preceding
embodiments.
Therefore, no description is given of this retrieval procedure.
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29
As shown in Figure 4b, if the riser 4 into be piggabie, the wye junction 25
can be
replaced by a wye junction 28 fiurned 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 to its operating position.
The system of Figures 4, 4a and 4b for raising hydrocarbon fluid can be
modified
in accordance with the modifications according to Figures 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.
In the preceding embodiments, the down-riser pump, whether hydraulic or
electric,
is mounted inside the riser. However, in the modification of Figures 5 and 6
to the
system according to Figures 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 37
, 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 fihe
sea. If
one fails, the other can be brought into service using the swifichgear 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 fihe 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
CA 02404881 2002-09-25
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may be used hydraulic pumps. Furthermore, if the production fluid pressure in
flowline 1 is large enough, the external pumps are not required.
In .accordance with another embodiment shown in Figure 7, the single pipe 12
such as included in Figure 2b or in the Figure 4 embodiment as modified in
Figure
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. Figure 7
shows a
system with buoyancy unifi 20 similar to that shown in Figure 4. In Figure 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.
In the embodiments of Figures 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 sea( with it.
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 thafi 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 9mm thick), as more of the pipe length is deployed down.the riser the
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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.
It is also menfiioned that a standard lubricator also generally has drive
tracks which
assist the deployment of the pipe length.
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 fihat 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.
Reference is now made to further embodiments according to Figures 8 to 11, 11a
to 11 c, 12 and 12a to 12d, 13 to 15 and 16a to 16d. These embodiments bear
similarities in a number of respects to fihe preceding embodiments, and where
possible corresponding reference numerals are used. Accordingly, the following
description is confined mainly to differences in construction or operation. '
.
Reference is now 'made to Figures 8 to 10 for a description of using VARRIS as
a
means of evacuating fihe riser/flowline by gas displacement or combined
gas/methanol displacement, or by action of the pump.
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
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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 hydrafie 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
requiremenfi
for external intervention as in conventional techniques.
In the embodiments to be described with 'reference to Figures 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 Figures 8 to 10, the coiled tubing 19 comprises an outer tube 118 and
an
inner coaxial tube 115.
Figure 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 ifs flowline section
downstream of the VARRIS barrier provided by the pump 11, or packer 90, 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
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providing a pressure in the flowline 1 immediately upstream of the packer 10
equal
to the gas pressure in the riser annulus 105.
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.
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.
Evacuation is continued until the fluid level in the riser annulus 105 has
reached a
predefined level.
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
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hydrocarbon production fluid ~in annulus 1057 and the relatively low pressure
achieved in this annulus, hydrate formation in the riser during production
infierruption can be avoided.
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.
An open-loop variant is shown in Figure 9. The principal difference from the
closed loop variant of Figure 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.
In the no flow condition the system settles down such that there is negligible
differential pressure across check valve 125.
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 7 05 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.
Evacuation is confiinued 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
'!
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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.
Figure 10 shows the use of VARRIS as a means of evacuating the riser flowline
by
use of pump 11.
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
valuing 132, 133 within the pump 11 to drain the riser 4 and utilising the
power
fluid exhaust route 11'4.
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.
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 valuing within the pump to cause
evacuation
of riser 4.
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Evacuation continues until a predetermined volume of fluid has been retrieved,
at
which point either circulation continues to flush the VARRIS inner and outer
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.
Figure 11 a relates to VARRIS as a slug suppresser/separator.
Instead of using external slug suppression/separation equipment, the
embodiment
of Figure 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. '
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.
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
fiowards 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.
Referring to Figure 11 a, 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.
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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
7 03. 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 re=setting the relative positions of
the middle
tubing 118 and fihe middle tubing hanger 120.
Reference is now made to Figures 11 b and 11 c, which are horizontal
secfiional
views taken along the lines 7 7 b-71 b and 71 c-11 c respectively in Figure 11
a. As
shown in Figure 11 c, positioned inside the perforated tubing 109 is a cyclone
insert 123, defining substantially tangential inlet passages 7231 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 fio rise in
the
separation zone 108 and leave as overflow. Other constructions, well known her
se, for creating cyclonic separation can be used instead of the specifically
described arrangement. '
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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.
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.
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.
The pump drive may be either hydraulic (HSP) or electrical (ESP). !n 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.
As shown, the apparatus incorporates measures, similar to that disclosed with
reference to Figures 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
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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.
Therefore, the separation device according to Figures 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.
The device may be able either in part or in its entirety to enable maintenance
or
reconfiguration of the separation elements.
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.
In conventional systems, successive slugs of gas and liquid in transition zone
107
are brought to the upper end of the riser and separafied by a slug catcher,
followed
by multi-stage separation. The integral slug suppressor separator included in
the
riser system according to Figures 11 a to 11 c 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.
!t will be appreciafied 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
CA 02404881 2002-09-25
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4 0 .>
. solution right up to the surface. It also has the further funcfiion. of
assisting in
inhibiting solid hydrate formation, as described above.
Figure 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.
Some risers are of coiled spiral inner construction, with an outer reinforced
casing,
or other similar form (see Figure 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 Figure 12 is designed to overcome this problem.
Figure 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.
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/man~fold 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 Figures 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 Figures 8 to 10.
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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.
It will be appreciated thafi 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.
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.
Evacuation of the riser annulus uses the same techniques as described with
reference to Figures 8 to 10 above.
The above system is also applicable to various riser configurations, e.g. the
so-
calied lazy-S (Figure 12b), steep wave, (Figure 12c) and steep S (Figure 12d)
configurations.
It will be appreciated therefore that this embodiment finds particular
application to
shallow water applications.
Referring now to Figure 13, there is shown a system for boosting or providing
artificial lift from at least one subsea we(I or at least one subsea field in
a rigid or
compliant riser suspended from a fixed platform shown schematically at 151.
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
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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 fine and heater can be used as in embodiments such as according to
Figure 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.
Reference wiN now be made to Figures 14 and 15,. which show embodiments
capable of transporting VARRIS equipment to/from a location remote from the
top
insertion point on a riser.
In general, to position permanent components axially along a riser/flowline,
motive
force can be provided by:-
1. gravity acting on the vertical elements of a deploymenfi string;
2. a pushing force applied at the riser entry point of the deployment string
(according to VARRIS);
3. flow within the riser/flowline driving a towing pig;
4, an electrically driven tractor unit; or
5, combinafiions of these methods.
1l. & 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 flowing 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
bofitom of the riser section, where there is a relatively sharp bend section
connecting the riser section and flowline.
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Figure 14 is a fiirst 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.
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
valuing within the tractor is used to set the packer that locates the VARRlS
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.
To retrieve the pump, pressure set valuing 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.
A specific implementation of this method will be described below with
reference to
Figures 14a, 14b and 14c.
A second technique to be described with reference to Figures 15a, 15b and 15c
uses the principle of the VARRIS pump which provides self drive along a
flowline.
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
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valuing wifihin 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.
Reference is now made to a specific implementation of the first method shown
in
Figures 14a, 14b and 14c, where the installation distance from the riser base
exceeds the ability of the coiled tubing deployment drum 7, ar derrick sysfiem
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.
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 inflafiable 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
fronfi
telescopic part exfiended 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.
0.n 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
fihe
system follows disengagement of the packer 10, and application of fiension to
the
VARRIS tubing 19 via the dispensing drum 7 located at the tubing head 122.
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A preferred method of operafiion 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.
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 info the product in
the
flowline 1), or closed loop (power fluid exhaust and returned to surtace via
coaxial
return line).
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.
The VARRIS power supply tubing 19 may be deployed from a coiled tubing drum 7
(Figure 14a), or derrick 160 (Figure 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
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46
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.
An example of the second method referred to above will now be described (see
Figures 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.
The method of operation for a closed loop option according to Figures 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.
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.
The method of operation for an open loop option will be described. This option
is
the same as shown in Figures 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
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47
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 pumpvcasing 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.
Another application of VARRIS is to the removal of scale/wax.
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 selfi
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.
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 fihose of the embodiment of Figure 15a above, the cutter which
is
forward of the pump is driven by a common shaf~/reducfiion unit. As above a
differential pressure is achieved across the tool which provides motive force
to pull
the cutters along the flowline. Cutting retrieval may be achieved by a variety
of
methods:-
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4~
1. Where there is no flow in the fiowline 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;
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 surfiace via the closed loop return line;
3. Where there is an open loop return, the cuttings are driven back to the
surface using the power fluid discharge; and
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.
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.
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 Figures 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
wail and a
small percentage of leakage or forward flow reflux from the discharge of the
pump
back tv 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
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49
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 info the vicinity of the cutters 171, ~ and thence returned to
the
surface via the annulus 1p5., 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.
Various embodiments will now be described.
A closed loop production mode cleaning.apparatus is shown in Figure 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
rofiating 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.
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 surtace via annulus 105.
On the refiurn 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.
In open loop production mode cleaning (Figure 16b), a single VARRIS hydraulic
power supply tubing 19 is utilised to power the fiurbine and provide traction
for the
tool. The turbine exhaust is commingled with the boosfied flow and returns to
the
surface via annulus 105.
In shutdown mode using annular cutting fluid flow (Figure 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
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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 cufiter blades produce sufficient traction as required.
Figure 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 fihe
cuttings
and provides the fluid transportation system for the chipping via annulus 105
to the
surface. As in Figure 16c, the movement within the flowline/riser is provided
by
the thrusfi/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.
In the embodiments according to Figures 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.
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.
Although the boost/lift pump in Figures 16a-c is a hydraulic pump, it could
instead
be an electric pump. . ., .
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 fihe 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. (f, alternatively, the component is to be
lowered, then it would be withdrawn from the riser, disconnected from the
pipe, an
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51
additional length of pipe attached to the end of the main pipe, the component
re-
attached and then driven back down into the riser to the final, required
position.
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.
The attendant vessel may itself include a producfiion 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.
In the Figures, individual items are provided with reference numerals
according to
the following Table:
1 ~ flowline
2 sea bed/mud line
3 homogeniser (optional)
4 riser
sea surFace
6 support vessel
7 powered drum
8 pipe lubricator/injector (lubrication element optional)
9 crane
packer
10a seal
11 HSP
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11' ESP ~ .
11 ~ inlet for HSP
11Z outlet for HSP
113 hydraulic fluid inlet
114 hydraulic fluid outlet
12 supply pipe
12a supply pipe
13 return pipe
7 3a return pipe .
14 pump
15 heater
16 power supply 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-ofd
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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
48 hose
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 upper annulus
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
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122 tubing head
123 Cyclone insert
724 tubing head
125 biased check valve (permits limited leakage)
126 riser evacuation port
128 main production valve
129 gas inlet valve
130 drive fluid exhausf 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)
151 platform static hang off
152 rigid riser clamps
153 riser base bend
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
172 cuttings
173 gearbox
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175 transport fluid
176 check valve
