U.S. patent application number 10/492137 was filed with the patent office on 2005-04-07 for system and method for injecting gas into a hydrocarbon reservoir.
Invention is credited to Andrews, Nicholas John Abbott, Appleford, David Eric, Lane, Brian William.
Application Number | 20050072574 10/492137 |
Document ID | / |
Family ID | 9923770 |
Filed Date | 2005-04-07 |
United States Patent
Application |
20050072574 |
Kind Code |
A1 |
Appleford, David Eric ; et
al. |
April 7, 2005 |
System and method for injecting gas into a hydrocarbon
reservoir
Abstract
Gas is supplied from a host facility (2) to an underwater gas
compressor (10) via a connecting pipeline (6) and the gas
compressor is connected to a plurality of gas injection wells (7)
for a hydrocarbon reservoir via well supply flowlines (8). The gas
compressor (10) compresses the supplied gas to a higher pressure,
and drives the gas into the reservoir via the flowlines (8) and gas
injection wells (7) at a pressure at least as high as the pressure
of the production fluid in the reservoir. This raises the overall
pressure in the reservoir to drive production fluid there to the
host facility (2). The compressed gas may alternatively be injected
into production fluid in a production well to provide a gas lift
effect.
Inventors: |
Appleford, David Eric;
(Theydon Bois Epping Essex, GB) ; Lane, Brian
William; (Canvey Island Essex, GB) ; Andrews,
Nicholas John Abbott; (Essex, GB) |
Correspondence
Address: |
Summa & Allan
11610 North Community House Road
Suite 200
Charlotte
NC
28277
US
|
Family ID: |
9923770 |
Appl. No.: |
10/492137 |
Filed: |
April 7, 2004 |
PCT Filed: |
October 11, 2002 |
PCT NO: |
PCT/GB02/04635 |
Current U.S.
Class: |
166/366 ;
166/305.1; 166/357; 166/90.1 |
Current CPC
Class: |
E21B 43/122 20130101;
E21B 43/18 20130101; E21B 43/017 20130101; E21B 43/40 20130101 |
Class at
Publication: |
166/366 ;
166/357; 166/305.1; 166/090.1 |
International
Class: |
E21B 043/01 |
Foreign Application Data
Date |
Code |
Application Number |
Oct 12, 2001 |
GB |
0124609.9 |
Claims
1. A system for injecting gas into a hydrocarbon reservoir,
comprising: a host facility (2) having gas supply means (3,4); an
underwater gas compressor (10) remote from the host facility, and
connected to the gas supply means by a pipeline (6); and at least
one well (7) connected to the underwater gas compressor (10),
whereby the gas compressor is arranged to supply the gas received
from the pipeline (6) to the or each well (7) and into the
hydrocarbon reservoir to improve conveyance of production fluid at
least towards the host facility (2).
2. A system as claimed in claim 1, wherein at least one said well
(7) is an injection well, the gas compressor (10) being arranged to
drive gas into the hydrocarbon reservoir via the or each injection
well (7) at a pressure at least as high as the pressure of the
production fluid in the reservoir to raise the overall pressure in
the reservoir.
3. A system as claimed in claim 1, wherein at least one said well
is a production well (25), the gas compressor (10) being connected
to inject gas into production fluid in the or each production
well.
4. A system as claimed in claim 1, wherein the gas compressor (10)
is connected to the at least one well (7) by at least one flowline
(8) which is able to withstand conveyed gas of a higher pressure
than the pipeline (6) between the host facility (2) and the gas
compressor (10).
5. A system as claimed in claim 1, wherein the underwater gas
compressor comprises a high pressure gas compressor (10) and the
host facility (2) has at least one lower pressure gas compressor
(4) for driving gas to the high pressure gas compressor (10).
6. A system as claimed in claim 1, wherein the underwater gas
compressor (10) is located at an underwater facility (5).
7. A system as claimed in claim 6, wherein the underwater facility
(15) includes fluid separating means (19) for separating gas from
the production fluid and recirculation means (22) for conveying gas
from the fluid separating means (19) into the gas compressor
(10).
8. A system as claimed in claim 6, wherein the underwater facility
(15) is on a seabed, and the system includes a production fluid
pipeline (24) for conveying production fluid from the underwater
facility (15) to the host facility (36), the production fluid
pipeline (24) including a production riser (37) from the seabed to
the host facility (36), and the host facility is connected to the
production riser (37) at or close to the seabed by a separate riser
(39).
9. A system as claimed in claim 6, wherein the underwater facility
(25) includes a retrievable module (27) which incorporates the gas
compressor (10).
10. A system as claimed in claim 1 including a power and control
umbilical (13) extending from the host facility (2) to the
underwater gas compressor (10) for conveying power and control
signals to the gas compressor.
11. A system as claimed in claim 10, wherein the power and control
umbilical (13) is arranged to convey power and control signals
required for other underwater equipment.
12. A method for injecting gas into a hydrocarbon reservoir,
comprising the steps of: supplying gas from a host facility (2) to
an underwater gas compressor (10) via a connecting pipeline (6);
compressing the gas received by the underwater gas compressor (10)
to a higher pressure; and injecting the compressed gas into at
least one well (7) connected to the underwater gas compressor (10),
and into the hydrocarbon reservoir to improve conveyance of
production fluid at least towards the host facility (2).
13. A method as claimed in claim 12, wherein the step of injecting
gas includes injecting gas into at least one injection well (7),
the gas being driven into the hydrocarbon reservoir via the or each
injection well at a pressure at least as high as the pressure of
the production fluid in the reservoir.
14. A method as claimed in claim 12, wherein the step of injecting
gas includes injecting gas into at least one production well (25),
the gas being injected into production fluid in the or each
production well (25).
15. A method as claimed in claim 12, including separating gas from
the production fluid at an underwater facility (15) including the
underwater gas compressor (10).
16. A method as claimed in claim 15, including conveying at least
some of the separated gas into the gas compressor (10).
17. A method as claimed in claim 15, including disposing of at
least some of the gas separated from the production fluid into at
least one cavity (43) below the surface of the ground underneath
the water in which the gas compressor (10) is located.
18. A method as claimed in any one of claims 12, including the
steps of receiving production fluid at the host facility (36) via a
production riser (37) from a seabed, and injecting gas from the
host facility (36) into the production riser (37) at or close to
the seabed.
19. A method for handling production fluid, comprising the steps
of: receiving production fluid in an underwater facility (15) from
a hydrocarbon reservoir; separating gas from the production fluid
in the underwater facility (15); and disposing of the gas into at
least one cavity (43) below the surface of the ground underneath
the water in which the underwater facility (15) is located.
Description
[0001] The present invention relates to a system and method for
injecting gas into a hydrocarbon reservoir.
[0002] In a developed field, production fluid, extracted from the
hydrocarbon reservoir by production wells, is driven to a host
facility by the natural pressure of the reservoir. However, where
the reservoir does not have enough natural pressure to drive the
production fluid to the host facility which may be due to the
production fluid comprising heavy, high density fluid that is
essentially oil, a means of increasing the reservoir pressure or
decreasing the specific gravity of the fluid is required.
[0003] In some cases the means may inject water from the host
facility into the reservoir to boost its pressure.
[0004] In other cases the means may inject gas into the reservoir
to boost its pressure via injection wells separate from the
production wells. A known system for injecting gas into a reservoir
comprises connecting the host facility to a seabed facility with a
high pressure pipeline, and at the seabed facility, manifolding the
pipeline into separate flowlines connected to injection wells. The
gas for injection is processed at the host facility to a
predetermined specification to make it suitable for compression and
high pressure transportation. This processing may comprise drying
the gas. The gas is then compressed by at least one gas compressor
at the host facility and is conveyed by the high pressure pipeline
down to the seabed facility and on into the reservoir via the well
flowlines and the injection wells. The gas for injection is
compressed to a pressure at least as high as that of the pressure
of the reservoir at the bottom of the wellbores of the injection
wells after taking into account the pressure losses incurred in the
pipeline and flowlines so that it is able to drive production fluid
from the reservoir up to the production wells and on to the host
facility.
[0005] Alternatively, the gas pumped from the host facility may be
used for a process known as "gas lift" in which gas is injected
into production wells. The wellbore of each production well has
riser tubing surrounded by an outer casing, the spacing between the
tubing and the outer casing being known as the annulus. Gas is
injected into the annulus and enters the tubing via perforations
spaced along the length of the tubing and the gas combines with the
heavy production fluid in the tubing to produce a less dense fluid.
This enables the fluid to be lifted to the host facility by the
well pressure. The gas used may be hydrocarbon gas which may be
from the field being developed or from a nearby or separate field
and any other suitable gas may be used.
[0006] The pipeline and flowlines for both gas injection and gas
lift which are required to convey the gas to the wells have to have
pipe walls thick enough to withstand the high pressure of the gas.
The cost of the pipeline itself and the installation costs are
high. This is particularly so when there is a long tie-back.
[0007] It is therefore an object of the present invention to
provide a system and method which overcomes at least some of the
above-mentioned disadvantages of the prior art.
[0008] According to one aspect of the present invention there is
provided a system for injecting gas into a hydrocarbon reservoir,
comprising:
[0009] a host facility having gas supply means;
[0010] an underwater gas compressor remote from the host facility,
and connected to the gas supply means by a pipeline; and
[0011] at least one well connected to the underwater gas
compressor, whereby the gas compressor is arranged to supply the
gas received from the pipeline to the or each well and into the
hydrocarbon reservoir to improve conveyance of production fluid at
least towards the host facility.
[0012] At least one said well may be an injection well, the gas
compressor being arranged to drive gas into the hydrocarbon
reservoir via the or each injection well at a pressure at least as
high as the pressure of the production fluid in the reservoir to
raise the overall pressure in the reservoir.
[0013] At least one said well may be a production well, the gas
compressor being connected to inject gas into production fluid in
the or each production well, and the production well is considered
to be part of the hydrocarbon reservoir.
[0014] The gas compressor may be connected to the at least one well
by at least one flowline which is able to withstand conveyed gas of
a higher pressure than the pipeline between the host facility and
the gas compressor.
[0015] The gas compressor is preferably located at an underwater
facility such as a seabed facility. By locating the gas compressor
on the underwater facility, a pipeline able to convey gas at a high
pressure is not required between the host facility and the
underwater facility, as gas from the host facility is only at a
high pressure once it has been compressed by the gas compressor of
the underwater facility. Hence, the pipeline between the host
facility and the underwater facility may have its pipe wall
thickness reduced as it does not need to convey gas at such a high
pressure. As there is a reduction in the quantity of pipe material
for this pipeline, there is a significant cost saving.
[0016] The host facility would preferably have at least one lower
pressure gas compressor for driving gas to the high pressure gas
compressor at the underwater facility. By conveying the gas for
injection at a lower pressure to the underwater facility, the
pressure losses due to friction in the pipeline are reduced.
[0017] Consequently, less power is required to compress the gas for
injection, enabling gas compressors and their drive motors (which
are preferably electric motors) at both the host facility and the
underwater facility to be of a lower/smaller specification. This is
likely to provide a cost saving when compared with having a high
pressure gas compressor and its associated drive motor at the host
facility. There is a further cost saving as the gas compressors at
the host facility and underwater facility require less energy to
drive them. The reduction in the size of the gas compressor and its
associated drive motor at the host facility provides a saving in
deck space on the host facility and in the weight to be supported
by the host facility.
[0018] The reduction in pipe wall thickness enables the sections of
the pipe for making up the pipeline to the underwater facility to
be welded together more easily and quickly which considerably
reduces fabrication costs. Furthermore, the reduction in pipe wall
thickness may enable the pipeline to be reeled onto a drum and be
laid from a pipe reel-lay barge which is a faster method of
installing a pipeline than other conventional methods.
[0019] The savings in pipeline costs enables longer tie-backs to
the host facility to be economically considered which may allow the
use of an existing host facility to be used for a remote field as
opposed to having to provide a new host facility. This is of
particular benefit when the field to be developed is located
beneath deep water.
[0020] The underwater facility may include fluid separating means
for separating gas from the production fluid from said at least one
production well and recirculation means for conveying gas from the
fluid separating means into the gas compressor. The gas separated
from the production fluid comprises gas supplied from the host
facility, hence by conveying the separated gas from the separating
means to the gas compressor, gas is being recirculated. Therefore,
the pipeline from the host facility to the underwater facility can
be of a smaller diameter when gas is recirculated as the quantity
of gas required from the host facility for injection is
significantly reduced.
[0021] By separating gas from the production fluid at the
underwater facility, the diameter of the pipeline for conveying
production fluid from the underwater facility to the host facility
can be significantly reduced as this pipeline is no longer required
to transport gas. As the production fluid in the pipeline is at
least substantially free from gas, the problems of slugging,
hydrate formation and of the flow of production fluid being choked
due to gas expanding as pressure reduces along the pipeline is
significantly reduced. Furthermore, the separation of gas from the
production fluid at the underwater facility may enable only a
single production fluid pipeline being required to convey
production fluid to the host facility instead of two such
pipelines. The reduction in the diameter of the production fluid
pipeline also has the advantages mentioned in relation to the gas
supply pipeline of requiring less material, being able to weld
pipeline sections together more quickly or being able to be
installed from a reel.
[0022] The underwater facility may be on a seabed and the
production fluid pipeline may include a production riser from the
seabed to the host facility at topsides, and the host facility may
be connected to the production riser at or close to the seabed by a
separate riser. The production riser is arranged to convey
production fluid to the host facility and the separate riser is
arranged to convey gas from the host facility for injection into
the production riser. By injecting gas into the production riser at
or near its base, gas is not required to be left in the production
fluid coming from the underwater facility for lifting the
production fluid up the production riser. Hence, only sufficient
gas need be required to achieve flow of production fluid from the
production wells to the base of the production riser. By having the
separate riser, production fluid flow from production wells to the
host facility, including absorbed/mixed gas, would be improved by
having better slug flow and reducing hydrate formation. The
production fluid pipeline from the underwater facility to the base
of the production riser may only need to be of a sufficient
diameter to convey at least substantially gas free production fluid
and does not need to be increased in diameter or have an additional
pipeline in order to convey gas or to avoid production fluid being
choked by gas. Also, by injecting gas into the production riser,
the need for pressure boosting of the production fluid at the
underwater facility may be reduced or eliminated thus reducing the
size of or eliminating the need for any pumps for such a purpose
there.
[0023] The system preferably includes a power and control umbilical
extending from the host facility to the underwater gas compressor
for conveying power and control signals to the gas compressor. The
power and control umbilical may be also arranged to convey power
and control signals required for other underwater equipment such as
Christmas trees and manifolds. Minimal additional cost is incurred
when providing power to the underwater gas compressor if the same
umbilical is used for the underwater gas compressor and other
underwater equipment.
[0024] The underwater facility may include a retrievable module
which incorporates the gas compressor. Hence, the gas compressor
may be easily recovered for inspection, maintenance or repair, for
example. The module may be of the general type forming part of the
modular system designed by Alpha Thames Ltd of Essex, United
Kingdom, and named AlphaPRIME.
[0025] According to another aspect of the present invention there
is provided a method for injecting gas into a hydrocarbon
reservoir, comprising the steps of:
[0026] supplying gas from a host facility to an underwater gas
compressor via a connecting pipeline;
[0027] compressing the gas received by the underwater gas
compressor to a higher pressure; and
[0028] injecting the compressed gas into at least one well
connected to the underwater gas compressor, and into the
hydrocarbon reservoir to improve conveyance of production fluid at
least towards the host facility.
[0029] The step of injecting gas may include injecting gas into at
least one injection well, and include driving the gas into the
hydrocarbon reservoir via the or each injection well at a pressure
at least as high as the pressure of the production fluid in the
reservoir.
[0030] The step of injecting gas may include injecting gas into at
least one production well, and include injecting gas into
production fluid in the or each production well.
[0031] The method may include the additional steps of conveying
production fluid from the reservoir, separating gas from the
production fluid, and conveying the separated gas into the gas
compressor. The gas separated from the production fluid may be
disposed of into at least one cavity below the surface of the
ground underneath the water in which the gas compressor is located.
Present regulations do not allow flaring gas for new fields being
developed, hence it is beneficial to dispose of gas in this way
when there is no market for the gas or it is uneconomic to export
the gas.
[0032] The method may include the steps of receiving production
fluid at the host facility via a production riser from a seabed,
and injecting gas from the host facility into the production riser
at or close to the seabed.
[0033] The method may include the steps of using any of the system
components referred to above.
[0034] According to yet another aspect of the present invention
there is provided a method for handling production fluid,
comprising the steps of:
[0035] receiving production fluid in an underwater facility from a
hydrocarbon reservoir;
[0036] separating gas from the production fluid in the underwater
facility; and
[0037] disposing of the gas into at least one cavity below the
surface of the ground underneath the water in which the underwater
facility is located.
[0038] Embodiments of the present invention will now be described,
by way of example, with reference to the accompanying drawings, in
which:
[0039] FIG. 1 is a schematic diagram of a system for putting the
invention into practice;
[0040] FIG. 2 is a schematic diagram of a modified system;
[0041] FIG. 3 is a modified detail of FIG. 2; and
[0042] FIGS. 4 to 7 are schematic diagrams of other modified
systems.
[0043] Referring to FIG. 1 of the accompanying drawings, a system 1
has a host facility 2 which may be, for example, onshore or an
offshore fixed or floating rig. The host facility 2 has a gas
processing plant 3 with a connected gas compressor 4 which is
connected to a remote seabed facility 5 by an injection gas supply
pipeline 6. The seabed facility 5 is connected to a plurality of
gas injection wells 7 for a hydrocarbon reservoir whereby each well
is connected to the facility 5 by a separate supply flowline 8
which is able to withstand conveyed gas of a higher pressure than
the gas supply pipeline 6.
[0044] At the seabed facility 5 the gas supply pipeline 6 is
connected to an inlet 9 of a high pressure gas compressor 10 and a
conduit 11 from an outlet 12 of the compressor 10 is manifolded to
the flowlines 8 connected to the injection wells 7.
[0045] The gas compressor 10 is arranged to be supplied with power
and control signals from the host facility 2 via a power and
control umbilical 13.
[0046] The operation of the system 1 will now be described.
[0047] The gas processing plant 3 dries gas for injection to a
predetermined specification to make it suitable for compression by
the compressor 4 at the host facility 2. The dried gas is routed
into the gas supply pipeline 6 which conveys the gas to the seabed
facility 5.
[0048] At the seabed facility 5, the gas is further compressed by
the high pressure gas compressor 10 and is injected into the
hydrocarbon reservoir via the well supply flowlines 8 and the gas
injection wells 7. The pressure of the injected gas is at least as
high as the pressure of the fluid in the reservoir so that it
drives the production fluid to the host facility 2 via production
wells and an arrangement of pipelines and flowlines (not
shown).
[0049] Modifications to the system 1 will now be described in which
parts which correspond to those shown in FIG. 1 are designated with
the same reference numerals and are not described in detail
below.
[0050] FIG. 2 illustrates one modification to the system 1 showing
the production wells 25 which are each connected to the seabed
facility 15 via a flowline 16 which are manifolded to a single
conduit 17 at the facility 15. In the modified system 18, the
seabed facility 15 has a fluid separation vessel 19 and the
manifold conduit 17 is connected to an inlet 20 of this vessel. At
the seabed facility 15, a first outlet 21 of the fluid separation
vessel 19 is connected to the gas supply pipeline 6 by a
recirculation conduit 22 and a second outlet 23 of the vessel 19 is
connected to a production fluid pipeline leading to the host
facility 2 indicated by arrow 24.
[0051] In use, gas compressed by the high pressure gas compressor
10 at the seabed facility 15 is injected into the hydrocarbon
reservoir via the well supply flowlines 8 and the gas injection
wells 7. This drives production fluid in the reservoir up to the
heads of production wells 25, and on into the fluid separation
vessel 19 via the flowlines 16 and the manifold conduit 17. The
vessel 19 separates most gas from the production fluid. The at
least substantially gas free production fluid leaves the fluid
separation vessel 19 by the second outlet 23 and is driven to the
host facility 2. The separated gas includes or comprises gas
supplied from the host facility 2 and this gas leaves the fluid
separation vessel 19 by the first outlet 21 and is conveyed by the
recirculation conduit 22 into the gas supply pipeline 6 to be
compressed by the gas compressor 10 for injection into the
reservoir. As gas is now being recirculated for injection into the
hydrocarbon reservoir to lift the production fluid, gas only needs
to be supplied by the host facility 2 to top-up the recirculated
gas, replacing gas not separated by the fluid separation vessel 19
or remaining in the reservoir.
[0052] In a modification to the system shown in FIG. 2, the seabed
facility 25 illustrated in FIG. 3 comprises a base structure 26
which supports a retrievable module 27 that contains the high
pressure gas compressor 10 and the fluid separation vessel 19. The
gas compressor inlet 9 is connected to the injection gas supply
pipeline 6 from the host facility 2 by a multi-ported fluid
connector 28 such as that described in GB-A-2261271 and the gas
compressor outlet 12 is connected by the outlet manifold conduit 11
to the well supply flowlines 8 via the same multi-ported fluid
connector 28. Also, the fluid separation vessel inlet 20 is
connected by the inlet manifold conduit 17 of the flowlines 16 via
the same connector 28 and the first outlet 21 from the vessel 19 is
connected to the inlet 9 of the gas compressor 10 via the
recirculation conduit 22. The second outlet 23 from the vessel is
connected to the production pipeline 24 leading to the host
facility 2 via the same fluid connector 28.
[0053] This connector 28 enables the module 27 to be isolated from
the pipelines 6,24 and flowlines 8,16 connected to the seabed
facility 25 when the module 27 is to be retrieved.
[0054] In addition, the module 27 has a power and control pod 29
which is connected to the power and control umbilical 13 by a
connector 30 whereby the pod 29 directs power and provides control
signals to equipment within the module 27. In particular, the pod
29 controls the high pressure gas compressor 10 but it may be
overridden by control signals received from the host facility 2 via
the umbilical 13. The pod 29 also drives the gas compressor 10 with
power received from the host facility 2 via the umbilical 13.
[0055] In use, gas from the host facility 2 is received by the high
pressure gas compressor 10 in the retrievable module 27 which
drives gas into the hydrocarbon reservoir. Production fluid from
the reservoir is received by the fluid separation vessel 19 in the
module 27 where gas is separated from the production fluid and is
conveyed by the recirculation conduit 22 so as to be compressed by
the high pressure gas compressor 10 for injection into the
reservoir. The at least substantially gas free production fluid
from the fluid separation vessel 19 leaves the module 27 via the
fluid connector 28 and is conveyed to the host facility 2 via the
production pipeline 24.
[0056] Another modification to the system 1 is shown in FIG. 4
where the modified system 32 is for gas lift and the injection
wells are replaced by production wells 25. The production wells 25,
in addition to being connected to the seabed facility 33 by the
flowlines 8, are also each connected to the seabed facility 33 via
a separate flowline 16, the flowlines 16 being manifolded to a
single conduit 17 at the facility 33. The conduit 17 is connected
to a production fluid pipeline leading to the host facility 2
indicated by arrow 24.
[0057] In use, gas compressed by the high pressure gas compressor
10 at the seabed facility 33 is injected down the annulus of the
wellbore of each production well 25 so that it enters the tubing
via tubing perforations and combines with and lifts the production
fluid from the hydrocarbon reservoir in the tubing of the wellbore.
The production fluid is lifted up to the heads of production wells
25, and on to the host facility 2 via the flowlines 16, the
manifold conduit 17 and the production fluid pipeline 24.
[0058] FIG. 5 illustrates a modification to the system 32 shown in
FIG. 4 which is similar to the system 18 shown in FIG. 2 except
that the modified system 34 is directed to gas lift as opposed to
gas injection with the flowlines 8 from the seabed facility 15
being connected to the production wells 25.
[0059] In use, gas compressed by the high pressure gas compressor
10 at the seabed facility 15 is injected down the wellbore of each
production well 25 so that it combines with and lifts the
production fluid from the reservoir. The production fluid is lifted
into the fluid separation vessel 19 which separates most gas from
the production fluid. The at least substantially gas free
production fluid leaves the fluid separation vessel 19 by the
second outlet 23 and is lifted to the host facility 2 and the
separated gas is conveyed by the recirculation conduit 22 into the
gas supply pipeline 6 to be compressed by the gas compressor 10 for
injection into the wellbore of each production well 25.
[0060] FIG. 6 illustrates one modification to the system 34 shown
in FIG. 5. The modified system 35 is particularly applicable to
deepwater applications, and the host facility 36 is shown to be a
floating production vessel as opposed to being a fixed production
structure as previously illustrated. The production fluid pipeline
24 connects the seabed facility 15 to the host facility 36 and the
portion of the pipeline 24 which rises from the seabed to the host
facility 36 is known as a production fluid riser 37. At the host
facility 36, the gas processing plant 3 is connected to a gas
compressor 38 which is separate from the gas compressor 4 for the
gas supply pipeline 6 and this gas compressor 38 is connected by a
riser 39 to the base of the production fluid riser 37.
[0061] In use, at the base of the production fluid riser 37
production fluid from the seabed facility 15 has gas from the host
facility 36 injected into it via the riser 39 so that sufficient
lift is provided to raise the production fluid up the production
riser 37 to the host facility 36.
[0062] The host facility 36 may have a fluid separation vessel (not
shown) for processing production fluid including gas which has
previously been injected into the production fluid via the riser
39. Such gas is separated from the production fluid by this vessel.
The separated gas may be then recirculated by being injected into
the base of the production riser 37 via the riser 39.
[0063] FIG. 7 illustrates another modification to the system 34
shown in FIG. 5 in which in the modified system 40, the gas
separated by the fluid separation vessel 19 is disposed of beneath
the seabed instead of being recirculated. The first outlet 21 of
the fluid separation vessel 19 is connected by a pipeline 41 to a
disposal well 42 which injects the gas into a cavity 43 beneath the
seabed, such as a depleted reservoir.
[0064] Whilst particular embodiments have been described, it will
be understood that various modifications may be made without
departing from the scope of the invention. For example, the seabed
facility shown in FIGS. 1 or 2 or any one of FIGS. 4 to 7 may have
a retrievable module like that illustrated in FIG. 3 and containing
the high pressure gas compressor 10 and any fluid separation vessel
19. The power and control pod 29 in the retrievable module 27 is
optional, as power and control could be provided/controlled
externally of the module 27. Production fluid from the fluid
separation vessel 19 may be boosted by a pump to enable the
production fluid to be conveyed to the host facility and/or
increase production rate and overall recovery of the production
fluid. The pipelines and flowlines described may be of a rigid or
flexible construction. The seabed facility may have a plurality of
fluid separation vessels and/or retrievable modules possibly
arranged to operate in parallel with each other.
[0065] Any of the above described embodiments may be used in
combination with a water injection system.
[0066] Although the invention has been described in the context of
a subsea hydrocarbon field, it would also be applicable to other
areas such as swamps or other inaccessible areas whereby the
system, including the high pressure gas compressor 10, would be
land based.
* * * * *