U.S. patent application number 10/477573 was filed with the patent office on 2004-08-05 for fluid transportation system.
Invention is credited to Appleford, David Eric, Lane, Brian William.
Application Number | 20040149445 10/477573 |
Document ID | / |
Family ID | 9914834 |
Filed Date | 2004-08-05 |
United States Patent
Application |
20040149445 |
Kind Code |
A1 |
Appleford, David Eric ; et
al. |
August 5, 2004 |
Fluid transportation system
Abstract
Method and apparatus for assisting the flow of production fluid
from a hydrocarbon well to a remote location in conditions in which
gelling or solidification is a problem. The method involves adding
dilution fluid (60) such as water, to production fluid from a
wellhead (4) in a first sub-system (8) close to the wellhead (4),
conveying the mixture to a second sub-system (14) where the
dilution fluid (60) is separated from the mixture in a separator
chamber (38) as a consequence of their different specific
gravities, recirculating the separated dilution fluid back to the
first sub-system (8) and adding it to further production fluid from
the wellhead (4). The requirements for pipeline heating, chemical
injection and conveying large volumes of dilution fluid to a host
facility can be avoided by the invention.
Inventors: |
Appleford, David Eric;
(Essex, GB) ; Lane, Brian William; (Essex,
GB) |
Correspondence
Address: |
SUMMA & ALLAN, P.A.
11610 NORTH COMMUNITY HOUSE ROAD
SUITE 200
CHARLOTTE
NC
28277
US
|
Family ID: |
9914834 |
Appl. No.: |
10/477573 |
Filed: |
November 12, 2003 |
PCT Filed: |
May 14, 2002 |
PCT NO: |
PCT/GB02/02217 |
Current U.S.
Class: |
166/357 ;
166/366 |
Current CPC
Class: |
E21B 43/01 20130101 |
Class at
Publication: |
166/357 ;
166/366 |
International
Class: |
E21B 043/01 |
Foreign Application Data
Date |
Code |
Application Number |
May 17, 2001 |
GB |
0112103.7 |
Claims
1. A method of assisting flow of production fluid from a subsea
wellhead (4) to a remote subsea location (14) including the steps
of: (a) adding dilution fluid to production fluid at a dilution
fluid addition location (8) close to or at the wellhead (4) to
provide a mixture; (b) conveying the mixture through a pipe (10) to
the remote location (14); (c) separating at least some of the
dilution fluid from the mixture at the remote location (14); (d)
conveying (12) the separated dilution fluid from the remote
location (14) to the dilution fluid addition location (8); and (e)
adding the separated dilution fluid to further production fluid
flowing through the wellhead (4) at the dilution fluid addition
location (8).
2. The method according to claim 1 wherein the remote subsea
location (14) is situated close to a host facility (2).
3. The method according to claims 1 and 2 wherein prior to step (a)
the dilution fluid is supplied from the host facility (2) to the
dilution fluid addition location (8).
4. The method according to claim 2 or 3 comprising the further step
of conveying (16) the separated production fluid to the host
facility (2).
5. The method according to any preceding claim wherein the dilution
fluid essentially comprises water.
6. The method according to any preceding claim wherein the ratio of
dilution fluid to production fluid in the mixture lies in the range
2:1 to 4:1.
7. The method according to claim 6 wherein the ratio of dilution
fluid to production fluid in the mixture lies in the range 2.5:1 to
3.5:1.
8. The method according to any preceding claim wherein the step of
separating (38) the dilution fluid (60) from the mixture involves
separating a majority of the dilution fluid (60) from the
mixture.
9. The method according to claim 8 wherein the step of separating
the dilution fluid (60) from the mixture involves separating at
least 90% of the dilution fluid (60) therefrom.
10. The method according to any preceding claim wherein the
separation of the dilution fluid from the mixture involves routing
the mixture into a separator chamber (38) of a system (14) at the
remote location where separation of the dilution fluid (60) from
the production fluid (63) occurs as a consequence of their
different specific gravities.
11. The method according to claim 10 wherein the system (14) at the
remote location includes a pump (62) and the conveying of the
separated dilution fluid (60) to the dilution fluid addition
location (8) includes pumping the dilution fluid (60) with the pump
(62).
12. The method according to any preceding claim including conveying
some of the separated fluid (60) to a disposal well (78).
13. The method according to claim 12 wherein a pump (80) is
situated at the dilution fluid addition location (8) and the step
of conveying the dilution fluid (60) to the disposal well (78)
includes pumping it there with the pump (80).
14. Apparatus for assisting flow of production fluid from a seabed
wellhead (4) to a remote subsea location (14) including dilution
fluid addition means (8) situated close to or at the wellhead (4)
for adding dilution fluid to the production fluid to produce a
mixture, a pipe (10) for conveying the mixture to the remote
location (14), separating means (38) at the remote location (14)
for separating at least some of the dilution fluid (60) from the
mixture and means (12, 62 . . . ) for conveying the separated
dilution fluid (60) from the remote location (14) to the dilution
fluid addition means (8) for addition to further production fluid
flowing through the wellhead (4).
Description
[0001] The present invention relates to a method and apparatus for
assisting a flow of hydrocarbon fluid from a wellhead of a
hydrocarbon extraction well to a remote location.
[0002] When production fluid from such a well is highly viscous
and/or exhibits non-Newtonian rheology (i.e. non-linear
relationship between rate of deformation and applied shear stress),
which may also be the case when the fluid contains wax, there is a
tendency for the fluid to gel or even solidify during
transportation through a pipeline running from the wellhead to a
remote location such as a host facility. This occurs because the
temperature of the fluid falls once it leaves the wellhead causing
its viscosity to increase. This problem is particularly pronounced
when the pipeline runs along the sea bed where temperatures are
low. In the past, this problem has been addressed by a variety of
techniques. A first technique is to insulate the pipeline which is
costly since the pipeline may be tens of kilometres long.
Furthermore, in the event of shutdown occurring for any reason, it
is necessary to inject chemicals into the production fluid to
prevent gelling or solidification occurring. A second technique is
to rely solely on injected chemicals. Any injection of such
chemicals suffers from the disadvantages that appropriate chemicals
need to be purchased and stored at the host facility. Also a
dedicated chemical injection pipeline leading from the host
facility to the wellhead needs to be provided as well as equipment
at the host facility for recovering the chemicals from the
production fluid.
[0003] A third technique is to use a so-called "pipe-in-pipe" for
conveying the production fluid from the wellhead to the host
facility. With this technique a continuous flow of heated water is
passed through an outer pipe in which an inner production fluid
transportation pipe is situated. The capital cost of the pipeline
is high as are the running costs associated with continuously
providing heated water, which is generally discharged into the sea
at the wellhead. As explained above, the injection of appropriate
chemicals is required in the event of shutdown occurring. Heating
may alternatively be provided by trace heaters in the pipeline in
combination with insulation over the majority of its length
[0004] A fourth technique is to continuously pump water from the
host facility down a high pressure riser and pipeline to the
wellhead (or to a down hole location) where the water is combined
with the production fluid producing a mixture which is conveyed to
the host facility where separation occurs. This technique suffers
from the significant costs associated with (a) providing a high
pressure pipeline for delivering dilution fluid to the wellhead;
(b) providing equipment at the host facility to treat the water so
that it is suitable for mixing with the production fluid; (c)
pumping water at high pressure to the wellhead; and (d) separating
the water from the production fluid once it has returned to the
host facility. Furthermore, in a situation in which the host
facility is owned by a company which is different from that
effecting extraction, a levy will generally be paid to the host
owner which is dependent on the overall volume of fluid received by
the host facility. Increasing this overall volume by the addition
of dilution fluid adds to the levy payable. A charge is also likely
to be levied for water provided by the host facility.
[0005] An object of the invention is to provide a system which
overcomes at least some of the problems of the prior art discussed
above.
[0006] Thus according to a first aspect of the invention there is
provided a method of assisting flow of production fluid from a
sub-sea wellhead to a remote sub-sea location including the steps
of: (a) adding dilution fluid to the production fluid at a dilution
fluid addition location close to or at the wellhead to provide a
mixture; (b) conveying the mixture through a pipe to the remote
location; (c) separating at least some of the dilution fluid from
the mixture at the remote location; (d) conveying the separated
dilution fluid from the remote location to the dilution fluid
addition location; and (e) adding the separated dilution fluid at
the dilution fluid addition location to further production fluid
flowing through the wellhead.
[0007] Such a method avoids the requirement to take any particular
precautionary measures if shutdown is to occur. This is
particularly useful since it may not be possible to anticipate such
a shutdown far enough in advance. Furthermore, the use of chemicals
and the requirement for a dedicated chemical injection line to the
wellhead can be avoided and a requirement for a continuous supply
of treated water pumped under high pressure from the host facility
can also be avoided. The inventive method also avoids the high
capital expenditure of pipe-in-pipe lines and pipes with electrical
heating elements. The running costs associated with heating a
continuous supply of diluting fluid, such as water, or providing a
continuous electricity supply for electrical heating of the pipe
are also avoided.
[0008] The tariff paid to a host operator will not be increased as
a direct or indirect result of delivering a mixture of production
fluid and a large amount of diluting fluid (normally water) to the
host facility.
[0009] Preferably the remote sub-sea location is situated close to
a host facility so that after separation of the dilution fluid from
the production fluid, the production fluid only needs to be
transported over a short distance.
[0010] In order to be able to take water from the host facility,
which would not be able to be discharged directly into the sea,
preferably prior to step (a) the dilution fluid is pumped from the
host facility to the dilution fluid addition location possibly via
the remote location. Such a step may well attract a negative tariff
for a company using the host facility (i.e. the host facility owner
pays the user for using contaminated water from the host).
[0011] The method preferably also involves the step of conveying
the separated production fluid to the host facility.
[0012] Conveniently the dilution fluid essentially comprises water
and the volume ratio of the dilution fluid to the production fluid
in the mixture may lie in the range 2:1 to 4:1 and more preferably
in the range 2.5:1 to 3.5:1. Such a ratio provides adequate
dilution without unduly increasing the volume of the mixture to be
conveyed to the remote location.
[0013] To increase efficiency of the method, the step of separating
the dilution fluid from the mixture preferably involves separating
a majority of the dilution fluid therefrom and more preferably
separating at least 90% of it therefrom.
[0014] Preferably the separation of the dilution fluid from the
mixture involves routing the mixture into a separator chamber of a
system at the remote location where separation of the dilution
fluid from the production fluid occurs as a consequence of their
different specific gravities. The equipment for effecting such
separation can be simple and robust and suitable for operating in
an underwater location.
[0015] Preferably the system at the remote location includes a pump
and the conveying of the separated dilution fluid to the dilution
fluid addition location includes pumping the dilution fluid with
the pump.
[0016] So as to increase the credit provided for removing
contaminated water from the host facility, preferably the method
includes conveying some of the water which has been used as
dilution fluid to a disposal well. The method may also involve
pumping a certain amount of contaminated water directly from the
host to the disposal well, possibly via the remote location. When
such a supply to a disposal well is employed, preferably a pump is
situated at the dilution fluid addition location and the step of
conveying the dilution fluid (e.g. water) to the disposal well
includes pumping it there with the pump.
[0017] According to a second aspect of the invention there is
provided apparatus for assisting flow of production fluid from a
sea-bed wellhead to a remote sub-sea location including dilution
fluid addition means situated close to or at the wellhead for
adding dilution fluid to the production fluid to produce a mixture,
a pipe for conveying the mixture to the remote location, separating
means at the remote location for separating at least some of the
dilution fluid from the mixture and means for conveying the
separated dilution fluid from the remote location to the dilution
fluid addition means for addition to further production fluid
flowing through the wellhead.
[0018] The invention will now be described by way of example only
with reference to the accompanying schematic Figures in which:
[0019] FIG. 1 shows a system for putting the invention into
practice;
[0020] FIG. 2 shows details of two seabed sub-systems of the system
shown in FIG. 1;
[0021] FIG. 3 shows a modified system for putting the invention
into practice; and
[0022] FIG. 4 shows details of the two seabed sub-systems of the
system shown in FIG. 3.
[0023] The system of FIG. 1 shows a host facility 2 connected to
receive production fluid from a wellhead tree 4. The production
fluid will be referred to below as oil but may be a mixture of
fluids such as oil and gas. The wellhead tree 4 is connected by an
output pipe 6 to a first seabed sub-system 8 which is connected by
a mixture pipeline 10 and a dilution fluid pipeline 12 to a second
seabed sub-system 14 situated remotely therefrom. While the
sub-systems have been described as seabed sub-systems they may be
floating and/or tethered to the seabed. Each of the first and
second sub-systems are respectively positioned close to the
wellhead tree 4 and the host facility 2 relative to the distance
they are apart from each other. The second sub-system 14 is
connected to the host facility 2 by means of a production fluid
riser 16 and a dilution fluid supply riser 18.
[0024] The components in each of the sub-systems 8 and 14 will now
be described in detail with reference to FIG. 2.
[0025] The first sub-system 8 has a production inlet 20 connected
to the output pipe 6, a dilution fluid inlet 22 connected to the
dilution fluid pipeline 12 and mixture outlet 24 connected to the
mixture pipeline 10. A mixing loop pipe 26 connects the dilution
fluid inlet 22 to an intermediate junction 29 on a production
conduit 28 extending between the production inlet 20 and the
mixture outlet 24. The mixing loop 26 has a remotely actuable
throttle valve 30 and a flow meter 31 for respectively controlling
and measuring flow through the mixing loop 26.
[0026] The second sub-system 14 has duplicated first and second
separations systems 32 and 34, only the first 32 of which will be
described in detail. A mixture inlet 36 is connected to the mixture
pipeline 10 and to an inlet 70 of a separator chamber 38 via a
failsafe valve 40. A first outlet 44 of the chamber 38 is connected
to a dilution fluid outlet 46 via a controlling throttle valve 48
and non-return valve 50. A second outlet 52 of the chamber 38 is
connected to a separated production fluid outlet 54 via a
controlling throttle valve 56. The separated production fluid
outlet 54 is connected to the production fluid riser 16. A level
sensor 42 senses the position of the interface between dilution
fluid 60 and oil 63 in the chamber 38 and a pressure sensor 58
senses the pressure in the chamber. A weir 61 is situated between
the first and second chamber outlets 44 and 52.
[0027] A pressure boosting pump 62 is positioned in a conduit 68
leading from the first chamber outlet 44 to the dilution fluid
outlet 46 for pumping dilution fluid out of the chamber 38. The
pump 62 is designed to be capable of pumping the dilution fluid
into the flow of produced fluid at the junction 29. An additional
pump may be situated in the mixing loop to facilitate this process.
Where it is necessary to boost the pressure of the production
fluid, to enable it to reach the second sub-system at an
appropriate flow rate, a jet pump may be situated at junction 29
arranged so that the dilution fluid is the diving fluid which
entrains production fluid. A recirculation loop pipe 64 connects
the conduit 68, downstream of the recirculation pump 62, to the
inlet 70 of the chamber 38 via a non-return valve 66 and a
restricting device 67 such as an orifice plate. The purpose of the
restricting device 67 is to ensure that dilution fluid does not
merely take the path of least resistance and be short circuited
through the separator.
[0028] The dilution fluid supply riser 18, leading from the host
facility, is connected to a dilution fluid inlet 72 which is
connected by a dilution fluid conduit 74, containing a non-return
valve 76, to the dilution fluid outlet 46.
[0029] The host facility 2 includes processing equipment (not
shown) for processing production fluid received from the production
fluid riser 16 and providing a supply of treated dilution fluid,
for example water, which is suitable for dilution of the production
fluid and may be pumped down the dilution fluid supply riser 18 to
the dilution fluid inlet 72 of the second sub-system 14.
[0030] The manner in which the system operates will now be
described. The description will refer to the dilution fluid as
being water although it could be an alternative fluid.
[0031] If the viscosity of the oil emerging from the wellhead tree
4 is too viscous, so that there is a danger of it gelling during
transportation to the host facility, then a batch of dilution fluid
(e.g. sea-water or water treated to prevent adverse reaction such
as scale formation) may be supplied from the host facility down the
dilution fluid supply riser 18 into the second sub-system 14 at the
dilution fluid inlet 72, through the conduit 74 and out via the
dilution fluid outlet 46. The water then flows through the dilution
fluid pipeline 12 to the dilution fluid inlet 22 of the first
sub-system 8 where it is routed via the mixing loop 26 to the
junction 29 with the production conduit 28 where it mixes with the
production fluid from the wellhead tree 4. Signals from the flow
meter 31 are monitored by a control system (not shown) which
controls the opening of the throttle valve 30 so that water is
mixed with the oil in the ratio 3:1 typically. The resulting
mixture then leaves the first sub-system 8 at the mixture outlet 24
and is conveyed via the mixture pipeline 10 to the mixture inlet 36
of the second sub-system 14 where it is routed into one of the two
separating systems 32 and 34. In the chamber 38 of the separating
system, the water 60 occupies the region to the left of the weir 61
(as seen in FIG. 2) and oil floats above the water and passes over
the weir 61 into the region to the right thereof. Separated oil
then flows out of the chamber 38 via the second outlet 52 to the
production fluid outlet 54 and up the production fluid riser 16 to
the host facility 2. The separated water 60 flows from the chamber
38 through its first outlet 44 and through the conduit 68 to the
dilution fluid outlet 46. The water is then returned from the
second to the first sub-system where it enters the first sub-system
at the dilution fluid inlet 22 from where it becomes mixed with
further oil as described above.
[0032] The control system (not shown), on the basis of signals
received from the level sensor 42 and pressure sensor 58, controls
the operation of throttle valves 56 and 48, controlling the flows
of oil and water respectively leaving the chamber 38, and the water
pressure boosting pump 62 to maintain the fluid interface between
the oil 63 and the water 60 in the chamber 38 below the top of the
weir 61. If there is a requirement to increase the amount of water
in the chamber 38, the throttle valve 48 would be closed to a
certain extent so that water would be forced by the recirculation
pump 62 through the pressure boosting loop 64 back into the chamber
38 rather than back to the first sub-system 8.
[0033] Using the method described above, the same batch of water is
repeatedly used to dilute oil flowing through the mixture pipeline
10 between the first and second sub-systems 8 and 14. Accordingly,
a continuous supply of water from the host facility is not required
and oil reaching the host facility is substantially free of
diluting water which has been removed from the mixture at the
second sub-system 14.
[0034] FIG. 4 shows a modified system in which parts which
correspond to those shown in FIG. 2 are designated with the same
reference numeral and not described in detail below.
[0035] The system shown in FIG. 4 differs from that shown in FIG. 2
in that it includes a means for delivering fluid received from the
host facility and/or the first outlets 44 of the chambers 38 in the
second sub-system to a deposal well 78.
[0036] The dilution fluid inlet 22 of the first sub-system is
connected by two pumps 80 to a disposal fluid outlet 82 which is
connected by a disposal pipeline 86 to a wellhead tree of the
disposal well 78. A flow meter 84 is situated in a disposal conduit
88 constituting this connection for sensing the rate of flow to the
disposal well 78. Two pumps are provided rather than one merely to
provided redundancy so that conveyance of fluid to the disposal
well need not be interrupted if one pump is not operating for any
reason.
[0037] When water from the host is to be disposed of directly
without performing any dilution function it will pass through the
so-called dilution pipeline 12 notwithstanding the fact that it is
not being used for any dilution purposes.
[0038] Although the invention has been described in the context of
a sub-sea hydrocarbon field, it would also be applicable to fields
in other environments in which access constitutes a problem, for
example in swampy areas, and/or fields in cold climatic areas such
as the Arctic.
* * * * *