U.S. patent application number 12/634957 was filed with the patent office on 2010-06-17 for subsea boosting cap system.
Invention is credited to PAULO CEZAR SILVA PAULO.
Application Number | 20100147527 12/634957 |
Document ID | / |
Family ID | 42239106 |
Filed Date | 2010-06-17 |
United States Patent
Application |
20100147527 |
Kind Code |
A1 |
PAULO; PAULO CEZAR SILVA |
June 17, 2010 |
SUBSEA BOOSTING CAP SYSTEM
Abstract
A subsea boosting cap system is disclosed. The system comprises
an anchor assembly capable of attaching to the sea floor. The
anchor assembly comprises a pump cavity capable of receiving a
removable pump assembly. A valve system is attached to the anchor
assembly. The valve system comprises an inlet flow path and an
outlet flow path. A boosting cap covers the pump cavity. The
boosting cap comprises a first flow path configured to provide
fluid communication between the inlet flow path and the removable
pump assembly. A second flow path provides fluid communication
between the removable pump assembly and the outlet. A crossover
flow path provides fluid communication between the inlet flow path
and the outlet flow path, the crossover flow path bypassing the
pump cavity.
Inventors: |
PAULO; PAULO CEZAR SILVA;
(Katy, TX) |
Correspondence
Address: |
Zarian Midgley & Johnson PLLC
University Plaza, 960 Broadway Ave., Suite 250
Boise
ID
83706
US
|
Family ID: |
42239106 |
Appl. No.: |
12/634957 |
Filed: |
December 10, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61122001 |
Dec 12, 2008 |
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Current U.S.
Class: |
166/339 ;
166/351 |
Current CPC
Class: |
Y02P 80/10 20151101;
F16K 11/0655 20130101; F16K 27/07 20130101; Y02P 80/156 20151101;
Y10T 137/0318 20150401 |
Class at
Publication: |
166/339 ;
166/351 |
International
Class: |
E21B 43/01 20060101
E21B043/01; E21B 41/00 20060101 E21B041/00 |
Claims
1. An offshore fluid production system, comprising: a subsea
wellbore at a first position on an ocean floor; a subsea boosting
cap system positioned in a second position on the ocean floor that
is different from the first position, the subsea boosting cap
system comprising: an anchor assembly capable of attaching to the
sea floor, the anchor assembly comprising a pump cavity capable of
receiving a removable pump assembly; a valve system attached to the
anchor assembly, the valve system comprising an inlet flow path and
an outlet flow path, the inlet flow path being in fluid
communication with the subsea wellbore; a boosting cap covering the
pump cavity, the boosting cap comprising a first flow path
configured to provide fluid communication between an inlet flow
path and the removable pump assembly when the removable pump
assembly is positioned in the pump cavity, and a second flow path
providing fluid communication between the removable pump assembly
and the outlet flow path when the removable pump assembly is
positioned in the pump cavity; and a crossover flow path providing
fluid communication between the inlet flow path and the outlet flow
path, the crossover flow path bypassing the pump cavity, the valve
system being capable of directing fluid flow to the first flow path
and the crossover flow path; and a downflow production line in
fluid communication with the outlet.
2. The system of claim 1, further comprising the removable pump
assembly engaging the pump cavity, the boosting cap being
positioned over the removable pump assembly.
3. The system of claim 2, wherein the pump assembly comprises a
spool adapter and one or more pumps supported by the spool
adapter.
4. The system of claim 3, wherein the pump assembly further
comprises a lower cavity for collecting contaminants, the lower
cavity being in fluid communication with the one or more pumps.
5. The system of claim 4, wherein a third flow path provides fluid
communication from the first flow path of the boosting cap to the
lower cavity and a fourth flow path provides fluid communication
from the lower cavity to the second flow path of the boosting
cap.
6. The system of claim 1, further comprising a pressure cap sealing
the pump cavity, the boosting cap being positioned over the pump
cavity and attached to the pressure cap, wherein the pump cavity
does not contain the removable pump assembly.
7. The system of claim 1, wherein the crossover flow path allows
fluid communication between the inlet flow path and the outlet flow
path when the boosting cap is removed from the pump cavity.
8. The system of claim 1, wherein the fluid communication between
the inlet flow path and the subsea wellbore is provided by a
conduit attached to the inlet flow path with a guide and hinge over
connecting device.
9. The system of claim 8, wherein the downflow production line is
attached to the outlet flow path with a guide and hinge over
connecting device.
10. A subsea boosting cap system, comprising: an anchor assembly
capable of attaching to the sea floor, the anchor assembly
comprising a pump cavity capable of receiving a removable pump
assembly; a valve system attached to the anchor assembly, the valve
system comprising an inlet flow path and an outlet flow path, the
inlet flow path being capable of fluidly communicating with a
subsea wellbore; a boosting cap covering the pump cavity, the
boosting cap comprising a first flow path configured to provide
fluid communication between the inlet flow path and the removable
pump assembly when the removable pump assembly is positioned in the
pump cavity, and a second flow path providing fluid communication
between the removable pump assembly and the outlet when the
removable pump assembly is positioned in the pump cavity; and a
crossover flow path providing fluid communication between the inlet
flow path and the outlet flow path, the crossover flow path
bypassing the pump cavity, the valve system being capable of
directing fluid flow to the first flow path and to the crossover
flow path.
11. The system of claim 10, wherein the cross over flow path allows
fluid communication between the inlet flow path and the outlet flow
path when the boosting cap is removed from the pump assembly.
12. The system of claim 10, further comprising the removable pump
assembly engaging the pump cavity, the boosting cap being
positioned over the removable pump assembly.
13. The system of claim 12, wherein the pump assembly comprises a
spool adapter and one or more pumps supported by the spool
adapter.
14. The system of claim 13, wherein the pump assembly further
comprises a lower cavity for collecting contaminants, the lower
cavity being in fluid communication with the one or more pumps.
15. The system of claim 14, wherein a third flow path provides
fluid communication from the first flow path of the boosting cap to
the lower cavity and a fourth flow path provides fluid
communication from the lower cavity to the second flow path of the
boosting cap.
16. The system of claim 10, further comprising a pressure cap
sealing the pump cavity, the boosting cap being positioned over the
pump cavity and attached to the pressure cap, wherein the pump
cavity does not contain the removable pump assembly.
17. The system of claim 10, wherein the valve system comprises a
directional gate valve capable of directing fluid flow to the first
flow path and to the crossover flow path, the directional gate
valve comprising a slab gate capable of stopping fluid flow through
one of the crossover flow path and the first flow path while
simultaneously opening one of the first flow path and crossover
flow path.
18. The system of claim 10, wherein the boosting cap is attached to
a boosting cap flowbore connector, the boosting cap flowbore
connector providing fluid communication between the boosting cap
and the valve system.
19. The system of claim 18, wherein the boosting cap flowbore
connector comprises a portion of the valve system.
20. A method for removing a pump assembly positioned in a pump
cavity of a subsea boosting cap system having a crossover flow path
that bypasses the pump cavity, the method comprising: flowing a
production fluid through a boosting cap flow path to a pump
assembly; stopping the flow of fluid through the pump assembly;
removing the boosting cap positioned over the pump assembly;
removing the pump assembly from the pump cavity; replacing the
boosting cap over the pump cavity; and flowing the fluid through
the crossover flow path while the pump assembly is removed from the
pump cavity.
21. The method of claim 20, further comprising directing the flow
of fluid through the crossover flow path while the boosting cap is
removed.
22. The method of claim 20, further comprising positioning a
pressure cap over the pump cavity, in addition to replacing the
boosting cap, after the pump assembly is removed.
23. The method of claim 20, further comprising engaging a second
pump assembly in the pump cavity after the first pump assembly is
removed.
24. The method of claim 23, further comprising diverting the flow
of fluid through the second pump assembly after engaging the second
pump assembly, the fluid in the pump assembly flowing down into a
settling cavity for removing contaminants and then flowing back up
through the second pump assembly and into the boosting cap.
25. The method of claim 20, wherein the removing the pump assembly
and the removing the boosting cap occur simultaneously.
Description
RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional Patent
Application 61/122,001, filed Dec. 12, 2008, and entitled SUBSEA
BOOSTING CAP SYSTEM, the disclosure of which is hereby incorporated
by reference in its entirety.
BACKGROUND
[0002] 1. Field of the Disclosure
[0003] The present disclosure relates generally to a subsea system,
and in particular, to a subsea boosting cap system.
[0004] 2. Description of the Related Art
[0005] In fluid production subsea systems, it is common to adopt an
artificial lift method as a means to achieve economic viable levels
of crude oil production and/or improve the reservoir oil recovery.
A common method of artificial lift is the use of pumps, such as,
for example, Coaxial Centrifugal Pumps (CCPs), which enable
increased production rate results. However, current solutions often
employ CCPs made to be installed inside subsea wellheads or similar
constructions, which imposes a dimensional constraint in diameter.
This can result in completion hardware that is excessively
tall/large with more complex stack up construction, which could
reduce the system reliability and consequentially add some
environmental risks.
[0006] From a performance view point, this complexity in
construction can also result in a long and winding plumbing
arrangement, which can cause significant pressure losses with
potential detrimental consequences for the production flowrate,
resulting in negative financial implications for the oilfield
lifetime sustainability. Likewise, taking into consideration the
required space on offshore vessels, a heavy, long and/or large pump
arrangement adds more difficulties and risks for the installation
and intervention activities as well as for onboard repairs. This
can result in larger deployment vessels and thus more expensive
offshore operations. It can also result in increased risk to the
environment due to increased potential leakage paths. These
concerns can be especially problematic in deep water fields where
the extreme underwater environment can complicate installation
and/or repair of subsea equipment, thus resulting in longer
shutdown periods and higher costs.
SUMMARY
[0007] The present disclosure is directed to overcoming, or at
least reducing the effects of, one or more of the issues set forth
above. For example, the present disclosure can provide one or more
of the following advantages: reduced installation costs; reduced
operating or equipment costs; increased production rates by
reducing the pressure losses across the flow path; reduced
equipment size and/or weight; and reduced environmental risks.
[0008] An embodiment of the present disclosure is directed to an
offshore fluid production system. The system comprises a subsea
wellbore at a first position on an ocean floor. A subsea boosting
cap system is positioned in a second position on the ocean floor
that is different from the first position. The subsea boosting cap
system comprises an anchor assembly capable of attaching to the sea
floor, the anchor assembly comprising a pump cavity capable of
receiving a removable pump assembly. The boosting cap system
further comprises a valve system attached to the anchor assembly.
The valve system comprises an inlet flow path and an outlet flow
path, the inlet flow path being in fluid communication with the
subsea wellbore. The boosting cap system further comprises a
boosting cap covering the pump cavity. The boosting cap comprises a
first flow path configured to provide fluid communication between
an inlet flow path and the removable pump assembly when the
removable pump assembly is positioned in the pump cavity. A second
flow path provides fluid communication between the removable pump
assembly and the outlet flow path when the removable pump assembly
is positioned in the pump cavity. The boosting cap system also
comprises a crossover flow path providing fluid communication
between the inlet flow path and the outlet flow path. The crossover
flow path bypasses the pump cavity. The valve system is capable of
directing fluid flow to the first flow path and the crossover flow
path. A downflow production line can be in fluid communication with
the outlet flow path of the boosting cap system.
[0009] Another embodiment of the present disclosure is directed to
a subsea boosting cap system. The system comprises an anchor
assembly capable of attaching to the sea floor. The anchor assembly
comprises a pump cavity capable of receiving a removable pump
assembly. A valve system is attached to the anchor assembly. The
valve system comprises an inlet flow path and an outlet flow path,
the inlet flow path being capable of fluidly communicating with a
subsea wellbore. A boosting cap covers the pump cavity. The
boosting cap comprises a first flow path configured to provide
fluid communication between the inlet flow path and the removable
pump assembly when the removable pump assembly is positioned in the
pump cavity. A second flow path provides fluid communication
between the removable pump assembly and the outlet when the
removable pump assembly is positioned in the pump cavity. A
crossover flow path provides fluid communication between the inlet
flow path and the outlet flow path, the crossover flow path
bypassing the pump cavity. The valve system is capable of directing
fluid flow to the first flow path and to the crossover flow
path.
[0010] Yet another embodiment of the present disclosure is directed
to a method for removing a pump assembly positioned in a pump
cavity of a subsea boosting cap system having a crossover flow path
that bypasses the pump cavity. The method comprises flowing a
production fluid through a boosting cap flow path to a pump
assembly. The flow of fluid through the pump assembly is stopped.
The boosting cap positioned over the pump assembly can be removed.
The pump assembly can be removed from the pump cavity. The boosting
cap can be replaced over the pump cavity. The fluid can be flowed
through the crossover flow path while the pump assembly is removed
from the pump cavity.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] FIG. 1 illustrates an offshore fluid production system,
according to an embodiment of the present disclosure.
[0012] FIG. 2 illustrates the offshore fluid production system of
FIG. 1 where the pump assembly has been removed, according to an
embodiment of the present disclosure.
[0013] FIGS. 3A and 3B illustrate a directional valve for directing
fluid, according to an embodiment of the present disclosure.
[0014] FIG. 4 illustrates an offshore fluid production system
comprising a subsea boosting cap system, according to an embodiment
of the present disclosure.
[0015] FIG. 5 illustrates an offshore fluid production system in
which the subsea boosting cap system is configured to have a flow
line connection via a double locking connection system, according
to an embodiment of the present disclosure.
[0016] FIG. 6 illustrates an embodiment of an offshore fluid
production system in which the subsea boosting cap system is
configured to have a flow line connection via a post connection
system, according to an embodiment of the present disclosure.
[0017] FIG. 7 illustrates a flowchart of a method for removing a
pump assembly, according to an embodiment of the present
disclosure.
[0018] While the disclosure is susceptible to various modifications
and alternative forms, specific embodiments have been shown by way
of example in the drawings and will be described in detail herein.
However, it should be understood that the disclosure is not
intended to be limited to the particular forms disclosed. Rather,
the intention is to cover all modifications, equivalents and
alternatives falling within the spirit and scope of the invention
as defined by the appended claims.
DETAILED DESCRIPTION
[0019] FIG. 1 illustrates an offshore fluid production system 100,
according to an embodiment of the present disclosure. Offshore
fluid production system 100 includes a subsea wellbore 102
positioned on the ocean floor 104. A subsea boosting cap system 106
is in a different position on the ocean floor 104, such as adjacent
to, or some distance away from, the subsea wellbore 102. Subsea
boosting cap system 106 can be attached to a downflow production
line 108, through which oil can flow to any suitable desired
downstream location, such as an oil platform at the surface.
[0020] The subsea boosting cap system 106 can include an anchor
assembly 110 capable of securing the system to the sea floor.
Anchor assembly 110 can be the structural foundation of the system,
providing the mechanical support and stability on the mudline sea
floor. Anchor assembly 110 can also provide the system vital
interlinks and structural basis to receive the inlet and outlet
flowline connections, power connections and hydraulic connections
for system monitoring and operability.
[0021] The anchor assembly 110 can be any suitable type of anchor
assembly known in the art. In an embodiment of FIG. 1, anchor
assembly 110 can include an upper frame 112 that can comprise
operational interfaces, such as a pump cavity 114 that is capable
of engaging a removable pump assembly 116. Anchor assembly 110 can
also include a lower frame 118.
[0022] In an embodiment, lower frame 118 can be shaped in a manner
so as to provide the ability to form a hydro cushion effect when
the frame starts to embed into the sea bed. Lower frame 118 can
further provide differential pressure when the suction process is
started, causing the hydrostatic head to push down the structure
into the sea bed until a desired depth is achieved. In an
embodiment, the shape of lower frame 118 can be, for example, an
upside-down cupped shape forming an enclosed space 120. An opening
122 is formed by lower frame 118 at an end of enclosed space 120,
which is designed to allow lower frame 118 to be embedded in the
sea floor via a suction force. A suction anchoring tube 124 can be
connected to a stab or other conduit (not shown) that can provide a
fluid pathway for providing the desired suction to the enclosed
space 120 through lower frame 118.
[0023] While the above described embodiment employs suction to
provide a desired anchor to the sea floor, any other suitable
technique for anchoring a structure to the sea floor can be
employed in place of or in addition to the anchoring structure of
FIG. 1. One of ordinary skill in the art would readily be able to
design and implement alternative anchoring structures.
[0024] Subsea boosting cap system 106 can include a valve system
126 attached to the anchor assembly 110 and to a boosting cap 162.
Valve system 126 comprises an inlet 128 and an outlet 130. Inlet
128 can be in fluid communication with the subsea wellbore 102 via
a production jumper 132. Outlet 130 can be in fluid communication
with the downflow production line 108 via a production jumper
134.
[0025] Production jumpers 132 and 134 can be attached to the inlet
128 and outlet 130 by any suitable connectors 133, which can be,
for example, guide and hinge over connecting devices. An example of
a suitable guide and hinge over connecting device is disclosed in
WO2008/063080 A1, entitled A CONNECTOR MEANS, by MOGEDAL, Knut et
al. and published on May 29, 2008, the disclosure of which is
hereby incorporated by reference in its entirety. Other suitable
connectors 133 include clamp type devices that can be locked by ROV
with a torque tool, hydraulically actuated devices, mechanically
actuated devices and/or electrically actuated devices.
[0026] Valve system 126 can comprise one or more valves for
controlling the flow of fluid through the subsea boosting cap
system 106. Any suitable type of valves can be employed. In an
embodiment, isolation valves 136 and directional valves 138 can be
employed. Isolation valves 136 can be capable of stopping or
starting fluid flow through a given flow path. The function of the
isolation valves 136 can generally be classified as the tertiary
barrier of the overall offshore fluid production system 100,
because they are often located in the intermediary position of the
subsea field lay out.
[0027] Directional gate valves 138 are capable of switching flow
from one flow path to another, as discussed in detail below. FIGS.
3A and 3B illustrate a directional valve 138, according to an
embodiment of the present disclosure. Directional valve 138
comprises a gate 140 set in a valve body 142 comprising upper valve
seats 144 and lower valve seats 146. The gate 140 is the on/off
element of the system and can seal against the seats 144 and 146.
Gate 140 can be any suitable gate, such as a slab gate, a
cylindrically shaped gate or any other suitable gate that can
function to direct the flow of water through the desired flow path.
In an embodiment, the gate 140 can be a slab with flat sides and
having a rectangular or square cross-section. A bore 147 can be
positioned in the gate 140 to allow fluid flow therethrough. The
gate 140 can traverse back and forth in gate chamber 159 so as to
position bore 147 to provide the ability to select a desired flow
direction.
[0028] In an embodiment, the valve body 142 can be the main
structural member of the system. For example, valve body 142 can
integrate all components to provide structural capacity, flow path
integrity, and pressure containing capability. In an embodiment,
valve body 142 has a dual bore passage configuration which provides
the ability to divert the flow according to the position of gate
140. In other embodiments, valve body 142 can have three or more
passages. Examples of such embodiments are disclosed in Co-pending
U.S. Patent Application No. _[Atty Docket No. AKER.022U]_, the
disclosure of which is hereby incorporated by reference in its
entirety.
[0029] The upper valve seats 144 and the lower valve seats 146
physically engage the gate 140 and the valve body 142 so as to
provide sealing capability on both sides of gate 140 around both
flow paths 155 and 157. In this design concept, the valve seats 144
and 146 can provide isolation between the dual flow paths 155 and
157.
[0030] A bonnet assembly 154 can enclose a stem 150 and stem seal
packing 152. The stem 150 can be the physical link between an
actuator 151 and the gate 140. Actuator 151 can be any suitable
actuation system. Such actuations systems are well known in the
art. The stem 150 can act as a dynamic barrier of the system,
connecting the gate 140 to the actuator 151 to provide the valve
functional motion. While the bonnet assembly 154 is illustrated
with a single stem 150, any suitable number and type of actuators
can be employed, such as one or more hydraulic, manual, electrical
and ROV operated actuators. Bonnet 154 can provide structural
retention for the dynamic sealing around the stem 150, as well as
structural strength to mount an actuation system of any type.
[0031] In an embodiment, directional valve 138 can comprise a
single gate 140 activated by a single actuator. In other
embodiments, multiple gates and/or multiple actuators can be
employed. The gate 140 can either be made as one integral piece or
as an assembly of multiple parts, as desired. A sealing system (not
shown) between gate 140 and valve seats 144 and 146, as well as
between the valve seats and valve body 142, can include any
suitable type of sealing mechanism. For example, the sealing
mechanism can comprise a metal to metal type seal, or any other
suitable type of seal made of any suitable material.
[0032] Directional valve 138 can include a single inlet,
illustrated as flow path 153, and two outlets, flow paths 155 and
157, as illustrated in the embodiment of FIGS. 3A and 3B. Flow
paths 155 and 157 can fluidly communicate with the flow path 153
through a connecting flow configuration 161. The connecting flow
configuration 161 is positioned within gate valve 138 at a location
separate from gate 140. Other potential gate configurations can
also be employed. Examples of suitable gate configurations are
disclosed in Co-pending U.S. Patent Application No. _[Atty docket
No: AKER.022U]_, the disclosure of which is hereby incorporated by
reference in its entirety.
[0033] FIG. 3A illustrates directional valve 138 in a first
position for allowing fluid to flow through a flow path 155 and
simultaneously blocking fluid flow through a flow path 157. FIG. 3B
illustrates directional valve 138 in a second position, which
allows fluid to flow through flow path 157, while simultaneously
blocking fluid flow through the flow path 155. During operation,
the stem 150, which can be connected to an actuator 151, can force
gate 140 from the first position, shown in FIG. 3A, to the second
position shown in FIG. 3B, thereby simultaneously beginning fluid
flow through flow path 157 and stopping fluid flow through the flow
path 155.
[0034] Referring again to FIG. 1, the boosting cap 162 can be
positioned to cover the pump cavity 114. As mentioned above, pump
cavity 114 can contain a removable pump assembly 116. In an
embodiment, boosting cap 162 is attached directly to the removable
pump assembly 116 via any suitable manner, such as, for example,
via a hydraulic, mechanical, electrical, or ROV operated connector.
As will be discussed in greater detail below, the boosting cap 162,
removable pump assembly 116 and optionally some or all of the valve
system 126 can be configured to be removable from anchor assembly
110.
[0035] The boosting cap 162 is configured to allow fluid connection
with the valve system 126. In an embodiment, at least a portion of
the valve system 126 of FIG. 1 is attached to the boosting cap 162
so as to be removable from the anchor assembly 110 when the
boosting cap 162 is removed. For example, valve system 126 can
comprise a boosting cap flowbore connector 186 that is connected to
the boosting cap 162. Valve system 126 can also comprise a portion
137 that can be connected to the anchor assembly 110. The boosting
cap flowbore connector 186 and valve system portion 137 can be
coupled together and configured so as to be separable one from the
other. Thus, boosting cap flowbore connector 186 can be attached to
boosting cap 162 in a manner that allows it to be removed from the
anchor assembly 110 with the boosting cap 162, while valve system
portion 137 remains coupled to the anchor assembly 110. When
boosting cap 162 is positioned on anchor assembly 110, boosting cap
flowbore connector 186 and valve system portion 137 can be held
together by any suitable means, such as clamping device 139.
[0036] Boosting cap 162 comprises the first flow path 158, which
can be configured to provide fluid communication between the inlet
flow path 188 and the removable pump assembly 116 when removable
pump assembly 116 is positioned in pump cavity 114. Boosting cap
162 further comprises a second flow path 160, which is configured
to provide fluid communication between the removable pump assembly
116 and outlet flow path 189 when removable pump assembly 116 is
positioned in pump cavity 114.
[0037] In an embodiment, boosting cap 162 further comprises a
crossover flow path 156 configured to provide fluid communication
between the inlet flow path 188 and outlet flow path 189. This
configuration allows fluid flow from the subsea wellbore to bypass
the pump cavity 114 when desired, such as when removable pump
assembly 116 is removed from the pump cavity 114 for maintenance
and/or repair.
[0038] In an alternative embodiment, illustrated in FIG. 4 and
described in greater detail below, crossover flow path 156 is
positioned outside of the boosting cap 162, as indicated by the
dashed portion of the crossover flow path 156. This alternative
configuration allows flow through crossover flow path 156 when
boosting cap 162 is removed from the boosting cap system.
[0039] Referring again to FIG. 1, the removable pump assembly 116
of subsea boosting cap system 106 comprises one or more pumps 164
supported by a spool adapter 166. Pumps 164 can be any suitable
pump that can be employed for pumping fluids from a wellbore. One
example of a suitable pump is a coaxial centrifugal pump (CCP). One
or more pumps can be employed. Where pump assembly 116 includes
multiple pumps, the pumps can be arranged in series or parallel.
Although pumps 164 are shown in a side-by-side arrangement in FIG.
1, they can also be positioned on top of each other in a straight
aligned arrangement, similarly as shown in FIG. 4; or any other
suitable arrangement, depending on installation vessel, pump type
and available space.
[0040] The pumps 164 can be enclosed inside a suitable enclosure,
such as, for example, a canister 165. Canister 165 can provide
physical protection for the pumps 164 by providing structural
integrity and physical capability to withstand installation and
operational loads. Canister 165 can also act as a pressure barrier
to the environment.
[0041] The removable pump assembly 116 can include any suitable
means for providing power to the pumps 164, such as, for example, a
high voltage penetrator 174. In an embodiment, as illustrated in
FIG. 1, spool adapter 166 comprises high voltage penetrator 174,
which provides power to the pumps and flow passage between the
upstream and downstream sides of the pumping processing, thereby
enabling means to isolate and divert fluid flow via directional
valves (e.g., valve 138) and isolation valves (e.g., valves 136)
during periods of maintenance on the removable pump assembly. This
can keep the offshore fluid production system 100 in continuous or
near continuous operation during pump malfunction or maintenance
operations. The high voltage penetrator is capable of being
electrically coupled to any suitable power source connection. In
embodiments, the high voltage penetrator 174 can provide means for
physical connection of the power supply directly to the pump
assembly 116, thereby avoiding multiple power connections to
minimize possibility of failure.
[0042] While the high voltage penetrator 174 is illustrated at a
horizontal position by the side of the spool adapter 166, it can be
installed at any suitable position and be configured in any
suitable spatial arrangement with respect to the subsea boosting
cap system 106. For example, it can be positioned on an upper side
of the boosting cap 162 in a horizontal or vertical arrangement via
an ROV flying lead. ROV flying leads are well known in the art.
[0043] In an embodiment, pump assembly 116 can further include a
settling cavity 168 to accommodate deposition of contaminants, such
as debris and/or denser parts of the produced fluid. Fluid flow
path 158 is in fluid communication with settling cavity 168 via a
third fluid flow path 170. Fluid is pumped up from the settling
cavity through a fourth flow path 172, through second flow path 160
in the boosting cap 162, and then through outlet flow path 189 to
the outlet 130. Thus, settling cavity 168 can close the loop
between the third fluid flow path 170 and the fourth flow path
172.
[0044] The various portions of the pump assembly 116 can be
fastened together by any suitable manner that can provide the
desired seal integrity and physical capability to withstand
installation and operational loads. For example, clamps 175 can be
used to fasten both the spool adapter 166 and the settling cavity
168 to the canister 165, as illustrated in the embodiment of FIG.
1. Any other suitable fastening means can also be used. In an
alternative embodiment, two or more of the various portions of pump
assembly 116 can be manufactured as a single integral part.
[0045] The pump assembly 116 can employ seals to provide desired
protection from leakage into and out of the various connections
between the different parts of pump assembly 116. For example,
seals 178 can be employed for sealing the canister 165. Seals 180
can provide sealing around flow bores, such as the flow bore
connections between the canister 165 and the settling cavity 168.
Seals 178 and 180 can be any suitable type of seals, such as, for
example, metal-to-metal seals.
[0046] Periodic maintenance or replacement of the pump assembly 116
can involve removing the pump assembly 116 from the subsea boosting
cap system 106. If a spare pump assembly is available, the boosting
cap 162 and pump assembly 116 can be retrieved to the surface,
where the pump assembly 116 can be replaced by the spare pump
assembly. Then the boosting cap 162 and spare pump assembly can be
re-installed in the subsea boosting cap system 106.
[0047] FIG. 2 illustrates an embodiment employing a pressure cap
176 in the subsea boosting cap system 106 where the pump assembly
116 has been removed, according to an embodiment of the present
disclosure. As illustrated in FIG. 2, the pressure cap 176 can be
used to seal the pump cavity 114 in the absence of the removable
pump assembly 116. In an embodiment, the pressure cap 176 can be
attached to the boosting cap 162 by a connecting means 177. Any
suitable connecting means can be employed, such as, for example, a
hydraulic, mechanical, electrical or ROV operated connector. In an
embodiment, the design of the boosting cap 162, pressure cap 176
and spool adapter 166 (FIG. 1) can include the same hub interface,
thereby allowing the same running tool to be used to install all
three.
[0048] Thus, in situations where the subsea boosting cap system 106
is in bypass mode for a relatively long period of time, such as
where a spare pump assembly is not available, the boosting cap 162
can be attached to the pressure cap 176 to provide a double barrier
while the fluid production system 100 is under production mode
(e.g., while hydrocarbon fluids are flowing through crossover flow
path 156). Alternatively, it may be desirable to employ the
boosting cap system 106 in bypass mode for periods of time without
the pressure cap 176.
[0049] FIG. 4 illustrates another embodiment of an offshore fluid
production system 100 comprising a subsea boosting cap system 106,
as mentioned above. The subsea boosting cap system of FIG. 4
differs from the subsea boosting cap system of FIG. 1 in that the
valve system and crossover flow path of the FIG. 4 embodiment allow
retrieval of the boosting cap without stopping production during
the time period that the boosting cap is removed.
[0050] In the embodiment of FIG. 4, crossover flow path 156 is
positioned outside of the boosting cap 162. For example, the
crossover flow path 156 can be a conduit that is attached to the
outside of boosting cap 162 in a manner that will allow crossover
flow path 156 to be run in and connected together with the boosting
cap 162. Valve system 126 can be configured to direct fluid flow
through either the crossover path 156, so that it bypasses the
boosting cap 162, or through the first flow path 158.
[0051] In an embodiment of FIG. 4, the valves system 126 can be
configured so that isolation valves 136 remain with the anchor
assembly 110 to direct the flow when the boosting cap 162 is
removed. Directional valves, such as those illustrated in FIG. 3,
or any other suitable valves, can be employed in place of or in
addition to isolation valves 136 to direct the flow.
[0052] A boosting cap flowbore connector 186 can be attached to
boosting cap 162 in an embodiment of FIG. 4. The boosting cap
flowbore connector 186 is capable of engaging and locking onto
posts 167, thereby allowing the boosting cap 162 to attach to the
valve system 126 and anchor assembly 110. Boosting cap flowbore
connector 186 can be designed to unlock and disengage from posts
167 using, for example, a ROV or other suitable means, thereby
allowing remote removal of the boosting cap 162 from the anchor
assembly 110.
[0053] FIG. 5 illustrates an embodiment of the offshore fluid
production system 100 in which the subsea boosting cap system 106
is configured to have a flow line connection via a double locking
connection system 182. Double locking connection system 182 can be
deployed and locked onto the anchor assembly 110 via a guide post
184. The double locking connection system 182 can also be connected
to boosting cap 162 via a boosting cap flowbore connector 186,
which is capable of locking onto posts 167, similarly as described
above in the embodiment of FIG. 4. Seals 180 can be employed to
seal the flow bore connections. Any suitable type of seals can be
employed, such as, for example, metal-to-metal seals. Isolation
valves 136 can be used to close the flow paths 188 while the
boosting cap 162 is not in place in order to protect against
contamination of the environment by production fluid spills.
Production jumpers 132 and 134 can be flexible or rigid and can be
connected to the subsea wellbore 102, subsea boosting cap system
106 and downflow production line 108 via any suitable connector,
such as swivel joints (not shown) for better landing
flexibility.
[0054] FIG. 6 illustrates another embodiment of the offshore fluid
production system 100 in which the subsea boosting cap system 106
is configured to have a flow line connection via a post connection
system 190. Post connection system 190 can be deployed onto the
anchor assembly 110 via a post 192 received by a receptacle 194.
The post connection system 190 can also be connected to boosting
cap 162 via a boosting cap flowbore connector 186. Seals 180 can be
employed to seal the flow bore connections. Any suitable type of
seals can be employed, such as, for example, metal-to-metal seals.
Isolation valves 136 can be used to close the flow path 188 while
the boosting cap 162 is not in place in order to protect against
contamination of the environment by production fluid spills, as
well as to control the flow of production fluid through the system.
Production jumpers 132 and 134 can be flexible or rigid and can be
connected to the subsea wellbore 102, subsea boosting cap system
106 and downflow production line 108 via any suitable connector,
such as swivel joints, mentioned above, for better landing
flexibility.
[0055] As shown in the embodiment of FIG. 7, the present disclosure
can also be directed to a method for removing a pump assembly
positioned in a pump cavity of any of the subsea boosting cap
systems of the present disclosure having a crossover flow path that
bypasses the pump cavity. The method can include flowing a
production fluid through a boosting cap flow path to a pump
assembly, as shown at 202. Stopping the flow of fluid through the
pump assembly and removing the boosting cap positioned over the
pump assembly, as shown at 204,206. The pump assembly can also be
removed from the pump cavity, as shown at 208, either
simultaneously with or separately from the boosting cap. The
boosting cap can then be replaced over the pump cavity, as shown at
210.
[0056] In an embodiment, production fluid can be flowed through the
crossover flow path after the boosting cap is replaced, but while
the pump assembly is removed from the pump cavity, as shown at 212.
In another embodiment where a system such as that shown in the
embodiment of FIG. 4 is employed, production fluid can be flowed
through the crossover flow path even when the boosting cap is
removed, thereby allowing continuous or substantially continuous
flow of production fluid during servicing of the pump assembly.
[0057] In an embodiment, the method can include positioning a
pressure cap 176 over the pump cavity, in addition to replacing the
boosting cap, after the pump assembly is removed. As discussed
above, the pressure cap can provide a second barrier to help
prevent fluid spills while the pump assembly is removed.
[0058] For the offshore contingency where the pressure cap 176 is
used, the pressure cap 176 can be installed on the ocean surface,
such as onboard an intervention vessel. Alternatively, pressure cap
176 can be installed in a subsea operation. An example of a subsea
installation employing the pressure cap 176 can include the
following main steps: First, the pressure cap 176 can be run via a
running tool and deployed on a subsea boosting cap system
intervention receptacle (not shown), which can be used for holding
the cap 176 while the running tool removes the pump assembly 116.
The running tool can then lock and lift the boosting cap 162 and
removable pump assembly 116 to deploy it in a mudmatt receptacle
(also not shown), where the running tool releases the boosting cap
162 from the spool adapter 166 of the removable pump assembly 116.
At this point in time, new seals can be placed by an ROV on
flowline connection porches, as is well known in the art. After
that, the running tool can move and lock the boosting cap 162 onto
the pressure cap 176. The boosting cap/pressure cap assembly is
then positioned back into the pump cavity 114. The connection
system is then locked to the inlet and outlet connectors. The
running tool can then be locked onto the spool adapter 166 of the
pump assembly 116 that was removed from the pump cavity, and the
pump assembly 116 can be transported to the surface.
[0059] The systems of the present disclosure can be installed using
any suitable method. The following method provides one illustrated
example for anchoring the Suction Anchoring Structure. First, the
Suction Anchoring Structure can be prepared with a vent hatch
opened, as is well known in the art. Slings can be attached from
the Suction Anchoring to the vessel crane master, with a heave
compensator at a non-active mode. The suction anchoring system can
be lowered through the splash zone with the vent hatch open. Run
down toward the seabed can occur at any suitable speed, such as at
speeds of about 0.5 m/s. The suction anchoring system can be
stopped around 3 meters above the seabed and the heave compensator
can be placed at active mode. Run in speed can then be reduced as
desired (e.g., as slow as possible) when entering into the seabed,
while watching for correct alignment. After entering the seabed,
lowering can be continued until slack is produced in the slings.
Then an ROV can close the vent hatch and hook up a suction stab
into the suction anchoring tube. Suction can then be started to
force the frame down into the seabed until the final desired depth
is achieved.
[0060] While the systems of the present disclosure have generally
been shown as having a vertical configuration, one of ordinary
skill in the art would readily understand that the systems can also
be configured in any other direction, such as to have a horizontal
or angular configuration.
[0061] Although various embodiments have been shown and described,
the disclosure is not so limited and will be understood to include
all such modifications and variations as would be apparent to one
skilled in the art.
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