U.S. patent application number 12/772511 was filed with the patent office on 2011-01-13 for subsea control system.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Tauna Leonardi, Joseph D. Scranton, John Skaggs, John Yarnold.
Application Number | 20110005770 12/772511 |
Document ID | / |
Family ID | 43030781 |
Filed Date | 2011-01-13 |
United States Patent
Application |
20110005770 |
Kind Code |
A1 |
Scranton; Joseph D. ; et
al. |
January 13, 2011 |
SUBSEA CONTROL SYSTEM
Abstract
A technique enables protection of subsea wells. The technique
employs a subsea test tree and associated control system to ensure
control over the well in a variety of situations. The subsea test
tree may be formed with an upper portion releasably coupled to a
lower portion. The upper portion employs at least one upper
shut-off valve, and the lower portion employs at least one lower
shut-off valve to protect against unwanted release of fluids from
either above or below the subsea test tree. The subsea test tree
also is coupled with the control system in a manner which allows
control to be exercised over the at least one upper shut-often
valve and the at least one lower shut-off valve.
Inventors: |
Scranton; Joseph D.;
(Missouri City, TX) ; Yarnold; John; (League City,
TX) ; Leonardi; Tauna; (Pearland, TX) ;
Skaggs; John; (Pearland, TX) |
Correspondence
Address: |
SCHLUMBERGER RESERVOIR COMPLETIONS
14910 AIRLINE ROAD, Bldg. 14
ROSHARON
TX
77583
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
43030781 |
Appl. No.: |
12/772511 |
Filed: |
May 3, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61175266 |
May 4, 2009 |
|
|
|
Current U.S.
Class: |
166/363 ;
166/364; 166/368 |
Current CPC
Class: |
E21B 34/045
20130101 |
Class at
Publication: |
166/363 ;
166/368; 166/364 |
International
Class: |
E21B 34/02 20060101
E21B034/02; E21B 33/03 20060101 E21B033/03; E21B 34/04 20060101
E21B034/04 |
Claims
1. A subsea wellhead control system, comprising: a subsea test tree
having an upper part and a lower part connecting at a disconnect
point; the upper part comprising a retainer valve; the lower part
comprising a ball valve and a flapper valve; a control system for
controlling the actuation of the subsea test tree including the
retainer valve, the ball valve and the flapper valve; and a
pressure balanced accumulator associated with the control system
and in hydraulic communication with the subsea test tree.
2. The subsea wellhead control system as recited in claim 1,
wherein the pressure balanced accumulator comprises a housing
having a generally tubular-shaped member having first and second
ends.
3. The subsea wellhead control system as recited in claim 2,
wherein the pressure balanced accumulator further comprises an
accumulator mechanism located within the housing proximate the
first end of the housing wherein the accumulator mechanism
comprises a first chamber for receiving a pressurized gas at a
first pressure and a second chamber for receiving a first
pressurized fluid at a second pressure and where the first and
second chambers are hermetically sealed from one another.
4. The subsea wellhead control system as recited in claim 3,
wherein the pressure balanced accumulator further comprises a third
chamber in the housing which abuts one end of the accumulator
mechanism, where the third chamber contains an oil fluid.
5. The subsea wellhead control system as recited in claim 4,
wherein the pressure balanced accumulator further comprises a
movable piston which is located within the housing proximate the
second end of the housing, the movable piston having first and
second ends with first and second cross-sectional areas,
respectively, where the piston is movable between a first position
and a second position, wherein the second end of the housing
includes a port to permit ambient subsea pressure to impinge on the
first end of the piston, where the second end of the piston
contacts the third chamber, and where the cross-sectional areas of
the first and second ends of the piston are selected so as to
optimize the pressure in the second chamber at which the piston
begins to expel fluid from the second chamber of the
accumulator.
6. The subsea wellhead control system as recited in claim 1,
wherein the control system comprises surface components and subsea
components.
7. The subsea wellhead control system as recited in claim 1,
further comprising a blowout preventer stack independently
controlled with respect to the subsea test tree.
8. The subsea wellhead control system as recited in claim 1,
further comprising at least one pipe ram.
9. The subsea wellhead control system as recited in claim 8,
further comprising at least one shear ram.
10. The subsea wellhead control system as recited in claim 1,
wherein the upper part and the lower part operate within a
riser.
11. The subsea wellhead control system as recited in claim 6,
wherein the control system comprises a programmable logic
controller.
12. A subsea control system, comprising: a subsea installation,
comprising: a blowout preventer; and a subsea test tree controlled
independently of the blowout preventer, the subsea test tree
comprising: a retainer valve located in an upper portion; at least
one valve located in a lower portion; and a latch mechanism
releasably coupling the upper portion to the lower portion.
13. The subsea control system as recited in claim 12, wherein the
at least one valve located in the lower portion comprises a ball
valve.
14. The subsea control system as recited in claim 13, wherein the
at least one valve located in the lower portion comprises a flapper
valve separated from the ball valve.
15. The subsea control system as recited in claim 14, further
comprising a control system coupled to the subsea test tree to
control actuation of the retainer valve, the ball valve and the
flapper valve.
16. The subsea control system as recited in claim 12, further
comprising a control system coupled to the subsea test tree and a
pressure balanced accumulator connected in cooperation with the
control system.
17. The subsea control system as recited in claim 16, wherein the
pressure balanced accumulator is operable to control the retainer
valve, located in the upper portion, and the at least one valve,
located in the lower portion.
18. The subsea control system as recited in claim 17, wherein the
pressure balanced accumulator comprises a movable piston to exert a
desired hydraulic supply pressure.
19. A method for controlling a subsea wellhead, comprising: forming
a subsea test tree with an upper portion, having at least one upper
shut-off valve, coupled to a lower portion, having at least one
lower shut-off valve; positioning the subsea test tree in a subsea
installation having separate emergency control features; coupling
the subsea test tree with a control system to control the at least
one upper shut-off valve and the at least one lower shut-often
valve; and utilizing a pressure balanced accumulator in cooperation
with the control system to supply pressurized fluid when
needed.
20. The method as recited in claim 19, wherein forming comprises
forming the upper portion with a retainer valve.
21. The method as recited in claim 20, wherein forming comprises
forming the lower portion with a ball valve.
22. The method as recited in claim 20, wherein forming comprises
forming the lower portion with a ball valve and a flapper
valve.
23. The method as recited in claim 19, wherein utilizing comprises
using a plurality of pressure chambers in cooperation with a
movable piston.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] The present document is based on and claims priority to U.S.
Provisional Application Ser. No. 61/175,266, filed May 4, 2009
incorporated herein.
BACKGROUND
[0002] A variety of subsea control systems are employed for use in
controlling subsea wells during, for example, emergency shutdowns.
Depending on the environment and location of a given subsea well,
various standards or protocols govern operation of the well. In
some applications, gas and oil wells are required to meet specific
safety integrity levels. Instrumented systems have been integrated
into subsea wells to ensure against unwanted discharge of fluids
into the surrounding subsea environment.
SUMMARY
[0003] In general, the present invention provides a technique for
enabling protection of subsea wells. The technique employs a subsea
test tree and associated control system to ensure control over the
well in a variety of situations. The subsea test tree may be formed
with an upper portion releasably coupled to a lower portion. The
upper portion employs at least one upper shut-off valve, and the
lower portion employs at least one lower shut-off valve to protect
against unwanted release of fluids from either above or below the
subsea test tree. The subsea test tree also is coupled with the
control system in a manner which allows control to be exercised
over the at least one upper and at least one lower shut-off
valves.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] Certain embodiments of the invention will hereafter be
described with reference to the accompanying drawings, wherein like
reference numerals denote like elements, and:
[0005] FIG. 1 is an illustration of one example of a subsea
installation and an associated control system, according to an
embodiment of the present invention;
[0006] FIG. 2 is an illustration of a portion of one example of a
subsea test tree that can be used at the subsea installation,
according to an embodiment of the present invention;
[0007] FIG. 3 is a schematic illustration of a portion of the
associated control system, according to an embodiment of the
present invention;
[0008] FIG. 4 is a schematic illustration of another portion of the
associated control system, according to an embodiment of the
present invention;
[0009] FIG. 5 is a schematic illustration of another portion of the
associated control system, according to an embodiment of the
present invention;
[0010] FIG. 6 is a schematic illustration of safety relevant
parameters topside and subsea, according to an embodiment of the
present invention;
[0011] FIG. 7 is a schematic illustration of one example of the
subsea control system incorporating a pressure balanced
accumulator, according to an embodiment of the present
invention;
[0012] FIG. 8 is a cross-sectional view of one example of the
pressure balanced accumulator illustrated in FIG. 7, according to
an embodiment of the present invention;
[0013] FIG. 9 is a cross-sectional view of an enlarged portion of
the pressure balanced accumulator illustrated in FIG. 8, according
to an embodiment of the present invention; and
[0014] FIG. 10 is a graph illustrating fluid volume expelled from
the pressure balanced accumulator at different hydrostatic pressure
levels, according to an embodiment of the present invention.
DETAILED DESCRIPTION
[0015] In the following description, numerous details are set forth
to provide an understanding of the present invention. However, it
will be understood by those of ordinary skill in the art that the
present invention may be practiced without these details and that
numerous variations or modifications from the described embodiments
may be possible.
[0016] The present invention generally relates to an overall subsea
control system comprising a subsea test tree, such as a subsea test
tree located within a riser, and an associated control. According
to one embodiment, the subsea control system is a subsea wellhead
control system comprising a subsea installation with an
independently controlled subsea test tree. The subsea test tree
comprises an upper portion separable from a lower portion and a
plurality of shut-off valves. At least one shut-off valve is
located in each of the upper portion and the lower portion.
[0017] The present technique and components, as described in
greater detail below, may be used in cooperation with existing
components and control systems. In one specific embodiment, for
example, the present technique may be employed with the SenTURIAN
Deep Water Control System manufactured by Schlumberger Corporation.
The system may be employed as a safety instrumented system as
defined by one or more applicable standards, such as IEC61508. In
this example, the IEC61508 standard is selected and covers
safety-related systems when such systems incorporate electrical,
electronic, or programmable electronic (E/E/PE) devices. Such
devices may include a variety of devices from electrical relays and
switches through programmable logic controllers (PLCs). The
standard is designed to cover possible hazards created when
failures of the safety functions performed by E/E/PE safety-related
systems occur. The international standard IEC61508, although
generic, is an example of a standard which is becoming more widely
accepted as a basis for the specification, design and operation of
programmable electronic systems in the petroleum production
industry.
[0018] Various control systems, e.g. deep water control systems,
are designed according to predetermined safety integrity levels
(SILs). In the description herein, SIL level determination is not
addressed, but instead SIL levels are discussed as outlined by the
Norwegian Petroleum Directorate for the safety functions carried
out by the system, e.g. SIL2. By definition, SIL2 ensures that the
safe failure fraction is between 90% and 99% assuming a hardware
fault tolerance of zero. SIL2 also implies that the probability of
failure on demand for dangerous undetected failures is between 0.01
and 0.001, thus resulting in a risk reduction factor of between 100
and 1000.
[0019] Referring generally to FIG. 1, a well system 20 is
illustrated, according to one embodiment of the present invention.
In the example illustrated, well system 20 is a subsea control
system comprising a subsea installation 22 which includes a
production control system 24 cooperating with a subsea test tree
26. The subsea installation 22 is positioned at a subsea location
28 generally over a well 30 such as an oil and/or gas production
well. Additionally, a control system 32 is employed to control
operation of the production control system 24 and subsea test tree
26. The control system 32 may comprise an integrated system or
independent systems for controlling the various components of the
production control system and the subsea test tree.
[0020] Although the production control system 24 and subsea test
tree 26 may comprise a variety of components depending on the
specific application and well environment in which a production
operation is to be conducted, specific examples are discussed to
facilitate an understanding of the present system and technique.
The present invention, however, is not limited to the specific
embodiments described. In one embodiment, production control system
24 comprises a horizontal tree section 34 having, for example, a
production line 36 and an annulus line 38. A blowout preventer 40,
e.g. a blowout preventer stack, may be positioned in cooperation
with the horizontal tree section 34 to protect against blowouts.
These components also comprise an internal passageway 42 to
accommodate passage of tubing string components 44 and related
components, such as a tubing hanger/running tool 46.
[0021] The production control system 24 also may comprise a variety
of additional components incorporated into or positioned above
blowout preventer 40. For example, at least one pipe ram 46 may be
mounted in subsea installation 22 at a suitable location. In
embodiment illustrated, two pipe rams 46 are employed. The system
also may comprise at least one shear ram 48, such as the two shear
rams illustrated. Additionally, one or more, e.g. two, annular rams
50 may be employed in the system. The various production control
systems 24 accommodate a riser 52 designed to receive subsea test
tree 26.
[0022] In the embodiment illustrated, the subsea test tree 26
comprises an upper portion 54 releasably coupled with a lower
portion 56 via a connector 58, such as a latch connector. The upper
portion 54 and the lower portion 56 each contain at least one
shut-off valve which may be selectively actuated to block flow of
production fluid through the subsea installation 22. The various
components of subsea installation 22 are designed to allow an
emergency shutdown. For example, subsea test tree 26 enables
provision of a safety system installed within riser 52 during
completion operations to facilitate safe, temporary closure of the
subsea well 30. The control system 32 provides hydraulic power to
the subsea test tree 26 to enable control over the shut-off valves.
Control over the subsea test tree 26 may be independent of the
safety functions of the production control system 24, such as
actuation of blowout preventer 40.
[0023] The shut-off valves in subsea test tree 26 may range in
number and design. In one embodiment, however, the upper portion 54
comprises a retainer valve 60, as further illustrated in FIG. 2. In
the specific embodiment illustrated, lower portion 56 comprises a
pair of valves in the form of a flapper valve 62 and a ball valve
64. As desired for a given application, other components may be
incorporated into subsea test tree 26. For example, the upper
portion 54 may comprise additional components in the form of a
space out sub 66, a bleed off valve 68, and a shear sub 70.
Similarly, the lower portion 56 may comprise additional components,
such as a ported joint 72 extending down to tubing hanger 46.
[0024] The shut-off valves may be controlled electrically,
hydraulically, or by other suitable techniques. In the embodiment
illustrated, however, valves 60, 62, 64 are controlled
hydraulically via hydraulic lines 74. For example, the position of
the valves 60, 62, 64 may be controlled via a combination of opened
or closed directional control valves 76 located in, for example, a
subsea control module 78. The directional control valve 76 control
whether hydraulic pressure is present or vented on its assigned
output port in the subsea test tree. The directional control valves
76 within subsea control module 78 may be controlled via solenoid
valves or other actuators which may be energized via electrical
signals sent from the surface. Accordingly, the overall control
system 32 for controlling subsea test tree 26 may have a variety of
topside and subsea components which work in cooperation.
[0025] During a specific valve operation, an operations engineer
may issue a command via a human machine interface 80 of a master
control station 82, such as a computer-based master control
station. In some applications, the master control station 82
comprises or works in cooperation with one or more programmable
logic controllers. Electric current is sent down through an
umbilical 84 to the solenoid valves and subsea control module 78 to
actuate directional control valves 76. The umbilical 84 also may
comprise one or more hydraulic control lines extending down to the
subsea control module from a hydraulic power unit 86. In the
embodiment illustrated in FIGS. 1 and 2, the hydraulic lines 74
also are routed to an accumulator 88, such as a subsea accumulator
module.
[0026] When a desired directional control valve 76 is opened,
hydraulic pressure supplied by hydraulic power unit 86 is passed
through its assigned output port to the subsea test tree 26.
Conversely, when a directional control valve 76 is closed, any
hydraulic pressure present at its output port is vented. Hydraulic
power is transferred from the subsea accumulator module 88 to a
particular valve 60, 62, 64 located in the subsea test tree 26. The
designated valve transitions and fulfills the intended safety
instrumented function for a given situation.
[0027] An emergency shutdown sequence may be achieved through a
series of commands sent to one or more of the valves 60, 62 and 64.
The emergency shutdown sequence may be designed to bring the
overall system to a safe state upon a given command. Depending on
the specific application, the emergency shutdown sequence also may
control transition of additional valves, e.g. a topside production
control valve, to a desired safety state.
[0028] If a complete loss of communication between the topside and
subsea equipment occurs, i.e. loss or severing of the umbilical 84,
the directional control valves 76 are designed to return to a
natural or default state via, for example, spring actuation. This
action automatically brings the well to a fail safe position with
the topside riser and the well sealed and isolated. If the topside
equipment is unable to bring the well into a safe state, then the
operator can institute a block-and-bleed on the hydraulic power
unit 86 to cause the subsea test tree to transition into its
failsafe configuration. Additionally, visual and/or audible alerts
may be used to alert an operator to a variety of fault or potential
fault situations.
[0029] In the specific example illustrated in FIG. 2, the subsea
test tree 26 has four basic functions utilizing retainer valve 60,
connector 58, flapper valve 62, and ball valve 64. The retainer
valve 60 functions to contain riser fluids in riser 52 after upper
portion 54 is disconnected from lower portion 56. The connector 58,
e.g. latch mechanism, enables the riser 52 and upper portion 54 to
be disconnected from the remaining subsea installation 22. The
flapper valve 62 provides a second or supplemental barrier used to
isolate and contain the subsea well. Similarly, the ball valve 64
is used to isolate and contain the subsea well as a first barrier
against release of production fluid.
[0030] The subsea test tree 26 may be used in a variety of
operational modes. For example, the subsea test tree 26 may be
transition to a "normal mode". In this mode, a standard emergency
shutdown sequence may be used in which a ball valve close function
is performed to close ball valve 64. By way of example, the ball
valve 64 may be closed by supplying hydraulic fluid at a desired
pressure, e.g. 5 kpsi. Another mode is employed as the subsea test
tree system is run in hole or pulled out of hole (RIH/POOH mode).
In this mode, the valve functions are disabled to prevent a
spurious unlatch at connector 58 while the assembly is suspended in
riser 52. In another example, the system is placed in a "coil
tubing" mode when coil tubing is present in riser 52 while a
disconnect is to be initiated. In this mode, the ball valve is
actuated under a higher pressure, e.g. 10 kpsi, to enable severing
of the tubing via, for example, shear rams 48.
[0031] The control system 32 also may be designed to operate in a
diagnostic mode. The diagnostic mode is useful in determining the
integrity of the signal path as well as the basic functionality of
the subsea control module, including the solenoid valves and
directional control valves. In this mode, a selected current, e.g.
a 30 mA current, is delivered down each of the electric lines, e.g.
seven lines, within umbilical 84. Then, by verifying the voltage
required to drive this current, the impedance of the system can be
inferred. This current is insufficient to trigger a solenoid into
actuation, but the current may be used to verify various
operational parameters. Examples of verifying operational
parameters include: verifying delivery of power to the system from
an uninterruptible power supply; verifying the solenoid driver
power supply is functional; verifying performance of a programmable
logic controller; verifying that all connectors are intact; and
verifying solenoids have not failed in an open or shorted manner.
The diagnostic testing can be performed on command from a SCADA, or
as a self-diagnostic function at pre-determined time intervals
depending on results of a hazard and operability application.
[0032] Referring generally to FIGS. 3-5, a variety of subsea
control system functions/implementations are illustrated via
schematic block diagrams. In the embodiment illustrated in FIG. 3,
for example, control system 32 utilizes a surface based master
control system 82 comprising a programmable logic control system 90
to isolate topside flow output via a production wing valve 92. The
wing valve 92 may comprise a master valve, a downhole safety valve,
or another wing valve operated by the production control system. By
way of example, the overall system may be designed at an SIL3 level
while the subsea test tree employed in the subsea installation 22
is at an SIL2 level.
[0033] In the embodiment illustrated in FIG. 3, the topside wing
valve 92 is operated by a high pressure system through a solenoid
actuated valve 94 controlled via programmable logic controller 90
in master control system 82. The valve 94 is considered to be in a
safe state when it is in its closed position. To avoid problems if
programmable logic controller 90 fails to actuate the valve when
desired, the system may be designed to enable manual triggering of
the valve. Verification that wing valve 92 has been actuated can be
based on select parameters. For example, the verification may be
based on detection of actuation current delivered by the master
control system; detection of the actuation voltage required to
achieve the desired current (implied impedance); and/or operator
verification of the position of the wing valve via an appropriate
gauge or sensor.
[0034] In the specific example illustrated, programmable logic
controller 90 is coupled to an emergency shutdown panel 96.
Additionally, the programmable logic controller 90 comprises an
input module 98, a logic module 100, and an output module 102. The
programmable logic controller 90 may be powered by an
uninterruptible power supply 104, and the output module 102 may be
independently coupled to a power supply unit 106. The output module
102 controls actuation of solenoid valve 94 which, in turn,
controls delivery of hydraulic actuation fluid to wing valve 92.
Additional components may be positioned between solenoid valve 94
and wing valve 92 to provide an added level of control and safety.
Examples of such components comprise a supplemental valve 108 and
an air block 110.
[0035] A similar control technique may be used to control actuation
of retainer valve 60 in upper portion 54, as illustrated in FIG. 4.
In this example, the emergency shutdown sub-function begins at the
master control system 82 where the demand is initiated, however the
function does not include other initiating factors. The function
concludes with the retainer valve 60 closing with respect to riser
52. An appropriate SIL level for this sub-function may be SIL2.
Verification that retainer valve 60 has been actuated to a closed
position can be based on select parameters. For example, the
verification may be based on detection of actuation current
delivered by the master control system; detection of the actuation
voltage required to achieve the desired current (implied
impedance); detection of flow as measured by flow meters on the
hydraulic power unit 86; and/or measuring a pressure response with
transducers on the subsea accumulator module 88.
[0036] Another control technique/sub-function is used to isolate
subsea well 30 via the shut-off valves, e.g. valves 62, 64, in the
lower portion 56 of subsea test tree 26, as illustrated in FIG. 5.
In this specific example, two shut-off valves are utilized for the
sake of redundancy in the form of flapper valve 62 and ball valve
64, however one valve is sufficient to leave the subsea well 30 in
a safe state. In this example, the emergency shutdown sub-function
begins at the master control system 82 where the demand is
initiated, however the function does not include other initiating
factors. The function concludes with the flapper valve 62 and/or
ball valve 64 closing with respect to subsea well 30. An
appropriate SIL level for this sub-function may be SIL2.
Verification that at least one of the flapper valve 62 and ball
valve 64 has been actuated to a closed position can be based on
select parameters. For example, the verification may be based on
detection of actuation current delivered by the master control
system; detection of the actuation voltage required to achieve the
desired current (implied impedance); detection of flow as measured
by flow meters on the hydraulic power unit 86; and/or measuring a
pressure response with transducers on the subsea accumulator module
88.
[0037] The safety integrity levels (SILs) described herein are not
necessarily derived from a risk-based approach for determining SIL
levels as described in standard IEC61508. Instead, the SIL levels
sometimes are based on industry recognized standards for production
system safety functions. Based on the minimum SIL requirements for
each function as applies to the existing layers of protection, the
minimum SIL level for the various safety integrity functions, e.g.
the sub-functions outlined in FIGS. 3-5, may be selected as
SIL2.
[0038] Additionally, the subsea test tree 26 and its corresponding
shut-off valves 60, 62, 64 may be operated completely independently
with respect to operation of the production control system 24 which
is used during normal operations. In this case, the overall control
system 32 may comprise completely independent control systems for
the subsea test tree 26 and the production control system 24. The
subsea test tree 26 may be installed within the production control
system 24, e.g. inside a Christmas tree, during operation inside
the blowout preventer stack 40. In the event that the blowout
preventer 40 is required to close, the subsea test tree 26 is
sealed and disconnected from the string (separated at connector
58). This allows the upper portion 54 of the subsea test tree 26 to
be retracted so the blowout preventer rams can be closed without
interference.
[0039] If the upper portion 54 cannot be unlatched and retracted
during a subsea test tree failure mode, the shear rams 48 may be
operated to sever the tool and safely close the well. The blowout
preventer control system has no influence on the safety functions
of the subsea test tree system. One example of a closing pattern
comprises closing the upper retainer valve 60, followed by closure
of the lower ball valve 64 and subsequent closure of the flapper
valve 62. Once the upper production string is sealed via retainer
valve 60 and access to the wellbore is sealed via ball valve 64 and
flapper valve 62, the subsea test tree is disconnected and
separated at connector 58.
[0040] Specific safety relevant parameters may be selected
according to the system design, environment, and applicable
requirements in a given geographical location. However, one example
of a typical approach is illustrated in FIG. 6 as having a safe
failure fraction exceeding 90% on the topside for a Type B safety
system (complex) and a hardware fault tolerance of zero, per
standard IEC61508-2. At the subsea location, the system comprises a
Type A subsystem having a safe failure fraction greater than 60%
and a hardware fault tolerance of zero. Final elements on the
topside may be evaluated to the DC fault model per IEC61508-2
(fault stuck at Vcc and stuck at Gnd, as well as stuck open and
stuck shorted). Final elements in the subsea portion of the system
are evaluated as a Type A system because only discrete passive
components are used. All failure modes of these components are well
defined and sufficient field data exists to be able to assume all
fault conditions.
[0041] The accumulator module 88 may be incorporated into the
overall system in a variety of configurations and at a variety of
locations. In one example, accumulator module 88 is a pressure
balanced accumulator to provide hydraulic power to the system in
case of emergency closure and disconnect and/or loss of hydraulic
power from the surface.
[0042] Accumulators are devices that provide a reserve of hydraulic
fluid under pressure and are used in conventional
hydraulically-driven systems where hydraulic fluid under pressure
operates a piece of equipment or a device. The hydraulic fluid is
pressurized by a pump that maintains the high pressure
required.
[0043] If the piece of equipment or the device is located a
considerable distance from the pump, a significant pressure drop
can occur in the hydraulic conduit or pipe which is conveying the
fluid from the pump to operate the device. Therefore, the flow may
be such that the pressure level at the device is below the pressure
required to operate the device. Consequently, operation may be
delayed until such a time as the pressure can build up with the
fluid being pumped through the hydraulic line. This result occurs,
for example, with deep water applications, such as with subsea test
tree and blowout preventer equipment used to shut off a wellbore to
secure an oil or gas well from accidental discharges to the
environment. Thus, accumulators may be used to provide a reserve
source of pressurized hydraulic fluid for this type of equipment.
In addition, if the pump is not operating, accumulators can be used
to provide a reserve source of pressurized hydraulic fluid to
enable the operation of a piece of equipment or device.
[0044] Accumulators may include a compressible fluid, e.g., gas,
nitrogen, helium, air, etc., on one side of a separating mechanism,
and a non-compressible fluid (hydraulic fluid) on the other side.
When the hydraulic system pressure drops below the precharged
pressure of the gas side, the separating mechanism will move in the
direction of the hydraulic side displacing stored hydraulic fluid
into the piece of equipment or the device as required.
[0045] When some types of accumulators are exposed to certain
hydrostatic pressure, such as the hydrostatic pressure encountered
in subsea operations, the available hydraulic fluid is decreased
since the hydrostatic pressure must first be overcome in order to
displace the hydraulic fluid from the accumulator. However,
pressure balanced accumulators may be employed to overcome the
above-described shortcomings. Examples of pressure-balanced
accumulators are disclosed in U.S. Pat. No. 6,202,753 to Benton and
U.S. Patent Publication No. 2005/0155658-A1 to White.
[0046] Referring generally to FIG. 7, an example of one
implementation of accumulator module 88 is illustrated. In this
example, accumulator module 88 is a pressure balanced accumulator
system. The accumulator system 88 is connected with the one or more
hydraulic lines 74 routed between hydraulic power unit 86 and
subsea test tree 26. Hydraulic power unit 86 may comprise one or
more suitable pumps 110 for pumping hydraulic fluid. The hydraulic
power unit 86 is located above a sea surface 111 and provides
control fluid for the operation of, for example, blowout preventer
40 and the valves 60, 62, 64 of subsea test tree 26. The
pressurized hydraulic fluid from hydraulic power unit 86 also is
used to charge the pressure balanced accumulator system 88. By way
of example, the hydrostatic pressure P.sub.HS supplied by pump 110
is approximately 7500 psi, although other pressure levels may be
used.
[0047] Referring generally to FIGS. 8 and 9, one embodiment of a
pressure balanced accumulator 88 is illustrated. The illustrated
embodiment is readily utilized in conjunction with subsea test tree
26, production control system 24, and control system 32. As
illustrated, the pressure balanced accumulator 88 comprises a
housing 112, which is a generally tubular-shaped member having two
ends 114 and 116. An accumulator mechanism 118 is located within
the housing 112 proximate the first end 114. The accumulator
mechanism 118 comprises a first chamber 120 (see FIG. 9) for
receiving a pressurized gas at a first pressure. The pressurized
gas may, for example, be injected into chamber 120 through gas
precharge port 122. In one embodiment of the present invention, the
gas in the first chamber 120 is helium, and it is pressurized to
approximately 3500 psi, although other pressures may be used
depending on the specific application.
[0048] With further reference to FIGS. 8 and 9, accumulator
mechanism 118 also comprises a second chamber 124 for receiving a
first pressurized fluid at a second pressure. The pressure of the
fluid in chamber 124 is sometimes referred to as the "gauge
pressure." In one embodiment, liquid may be injected into chamber
124 via a seal stab port 126. The liquid injected into chamber 124
may be in the form of a water glycol mixture according to one
embodiment of the present invention. By way of example, the mixture
may be injected into chamber 124 at a pressure of approximately
5000 psi, although other pressures may be utilized in other
applications. Chambers 120 and 124 are hermetically sealed from one
another at regions 128 and 130.
[0049] The pressure balanced accumulator system 88 may further
comprise a third chamber 132 which abuts accumulator mechanism 118
in housing 112. Third chamber 132 contains a fluid, which may be
injected into chamber 132 via fluid fill port 134. In one
embodiment, the fluid injected into third chamber 132 is silicon
oil, which is selected for use because of its lubricity and because
it will not adversely affect seals 136 deployed to seal along one
end of chamber 132. Initially, the silicon fluid is not injected
into third chamber 132 under pressure. In operation, however, the
pressure of the fluid in chamber 132 tracks the pressure of the
fluid in second chamber 124, as described below.
[0050] Pressure balanced accumulator 88 also comprises a piston 138
which is located within the housing proximate the second end 116 of
housing 112. The piston 138 has a first end 140 and a second end
142 which have first and second cross-sectional areas,
respectively. In one embodiment, the cross-sectional areas of
piston ends 140 and 142 are circular in shape. Piston 138 is
movable between a first position, as shown in FIG. 8, and a second
position in which piston end 140 is stopped by a shoulder 144.
[0051] Housing end 116 also may comprise an ambient pressure port
146. When pressure balanced accumulator 88 is used in a subsea
environment, ambient pressure port 146 permits the ambient subsea
pressure to impinge on end 140 of piston 138.
[0052] In the illustrated embodiment, pressure balanced accumulator
system 88 also comprises an atmospheric chamber 148 which includes
an annular recess 150 formed between piston 138 and the wall of
housing 112; an axial cavity 152 which is formed by hollowing out a
portion of piston 138; and a passage 154 connecting annular recess
150 and axial cavity 152. This atmospheric chamber allows
differential pressure to exist across piston 138 which enables the
piston to start to move when an equilibrium pressure exists across
piston 138 as discussed below. In one embodiment, the pressure in
the atmospheric chamber is 14.7 psi, the volume of annular recess
150 is approximately 10 in.sup.3, and the volume of axial cavity
152 is approximately 200 in.sup.3.
[0053] In subsea applications, such as the subsea applications
described above, accumulator module 88 may be located in a subsea
environment to control the operation of an in-riser or open water
intervention system, such as subsea test tree 26 and associated
valves 60, 62, 64. The first and second chambers 120 and 124 in
accumulator mechanism 118 of pressure balanced accumulator system
88 are precharged prior to placement of pressure balanced
accumulator system 88 in the subsea environment. Pump 110, which is
located above the sea surface 111, provides the control fluid for
the operation of blowout preventer 40 and shut-off valves 60, 62,
64. The pump 110 also provides a charging input to second chamber
124 of accumulator mechanism 118 in pressure balanced accumulator
system 88.
[0054] For purposes of illustration, it can be assumed that the
hydrostatic pressure, P.sub.HS, in which pressure balanced
accumulator 88 is operating is 7500 psi, although other pressures
may be employed. This ambient pressure is communicated through
ambient pressure port 146 of accumulator system 88 and impinges on
end 140 of piston 138. The force acting on piston 138 at its end
140 is given by the formula:
F.sub.1=P.sub.HS.times.(the area of piston end 140). (1)
The force on end 142 of piston 138 is given by the formula:
F.sub.2=(P.sub.HS+5000).times.(the area of piston end 142). (2)
[0055] In one specific example of the present invention, piston
ends 140 and 142 are circular in cross-section and have
cross-sectional areas established by diameters of 3.375 inches and
2.688 inches, respectively, although the sizes are for purposes of
explanation only. At the hydrostatic pressure of 7500 psi, the
equilibrium pressure, P.sub.E, at which the piston 138 starts to
move is:
P E = 7500 ( 3.375 2.688 ) 2 = 11 , 824 lbf ( 3 ) ##EQU00001##
[0056] The gauge pressure P.sub.G at which the piston begins to
move is given by the formula:
P.sub.G=P.sub.E-P.sub.HS=11,824-7,500P.sub.G=4,324 psi (4)
[0057] In accordance with the present invention, the diameter of
piston ends 140 (D.sub.1) and 142 (D.sub.2) may be sized for
optimal efficiency at a predetermined hydrostatic pressure, using
the following formula:
D 1 = ( P HS + P C - S ) P HS D 2 ##EQU00002##
where P.sub.C is the pressure to which the second chamber of
accumulator mechanism 118 is charged, e.g., 5000 psi, and S is a
hydraulic safety factor which is an allowance given to prevent
instability in maximum hydrostatic conditions. For a hydrostatic
pressure of 7500 psi, S is approximately 500 psi. If D.sub.2=2.688
inches as in the above calculation with respect to equations (3)
and (4) then D.sub.4 according to equation (5) is 3.40 inches.
[0058] In FIG. 10, a graph is presented with a graph line 156
provided to illustrate the fluid volume of fluid expelled from the
accumulator mechanism 118 at a hydrostatic pressure of 7500 psi and
with D.sub.1 and D.sub.2 being 3.375 inches and 2.688 inches,
respectively. Graph lines 158, 160 and 162 illustrate fluid volume
expelled at hydrostatic pressures of 6500, 5500 and 4500 psi,
respectively.
[0059] The overall subsea control system 20 may be designed for use
in a variety of well applications and well environments.
Accordingly, the number, type and configuration of components and
systems within the overall system may be adjusted to accommodate
different applications. For example, the subsea test tree may
include different numbers and types of shut-off valves as well as a
variety of connectors, e.g. latch mechanisms, for releasably
connecting the upper and lower parts of the subsea test tree. The
production control system also may comprise various types and
configurations of subsea installation components. Similarly, the
control system 32 may rely on various topside and subsea components
which enable independent control over the subsea test tree and the
blowout preventer. In some applications, the control system
utilizes surface components which are computer-based to enable easy
input of commands and monitoring of subsea functions. As described
above, programmable logic controllers also may be employed and used
to carry out various sub-functions implemented in emergency
shutdown procedures. Various adaptations may be made to accommodate
specific environments, types of well equipment, applicable
standards, and other parameters which affect a given subsea well
application.
[0060] Although only a few embodiments of the present invention
have been described in detail above, those of ordinary skill in the
art will readily appreciate that many modifications are possible
without materially departing from the teachings of this invention.
Accordingly, such modifications are intended to be included within
the scope of this invention as defined in the claims.
* * * * *