Note: Descriptions are shown in the official language in which they were submitted.
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EXPANDABLE LOCKOUT FOR A SUBSURFACE SAFETY VALVE
The invention relates to methods a~ld apparatus for locking a wellbore valve
in an open
position. More particularly, the invention relates to methods and apparatus
for
permanently locking a subsurface safety valve in an open position through the
use of
expandable tubulars.
For oil and gas wells, especially those that operate offshore, redundant
safety devices
typically include a valve located about 500 feet (152 m) below the ocean mud
line
sealably connected to the production tubing string through which production
fluids pass.
The valve, typically referred to as a subsurface safety valve, ensures that if
the fluid
conduit between the ocean floor and the platform is disrupted (by a passing
vessel for
instance) that the flow of production fluid from the sub-sea well head will be
cut off and
the ocean will not be contaminated with production fluid. If the subsurface
safety valve
malfunctions during its operational life, it may become necessary to
permanently lock
out the valve in an open position. This is particularly necessary when the
safety valve
has malfunctioned and closed, commonly due to a control line break or
hydraulic
chamber lealc. The most common type of subsurface safety valve in use in
subterranean
wells today is the "surface controlled subsurface safety valve", commonly and
hereinafter referred to as an SCSSV. SCSSVs are required by regulatory
agencies in all
offshore wells worldwide. SCSSVs may also be used in land wells where the risk
of
wellhead damage and uncontrolled blowout of the well is high. Examples of
subsurface
safety valves include flapper (as shown in Figure 6), ball (as shown in Figure
7), and
annulus type valves. Safety valves are typically actuated by a reciprocating
flow tube or
choke. In the case of a flapper type valve, the flapper pivots about a hinge
to close and
block the flow of fluid through the valve. In essence, SCSSVs are "normally
closed"
downhole valves which are operated by pressurized hydraulic fluid in a small
diameter
control Iine extending from an actuator integral to the valve to a control
panel on the
earth's surface. Pressure in the control line exerted by the control panel
holds the
SCSSV in the open position, permitting fluid to pass through the valve and to
the
surface of the well for collection. Disruption of that pressure for any reason
causes the
valve to close. For example, if a control line or hydraulic seal failure
occurs, loss of
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2
hydraulic pressure causes inadvertent closure of the flapper.
Valves, including SCSSVs; may be held in an open position by placing a spring
metal
band which expands from a contracted, run-in position to a radially enlarged
locking
position adjacent the flapper thereby holding the valve member open. For
example;
U.S. Pat. No. 4,577,694, discloses a running tool that holds a metal band
spring in the
collapsed position for placement in the well. When released , the spring
expands into
contact with the valve member, thereby holding it in the open position. One
disadvantage to a metal band spring is that hydrocarbons flowing past the
metal band
spring cause eddies and low pressure areas that can cause the spring to
inadvertently
collapse and flow upward with production. This action can permit the
"permanently
locked out" SCSSV to inadvertently shut, thereby stopping the flow of
hydrocarbons
from the well. This results in costly remedial workover operations and lost
production.
Other methods of locking out the SCSSV include incoiporation of a lockout
device
integrally into a valve actuating mechanism. However, this solution
complicates the
design and adds to the total cost of the valve. An example of this type of
lockout
mechanism is described in U.S. Patent No. 4, 624,315. Because of the high
degree of
reliability and longevity of modern SCSSVs, the need arises very infrequently
for locking
most SCSSVs open. Furthermore, the integral lock open mechanism has an adverse
effect on the reliability of the SCSSV by being continuously subjected to
subsurface well
conditions during normal operations. As such, it may be damaged, corroded or
stuck in
the retracted position, preventing a necessary lock open operation when
required.
Insertable locking devices far safety valves are also hampered by the physical
characteristics of wellbores. Wellbores and inside diameters thereof vary
greatly from
well to well. Also, the inside diameter of a wellbore may vary at different
depths. The
"drift" diameter of a wellbore refers to a maximum diameter of a length of bar
that will
pass unimpeded through the inside diameter of a wellbore. Any insertable
locking
device must therefore meet limitations in space inherent in a particular
wellbore.
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One attempt to compensate for variable physical characteristics of a wellbore
has been
to utilize expandable tubular technology. Both slotted and solid tubulars can
be
expanded in situ to enlarge a fluid path through the tubular and also to fix a
smaller
tubular within the inner diameter of a larger tubular therearound. Tubulars
are
expanded by the use of a cone-shaped mandrel or by an expansion tool with
expandable,
fluid actuated members disposed on a body and run into the wellbore on a
tubular
string. During expansion of a tubular, the tubular walls are expanded past
their elastic
limit. Examples of expandable tubulars include slotted screen, joints,
packers, and
liners. Figures la and 1b are perspective and cross-sectional views of an
exemplary
expansion tool 100 and Figure lc is an exploded view thereof. The expansion
tool 100
has a body 102 which is hollow and generally tubular with connectors 104 and
106 for
connection to other components (not shown) of a downhole assembly. The
connectors
104 and 106 are of a reduced diameter (compared to the outside diameter of the
longitudinally central body part 108 of the tool 100), and together with three
longitudinal flutes 110 on the central body part 108, allow the passage of
fluids between
the outside of the tool 100 and the interior of a tubular therearound (not
shown). The
central body part 108 has three lands 112 defined between the three flutes
110, each
land 112 being formed with a respective recess 114 to hold a respective roller
116.
Each of the recesses 114 has parallel sides and extends radially from the
radially
perforated tubular core 115 of the tool 100 to the exterior of the respective
land 112.
Each of the mutually identical rollers 116 is near-cylindrical and slightly
barreled. Each
of the rollers 116 is mounted by means of a bearing 118 at each end of the
respective
roller for rotation about a respective rotational axis which is parallel to
the longitudinal
axis of the tool 100 and radially offset therefrom at 120-degree mutual
circumferential
separations around the central body 108. The bearings 118 are formed as
integral end
members of radially slidable pistons 120, one piston 120 being slidably sealed
within
each radially extended recess 114. The inner end of each piston 120 (Figure
la) is
exposed to the pressure of fluid within the hollow core of the tool 100 by way
of the
radial perforations in the tubular core 115. In this manner, pressurized fluid
provided
from the surface of the well, via a tubular, can actuate the pistons 120 and
cause them to
extend outward and to contact the inner wall of a tubular to be expanded.
Therefore, a need exists to provide a method and apparatus for permanently
holding
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open the SCSSV by a mechanism which is entirely separate from the SCSSV
mechanism, and one which would not tend to flow out of position during
production
operations. Additionally, a need exists to provide a lockout sleeve device
utilizing
expandable tubular technology which can be subsequently inserted in the well
conduit
only when it becomes necessary to permanently lock the SCSSV in an open
position.
In one aspect of the invention, a locking assembly for a wellbore valve is
provided
comprising a cylindrical sleeve insertable into an interior of the valve.
After insertion
into the valve, the body is expanded into interference with a closing
mechanism of the
valve, thereby locking the valve in an open position.
In one embodiment, a method and apparatus for locking out a safety valve in a
wellbore
is provided in which a tubular, or a lockout sleeve, having an outer diameter
substantially equal to or less than a drift diameter of the wellbore and an
expansion tool
are placed in the wellbore. The safety valve is located and the lockout sleeve
and
expansion tool are landed adjacent the safety valve. With the valve in an open
position,
the lockout sleeve and the expansion tool are positioned within an inner
diameter
thereof. The expansion tool is energized causing extendable members therein to
extend
radially to contact an inner diameter of the lockout sleeve. The lockout
sleeve is
expanded into substantial contact with the inner diameter of the safety valve,
wherein
the inner diameter of the expanded lockout sleeve is substantially equal to or
greater
than the drift diameter of the wellbore.
In one embodiment, a method for locking out a safety valve in a wellbore is
provided in
which a tubular, or lockout sleeve, having an outer diameter substantially
equal to or
less than a drift diameter of the wellbore and an expansion tool are placed in
the
wellbore. The lockout sleeve and expansion tool are landed adjacent the safety
valve
and a flow tube disposed within the safety valve is located. With the valve in
an open
position, the lockout sleeve and the expansion tool are positioned within an
inner
diameter thereof. The expansion tool is energized causing extendable members
therein
to extend radially to contact an inner diameter of the lockout sleeve. The
lockout sleeve
is expanded into substantial contact with the inner diameter of the safety
valve adjacent
the flow tube, wherein the inner diameter of the expanded lockout sleeve is
substantially
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equal to or greater than the drift diameter of the wellbore.
In one embodiment, an apparatus for locking out a safety valve in a wellbore
is
provided having a tubular, or lockout sleeve, with an outer diameter
substantially equal
to or less than a drift diameter of the wellbore. Preferably, the lockout
sleeve has one or
more surface features. The lockout sleeve is made of a .ductile material and
the surface
features may be slots, holes, ovals, diamonds, perforations, or a combination
thereof.
Further, an inner diameter of the lockout sleeve is expandable to a diameter
substantially equal to or greater than the drift diameter of the wellbore.
According to an aspect of the present invention there is provided a lockout
sleeve for a
safety valve in a wellbore, comprising an expandable tubular having an initial
outer
diameter substantially equal to or less than a drift diameter of the wellbore,
wherein the
tubular is arranged to be expanded by means of an expansion tool.
Some preferred embodiments of the invention will now be described by way of
example
only and with reference to the accompanying drawings, in which:
Figure la is a perspective view of an expansion tool; _
Figure 1b is a perspective end view in section thereof;
Figure lc is an exploded view of the expansion tool;.
Figure 2 is a perspective view of an embodiment of an unexpanded lockout
sleeve
according to the invention;
Figure 3 is a perspective view of the embodiment shown in Figure 2 in an
expanded
state;
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Sa
Figure 4 is a section view of a flapper section of a subsurface safety valve
having an
expansion tool and an unexpended tubular disposed therein;
Figure S is a section view of the erilbodiment shown in Figure 4, wherein the
tubular is
expanded;
Figure 6 is a section view of a flapper, type surface controlled subsurface
safety valve,
having an expanded tubular according to an embodiment of the invention
disposed
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therein; and
Figure 7 is a section view of a ball type surface controlled subsurface safety
valve,
having an expanded tubular according to an embodiment of the invention
disposed
S therein.
Figure 2 is a perspective view of an embodiment of an unexpanded lockout
sleeve 10
according to the invention. The lockout sleeve 10 has a generally tubular body
having
an outer diameter (OD), an inner diameter (ID), and a predetermined length L1.
The
lockout sleeve 10 is preferably made of a ductile material having sufficient
properties to
resist forces designed to yield the lockout sleeve, yet able to plastically
and/or
elastically deform during application of such forces to a larger diameter
without
breaking or rupturing. Preferably, the lockout sleeve 10 has a plurality of
slots 16
formed in its wall 18. Alternatively, the lockout sleeve may be a solid
tubular without
any surface features or have a single longitudinal slot extending the length
(L1) of the
sleeve. The slots 16 are preferably arranged in a longitudinal pattern in an
overlapping
fashion to facilitate expansion. However, it should be understood that the
slots 16 may
be any appropriate shape of configuration to enable the lockout sleeve 10 to
expand
with the application of a radial force. Other surface features include slits,
ellipses,
ovals, holes, perforations, irregular shapes, such as dog bone slots, or
combinations
thereof.
Prior to expansion of the lockout sleeve, the outside diameter 12 of the
lockout sleeve
10 is substantially equal to or less than the maximum diameter that will drift
to a desired
location in the wellbore. After expansion of the sleeve, the inside diameter
14 of the
lockout sleeve 10 is preferably greater than or equal to the drift diameter of
the
wellbore.
Figure 3 is a perspective view of an embodiment of an expanded lockout sleeve
10
according to the present invention. The expanded slots 16 form a diamond shape
as the
lockout sleeve 10 is expanded. In use, the expansion tool 100 is lowered into
the
wellbore (not shown) to a predetermined position and thereafter pressurized
fluid is
provided in the run-in tubular 130. In the preferred embodiment, some portion
of the
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fluid is passed through an orif ce or some other pressure increasing device
and into the
expansion tool 100 where the fluid urges the rollers 116 outwards to contact
the wall of
the tubular, or lockout sleeve 10, therearound. The expansion tool 100 exerts
forces
against the wall of the lockout sleeve 10 therearound while rotating and,
optionally,
moving axially within the wellbore. The result is the lockout sleeve is
expanded past its
elastic limits along at least a portion of its outside diameter. Gravity and
the weight of
the components urges the expansion tool 100 downward in the wellbore even as
the
rollers 116 of the expander tool 100 are actuated. The expansion can also take
place in
a "bottom up" fashion by providing an upward force on the run-in tubular
string. A
tractor (not shown) may be used in a lateral wellbore or in some other
circumstance
when gravity and the weight of the components are not adequate to cause the
actuated
expansion tool 100 to move downward along the wellbore. The run-in string of
tubulars
may include coiled tubing and in that instance, a mud motor may be utilized
adjacent
the expansion tool to provide rotational force to the tool. The structure of
mud motors
is well known. The mud motor can be a positive displacement Moineau-type
device
and includes a Iobed rotor that turns within a lobed stator in response to the
flow of
fluids under pressure in the coiled tubing string. The mud motor provides
rotational
force to rotate the expansion tool in the wellbore while the rollers are
actuated against
an inside surface of a tubular therearound. Additionally, the run-in string
may be
replaced by wire (or e-line) line providing electrical energy to an electrical
motor and
also having the strength to hold the weight of the appartus in the wellbore.
In this
embodiment, the electrical motor runs a downhole pump providing a source of
pressurized fluid to an expander tool, tractor and/or a mud motor.
Figure 4 is a section view of a flapper section 34 of a subsurface safety
valve 39 having
an expansion tool 100 and an unexpanded lockout sleeve 10 disposed therein.
The
lockout sleeve 10 and expansion tool 100 are disposed on the end of a run-in
string 130,
or coil tubing, which may be used to provide hydraulic fluid to the expansion
tool 100.
The lockout sleeve 10 and expansion tool 100 are shearably connected and are
placed in
the wellbore as an assembly. The assembly is lowered to a desired location
within the
safety valve 39. The flapper section 34 of the safety valve 39 rotates about a
hinge pin
36 (shown in an open position). Once the assembly is located at the desired
location in
the wellbore, the flapper section 34 is opened by the downward force of the
assembly
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on the flapper section 34. Fluid pressure to actuate the rollers 116 of the
expansion tool
100 is provided from the surface of the well through the run-in string 130.
The rollers
116 are then actuated and extended radially outward to contact the inner
diameter 14 of
the lockout sleeve 10. The lockout sleeve 10 is then expanded into substantial
contact
with the inner diameter of the safety valve 39.
Figure 5 is a section view of the embodiment shown in Figure 4, wherein the
lockout
sleeve 10 is expanded into substantial contact with an inner diameter of the
safety valve
39. The lockout sleeve 10 in its expanded condition is substantially greater
than or equal
to the smallest inner diameter of the safety valve 39 or a tubular (not shown)
disposed
between the safety valve 39 and the wellbore. This allows the locked out
safety valve
39 to maintain its full open inner diameter and ensure that no flow capacity
is lost with
the addition of the lockout sleeve.
Figure 6 is a section view of a flapper type surface controlled subsurface
safety valve
30, having an expanded lockout sleeve 10 disposed therein. Hydraulic fluid is
provided
to the safety valve 30 via a control line 34 operated by a control panel 32 on
the earth's
surface. A valve operator 35, such as a rod piston, moves downward in response
to
increasing fluid pressure in the control line 34. A flow tube 40 moves
downward in
tandem with the movement of the valve operator 35, thereby opening the flapper
34. A
return means 38, such as a spring, a gas charge, or a combination thereof,
biases the
safety valve 30 in the closed position by acting to urge the flow tube 40
upwards,
opposing the force of hydraulic pressure. Lowering (or loss of) the hydraulic
fluid
pressure in the control line 34 serves to move the flow tube 40 upwards
thereby closing
the safety valve 30. The lockout sleeve 10 has been expanded into a recess 42
above the
flow tube 40, thereby prohibiting an upward movement of the flow tube 40. This
causes
the flapper to remain in the open position, permanently locking out the safety
valve 30.
Figure 7 is a section view of a ball type surface controlled subsurface safety
valve,
having an expanded tubular according to the invention disposed therein. A
valve
operator 35, such as an annular piston, moves downward in response to
increasing fluid
pressure in the control line 34. A flow tube 40 moves downward in tandem with
the
movement of the valve operator 35, thereby rotating and opening the ball
closure
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mechanism 44. A return means 38, such as a spring, a gas charge, or a
combination
thereof, biases the safety valve 31 to the closed position by acting to move
the flow tube
40 upwards, opposing the force of hydraulic pressure. Reduced hydraulic fluid
pressure
in the control line 34 serves to move the flow tube 40 upwards thereby closing
the
safety valve 30. The lockout sleeve 10 has been expanded into a recess 42
above the
flow tube 40, thereby preventing any upward movement of the flow tube 40. This
causes the ball 44 to remain in the open position, permanently locking out the
safety
valve 30.
As illustrated by the forgoing, the present invention solves problems
associated with
wellbore valves, especially subsurface safety valves by providing an easy
means to
permanently opening the valves without substantially restricting the flow
capacity of the
valve.
