U.S. patent application number 11/804829 was filed with the patent office on 2007-11-29 for method and apparatus for equalizing pressure with a wellbore.
Invention is credited to Patrick C. Hyde, Lary G. Ratliff, Tod Stephens.
Application Number | 20070272415 11/804829 |
Document ID | / |
Family ID | 38748465 |
Filed Date | 2007-11-29 |
United States Patent
Application |
20070272415 |
Kind Code |
A1 |
Ratliff; Lary G. ; et
al. |
November 29, 2007 |
Method and apparatus for equalizing pressure with a wellbore
Abstract
A method, assembly and apparatus for equalizing pressure around
a sealing device in a production or injection tree. The method
includes coupling a circulating assembly to an oil field tree and
forming an isolated region between a portion of the circulating
assembly, a portion of the tree and a sealing device within the
tree. Then, a circulating mechanism in the circulating assembly is
adjusted to create a flow path between the interior of the
circulating assembly and a location below the sealing device. When
the pressure below the sealing device has substantially equalized
with the pressure within the interior of the circulating assembly,
the sealing device is removed through the circulating assembly.
Further, remediation and production operations may be performed on
wellbore tools or a subsurface formation below the tree.
Inventors: |
Ratliff; Lary G.; (Columbus,
TX) ; Stephens; Tod; (Chickasha, OK) ; Hyde;
Patrick C.; (Hurst, TX) |
Correspondence
Address: |
EXXONMOBIL UPSTREAM RESEARCH COMPANY
P.O. BOX 2189
(CORP-URC-SW 341)
HOUSTON
TX
77252-2189
US
|
Family ID: |
38748465 |
Appl. No.: |
11/804829 |
Filed: |
May 21, 2007 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
60802924 |
May 24, 2006 |
|
|
|
Current U.S.
Class: |
166/368 |
Current CPC
Class: |
E21B 33/035 20130101;
E21B 2200/06 20200501 |
Class at
Publication: |
166/368 |
International
Class: |
E21B 33/035 20060101
E21B033/035 |
Claims
1. A pressure equalizing apparatus for use with an oil field tree
comprising: a first tubular member having a first end, a second
end, at least one first tubular opening and a central opening
within the first tubular member to provide a longitudinal fluid
flow path between the first end and the second end; a circulating
mechanism coupled to the first tubular member and having a
circulating position and an isolating position, wherein the
circulating position provides at least one radial flow path between
the central opening and a region external to the first tubular
member through one or more of the at least one first tubular
opening and the isolating position prevents fluid flow between the
central opening and the region external to the first tubular
member, and further wherein the inner diameter of the apparatus is
adapted to pass a sealing device through the apparatus.
2. The apparatus of claim 1 wherein the first tubular member has a
differential pressure rating up to about 15,000 pounds per square
inch.
3. The apparatus of claim 1 wherein the apparatus has a torque
rating of up to about 50,000 foot-pounds.
4. The apparatus of claim 1 wherein the inner diameter of the
apparatus is in a range between about 4.7 inches and about 10
inches.
5. The apparatus of claim 1 wherein the outer diameter of the
apparatus is in a range between about 113/4 inches and 183/4
inches.
6. The apparatus of claim 1 wherein the length of the apparatus is
less than or equal to about 215 inches in the circulating
position.
7. The apparatus of claim 1 wherein the first tubular member
comprises at least one slot and the circulating mechanism comprises
at least one guide member at least partially disposed within the at
least one slot, wherein the at least one guide member is configured
to provide the at least one radial flow path in the circulating
position and prevent fluid flow in the isolating position.
8. The apparatus of claim 7 wherein the at least one slot comprises
a straight slot and a "J" slot.
9. The apparatus of claim 1 wherein the first tubular member
comprises at least one slot and the circulating mechanism comprises
a guide member at least partially disposed within the at least one
slot, wherein the guide member is configured to move between the
circulating position and the isolating position.
10. The apparatus of claim 1 wherein the circulating mechanism is
mechanically actuated.
11. The apparatus of claim 1 wherein the circulating mechanism
comprises: a second tubular member at least disposed partially
within the first tubular member, the second tubular member having
at least one second tubular opening and a plurality of threads at
one end of the second tubular member opposite the end of the second
tubular member at least disposed partially within the first tubular
member; and a plurality of seals disposed between the first tubular
member and the second tubular member to isolate fluid flow through
the at least one first tubular opening and the at least one second
tubular opening in the isolating position.
12. The apparatus of claim 11 wherein the first tubular member
comprises at least one slot and the circulating mechanism comprises
a guide member that engages the at least one slot, wherein the
guide member is configured to align the at least one first tubular
opening and the at least one second tubular opening to provide the
at least one radial flow path in the circulating position and
misalign the at least one first tubular opening and at least one
second tubular opening in the isolating position.
13. The apparatus of claim 1 wherein the circulating mechanism
comprises: a second tubular member disposed partially around the
first tubular member, the second tubular member having at least one
second tubular opening and a plurality of threads at one end of the
second tubular member opposite the end of the second tubular member
disposed partially around the first tubular member; and a plurality
of seals disposed between the first tubular member and the second
tubular member to isolate fluid flow through the at least one first
tubular opening and at least one second tubular opening in the
isolating position.
14. The apparatus of claim 1 wherein the circulating mechanism is
hydraulically actuated.
15. The apparatus of claim 1 wherein the circulating mechanism
comprises: a second tubular member disposed adjacent to the first
tubular member and having at least one second tubular opening; a
plurality of isolation seals disposed between the first tubular
member and the second tubular member to isolate fluid flow through
the at least one first tubular opening and the at least one second
tubular opening in the isolating position; a piston disposed
between the first tubular member and the second tubular member;
wherein the piston is hydraulically actuated to move from the
isolating position to align the at least one first tubular opening
and the at least one second tubular opening to provide the at least
one radial flow path in the circulating position.
16. The apparatus of claim 1 wherein the circulating mechanism is
electrically actuated.
17. The apparatus of claim 1 wherein the circulating mechanism is
magnetically actuated.
18. The apparatus of claim 1 wherein one of splines, wedges and
screws prevent rotation of the first tubular member with respect to
the circulating mechanism beyond the circulating position and the
isolating position and the first tubular member and the circulating
mechanism are not rotationally fixed with respect to each other.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application No. 60/802,924, filed May 24, 2006.
FIELD OF THE INVENTION
[0002] This invention relates generally to an apparatus and method
for equalizing pressure with a wellbore for production, injection
and remediation operations. More particularly, this invention
relates to a wellbore apparatus and method for equalizing pressure
between a circulating tool and a location below a sealing device in
and/or associated with an oil field tree. This pressure
equalization may reduce potential damage within the wellbore when
the sealing device is removed through the circulating tool.
BACKGROUND
[0003] This section is intended to introduce the reader to various
aspects of art, which may be associated with exemplary embodiments
of the present invention, which are described and/or claimed below.
This discussion is believed to be helpful in providing the reader
with information to facilitate understanding of particular
techniques of the present invention. Accordingly, it should be
understood that these statements are to be read in this light, and
not necessarily as admissions of prior art.
[0004] The production of hydrocarbons, such as oil and gas, has
been performed for numerous years. However, when producing
hydrocarbons from subsurface or subsurface formations, it becomes
more challenging because of the location of the subsurface
formations. For example, some subsurface formations are located in
ultra-deep water and in remote locations. In these locations,
problems may occur within the wellbore that limit or prevent the
production of hydrocarbons from the subsurface formation. As a
result, the well may have remediation operations performed on one
or more of the intervals in the subsurface formation to enhance
production operations.
[0005] In certain environments, the ability to perform the
remediation operations may be difficult and expensive. In
particular, the hydrostatic pressure within a riser in deep water
environments may complicate the removal of a sealing device, such
as a plug, from within a subsea tree because of the pressure
differential around the sealing device. This may result in
abandonment of the well if the sealing device cannot be removed.
However, if the sealing device can be removed, the removal of the
sealing device may damage tools within the wellbore and/or the
subsurface formation if the sealing device is not removed properly.
That is, the pressure differential around the sealing device may
result in breaking wireline, loss of fluid to the formation and/or
loss of one or more of the intervals in the completion. As such,
removal of the sealing devices from a subsea tree may be
problematic.
[0006] Typically, procedures and processes require multiple days of
rig time to remove the sealing device properly. For example, a
typical procedure to remove a sealing device, such as a plug,
involves running and coupling a riser and blowout preventer (BOP)
to a subsea tree. Once installed, a landing string is run multiple
times into the riser to access and interact with the subsea tree.
These different runs may involve removing the tree cap, latching
the tubing hanger, using a nitrogen unit to lighten the column of
fluid within the riser to equalize pressure above and below the
plug, removing the plug if the pressure is equalized on both sides
of the plug, and rigging down the units. The time to perform these
plug removal operations may be about 100 hours of rig time.
[0007] Accordingly, the need exists for an efficient method and
apparatus to equalize pressure around sealing devices in a subsea
tree, such as a plug and/or packer. In particular, this apparatus
and method may be utilized in plug removal procedures to reduce the
time and cost associated with performing remediation operations for
subsurface formations.
[0008] Other related material may be found in at least U.S. Pat.
No. 6,612,368; U.S. Pat. No. 6,681,850; U.S. Pat. No. 6,840,494;
and U.S. Patent Application Publication No. 2004/0188083.
SUMMARY
[0009] In one embodiment, a pressure equalizing apparatus for use
with an oil field tree is described. The pressure equalizing
apparatus including a first tubular member having a first end, a
second end, at least one first tubular opening and a central
opening within the first tubular member to provide a longitudinal
fluid flow path between the first end and the second end. Further,
the pressure equalizing apparatus includes a circulating mechanism
coupled to the first tubular member and having a circulating
position and an isolating position, wherein the circulating
position provides at least one radial flow path between the central
opening and a region external to the first tubular member through
the at least one first tubular opening and the isolating position
prevents fluid flow between the central opening and the region
external to the first tubular member. The inner diameter of the
apparatus is adapted to pass a sealing device through the
apparatus. Further, the circulating mechanism may be mechanically,
electrically, magnetically or hydraulically actuated.
[0010] In a second embodiment, an assembly for equalizing pressure
is described. This assembly includes a blowout preventer having a
first central opening and adapted to couple to an oil field tree.
Further, the assembly includes a circulating assembly configured to
be disposed at least partially within the first central opening and
to engage the blowout preventer to form an isolated region between
a portion of the circulating assembly and at least a portion of the
interior of the blowout preventer. The circulating assembly has a
first end, a second end and a plurality of subassemblies coupled
together with a second central opening extending through the
interior of the plurality of subassemblies to provide a first flow
path between the first end and the second end. The plurality of
subassemblies includes a first connection subassembly at the first
end adapted to engage with the oil field tree; and a circulating
tool coupled to the first connection subassembly and having a
circulating position and an isolating position, wherein the
circulating position provides a second flow path between the second
central opening and the isolated region and the isolating position
prevents fluid flow between the second central opening and the
isolated region. Further, the plurality of subassemblies includes a
second connection subassembly at the second end adapted to engage
with landing string, wherein the circulating tool is coupled
between the first connection subassembly and the second connection
subassembly.
[0011] In a third embodiment, a method for equalizing pressure
around a sealing device is described. The method includes coupling
a circulating assembly to an oil field tree; forming an isolated
region between a portion of the circulating assembly, a portion of
the oil field tree and a sealing device within the oil field tree;
adjusting a circulating mechanism in the circulating assembly to
circulate fluid between the interior of the circulating assembly
and a location below the sealing device; removing the sealing
device through the circulating assembly when the pressure at the
location has substantially equalized with the pressure within the
interior of the circulating assembly. Further, remediation
operations may be performed on wellbore tools or a subsurface
formation below the oil field tree once the sealing device is
removed. Then, the sealing device may be reinstalled. Once
reinstalled, hydrocarbons may be produced from the subsurface
formation or the stimulation fluids may be injected into the
well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] The foregoing and other advantages of the present technique
may become apparent upon reading the following detailed description
and upon reference to the drawings in which:
[0013] FIG. 1 is an exemplary production system in accordance with
certain aspects of the present techniques;
[0014] FIG. 2 is an exemplary flow chart of the installation and
use of the circulating assembly and blowout preventer from FIG. 1
in accordance with aspects of the present techniques;
[0015] FIG. 3 is an exemplary view of the circulating assembly with
the blowout preventer and subsea tree from FIG. 1 in accordance
with aspects of the present techniques;
[0016] FIGS. 4A-4C are exemplary embodiments of the circulating
tool of FIG. 3 that is mechanically actuated in accordance with
aspects of the present techniques; and
[0017] FIGS. 5A-5B are exemplary embodiments of the circulating
tool of FIG. 3 that is hydraulically actuated in accordance with
aspects of the present techniques.
DETAILED DESCRIPTION
[0018] In the following detailed description, the specific
embodiments of the present invention are described in connection
with its preferred embodiments. However, to the extent that the
following description is specific to a particular embodiment or a
particular use of the present techniques, it is intended to be
illustrative only and merely provides a concise description of the
exemplary embodiments. Accordingly, the invention is not limited to
the specific embodiments described below, but rather; the invention
includes all alternatives, modifications, and equivalents falling
within the true scope of the appended claims.
[0019] The present technique includes one or more embodiments of a
circulating tool that may be utilized with a blowout preventer
and/or other subassemblies to equalize pressure around a sealing
device, as described below. Under the present technique, an
apparatus, system and method are described for utilizing a
circulating tool having a circulating mechanism to equalize
pressure around a sealing device, such as a plug in a
production/injection oil field tree. In the method, the circulating
tool may be coupled to other tools or subassemblies to engage with
the oil field tree. Then, an isolated region is formed between at
least a portion of the circulating tool, at least a portion of the
BOP and at least a portion of the oil field tree. Once the isolated
region is formed, the circulating mechanism is utilized to provide
a fluid flow path between the interior of the circulating tool and
a location external to the circulating tool within the isolated
region. The oil field tree may also be adjusted to provide a flow
path between a location below the sealing device and the isolated
region. Through this fluid flow path, the pressure at the location
below the sealing device equalizes with the pressure within the
circulating tool. Then, the sealing device may be removed from the
oil field tree through the circulating device without damaging to
subsurface intervals and tools within the wellbore. As such, the
present techniques may be used in well remediation operations to
enhance hydrocarbon production, stimulation and/or remediation
operations for a subsurface formation.
[0020] Turning now to the drawings, and referring initially to FIG.
1, an exemplary production system 100 in accordance with certain
aspects of the present techniques is illustrated. In the exemplary
production system 100, a floating drilling rig 102 and production
facility 103 are coupled to a production or injection tree, such as
a subsea tree 104 located on the sea floor 106. The subsea tree 104
is an interface between one or more subsurface formations, such as
subsurface formation 107, and equipment or devices coupled to the
wellbore 114. The subsurface formation 107 may include multiple
production intervals or zones 108a-108n, wherein number "n" is any
integer number. As the production intervals 108a-108n may have
hydrocarbons, such as oil and gas, the production of hydrocarbons
may involve accessing downhole tools or wellbores via the subsea
tree 104 for remediation operations. However, it should be noted
that the production system 100 is illustrated for exemplary
purposes and the present techniques may be useful for other
specific subsea or land locations.
[0021] Within the wellbore 114, various equipment and components
are utilized to access the production intervals 108a-108n and to
provide hydrocarbons to the subsea tree 104. For instance, a
surface casing string 124 may be installed from the sea floor 106
to a location at a specific depth beneath the sea floor 106. Within
the surface casing string 124, an intermediate or production casing
string 126, which may extend down to a depth near the production
interval 108a, may provide support for the walls of the wellbore
114. Within the surface and production casing strings 124 and 126,
a production tubing string 128 may be utilized to provide a flow
path through the wellbore 114 for hydrocarbons and other fluids. A
subsurface safety valve 132 may be utilized to block the flow of
fluids from portions of the production tubing string 128 in the
event of rupture, while packers 134 and 136 may be utilized to
isolate specific zones within the wellbore annulus from each other.
Also, flow control devices, such as sand control devices 138a-138n,
may be utilized to manage the flow of fluids from the intervals to
the production tubing string 128.
[0022] Above the wellbore 114 at the sea floor 106, the subsea tree
104 provides an interface to other equipment that may be utilized
in producing hydrocarbons from the wellbore 114. For instance, the
subsea tree 104 may be coupled to a floating production facility
103 via a production umbilical 105. The floating production
facility 103, which may be utilized to produce and process
hydrocarbons from the subsurface formation 107, may be a floating
production facility or platform that include vessels capable of
managing the production of fluids, such as hydrocarbons, from
subsea wells. The production umbilical 105 may include one or more
fluid flow lines and/or electrical cables.
[0023] Also, the subsea tree 104 may be coupled to the floating
drilling rig 102 via a blowout preventer 110 and riser 111 and an
additional connection via a circulating assembly 112 and landing
string 113. The floating drilling rig 102 may be configured to
monitor and/or, perform remediation operations on the
equipment/tools associated with the wellbore 114. In particular,
the floating drilling rig 102 may include various tools that are
utilized for circulating operations, such as adjusting the
circulating mechanisms in a circulating tool, equalizing pressure
and/or removing plugs, along with other remediation operations,
such as stimulating an interval within the wellbore or adjusting
downhole tools. The blowout preventer 110 may be an assembly of
tools coupled to the subsea tree 104 and utilized to maintain well
control for circulating and remediation operations. The riser 111
and landing string 113 may be tubular members or piping, such as
rig marine riser, casing pipe and/or drilling pipe. The landing
string 113 may also include a control umbilical (not shown), which
has electrical and/or hydraulic control lines, for controlling and
communicating with various devices from the floating drilling rig
102. The circulating assembly 112 is configured to fit within or at
least partially within the blowout preventer 110 and has a
circulating tool that equalizes fluid pressure between the interior
of the circulating assembly 112 and a location below a sealing
device in the subsea tree 104.
[0024] Beneficially, the circulating assembly 112 is utilized to
equalize pressure around the sealing device, which may be a plug in
the subsea tree 104. With the pressure equalized, the plug may be
removed from the subsea tree 104 without causing damage to the
formation 107 and/or tools, such as the sand control devices
138a-138n. As such, various tools or subassemblies may be utilized
as part of the circulating assembly.
[0025] For example, the circulating assembly 112 may include a
tubing hanger running tool along with pipe joints (or subsea test
tree) and the landing string 113. The circulating assembly 112 may
then be coupled to the blowout preventer 110 to form an isolated
region above a plug in the subsea tree 104. If the blowout
preventer 110 has a choke and/or kill lines, these lines may be
utilized to provide a lighter fluid to the isolated region. Then,
valves within the subsea tree may be utilized to provide a flow
path from the isolated region to a location below the plug to
equalize pressure around the plug. However, these lines typically
include debris from previous operations, which may result in
increased rig time to remove the debris or work around the debris.
As such, the circulating assembly 112 may include a circulating
tool to provide an additional flow path directly from the landing
string 113 within the isolated region. The process of installing
and using the circulating assembly 112 is described further below
in FIG. 2.
[0026] FIG. 2 is an exemplary flow chart of the installation and
use of the circulating assembly and blowout preventer from FIG. 1
in accordance with aspects of the present techniques. This flow
chart, which is referred to by reference numeral 200, may be best
understood by concurrently viewing FIG. 1. In this flow chart 200,
a process to equalize fluid pressure between the interior of a
circulating assembly and a location below a sealing device, such as
a plug or packer in a subsea tree 104, is described. By equalizing
pressure, the time and expense of remediation operations on a
subsea tree may be reduced. That is, the present technique provides
a mechanism for efficiently removing a sealing device by equalizing
pressure around the sealing device. Thus, the circulating assembly
and blowout preventer may enhance remediation and production
operations.
[0027] The flow chart begins at block 202. At block 204, a riser
111 and blowout preventer (BOP) 110 may be installed. The riser 111
and BOP 110 may be installed by coupling the riser 111 to the BOP
110, running the coupled BOP 110 and riser 111 to the subsea tree
104 and engaging the BOP 110 to the subsea tree 104. At block 206,
the circulating assembly 112 may be coupled to the oil field tree.
The circulating assembly 112, which may be a single tool or two or
more tools or subassemblies coupled together, may include a
circulating tool having a circulating mechanism that is
mechanically, hydraulically, magnetically or electrically actuated,
as discussed further in FIGS. 3, 4A-4C and 5A-5B. The circulating
assembly 112 may be coupled to the landing string 113, run within
the riser 111 via the landing string 113, and engaged with the
subsea tree 104, as part of the coupling process. In addition, the
coupling of the circulating assembly 112 may include picking up a
coil tubing lift frame to compensate for movement of the floating
drilling rig 102 due to the water and a big bore surface tree for
well control. Then, the coil tubing lift frame and big bore surface
tree are attached to the landing string 113 and the tubing hanger
running tool may be latched to the tree tubing hanger. At block
208, an isolated region may be formed with a portion of the BOP
110, a portion of the circulating assembly 112 and a portion of the
oil field tree, such as subsea tree 104. This isolated region may
be formed to include at least a portion of the circulating tool by
engaging a packer between the BOP 110 and a section of the
circulating assembly 112, as discussed in FIG. 3, or by engaging a
sealing mechanism from a portion of the circulating assembly 112 to
a portion of the subsea tree 104.
[0028] With the isolated region formed, various steps may be
performed to equalize pressure for the removal of the sealing
device within the subsea tree 104. At block 210, the circulating
tool is adjusted into a circulating configuration or position. This
adjustment may include a mechanical actuation, electrical
actuation, or hydraulic actuation of a section of the circulating
tool, as noted above. For instance, if the circulating mechanism of
the circulating tool is mechanically actuated, it may be placed
into the circulating position to provide a fluid flow path between
the interior of the circulating tool and the isolated region. Then,
fluid may be circulated into the circulating assembly 112 and
isolated region via the landing string 113, as shown in block 212.
This fluid may displace other fluid within the landing string 113
with a lighter or heavier fluid, such as nitrogen, to within a
specific distance, such as 100 feet (ft) of the circulating tool in
the circulating assembly 112. This fluid may be utilized to adjust
the weight of the fluid within the circulating assembly 112 to
match the fluid below the sealing device and/or within the
wellbore. At block 214, a fluid flow path is provided for between
the circulating assembly 112 and a location below the sealing
device in the oil field tree. The flow path may be provided by
opening various valves within the subsea tree 104 to provide a flow
path between fluids inside the landing string 113 and the subsea
tree 104 under the sealing device.
[0029] With the fluid communicating with each other on both sides
of the sealing device, the pressure around the sealing device may
be monitored, as shown in block 216. The pressure may be indicated
by various sensors or gauges positioned near or around the sealing
device in the subsea tree 104 and in the circulating assembly 112.
At block 218, if the pressure has not equalized, the monitoring of
the pressure may continue in block 216. However, if the pressure
has equalized, the sealing device may be removed through the
circulating assembly in block 220. The sealing device may be
removed by running slick line, electrical line or coil tubing with
a receiving tool through the circulating assembly 112 to latch and
pull a plug or packer in or below the subsea tree 104. Once the
sealing device is removed, the circulating tool may be adjusted
into an isolating configuration or position, as shown in block 221.
Then, the remediation operations may be performed in block 222. The
remediation operations may include stimulation treatments of one or
more of the intervals 108, installing straddle bridges or plugs
into certain intervals 108, adjusting sleeves for flow control
devices 138a-138n, cutting tubing and preparing to complete another
interval and/or reinstalling a plug or packer into the subsea tree
104. Once the remediation operations are completed, the production
operations may be performed in block 224. The production operations
may include setting plugs and sliding sleeves, monitoring the
pressures associated with the wellbore, producing hydrocarbons and
processing the hydrocarbons. Regardless, the process may end at
block 226.
[0030] As a specific example, process described above may be
utilized to remove a tubing hanger plug. In this example, the riser
111 and BOP 110 may be coupled to the subsea tree 104 via a
connection, such as a threaded connection or H4 connector. Then, a
tree cap may be removed from the subsea tree 104 and returned to
the surface. Next, the circulating assembly 112, which includes a
circulating tool, is coupled to the subsea tree 104 and an isolated
region is formed between portions of the BOP 110, circulating
assembly 112 and subsea tree 104. Then, the circulating tool in the
circulating assembly 112 may be adjusted into a circulating
position along with valves in the subsea tree 104 to provide a
fluid communication path between fluid above and below the tubing
hanger plug. Once equalized, the tubing hanger plug is pulled to
the surface and remediation operations may be performed on the
intervals within the wellbore through the subsea tree 104, which
are followed by production operations.
[0031] As another example, process described above may be utilized
to remove a tree cap plug without removing the tree cap. In this
example, the riser 111 and BOP 110 may again be coupled to the
subsea tree 104 by a connection, such as a threaded connection or
H4 connector. Then, the circulating assembly 112, which includes a
circulating tool, is coupled to the subsea tree 104 and an isolated
region is formed between the BOP 110, circulating assembly 112 and
subsea tree 104. Once the isolated region is formed, the
circulating tool in the circulating assembly 112 may be adjusted
into a circulating position along with valves in the subsea tree
104 to provide a fluid communication path between fluid above and
below the tree cap plug. Once equalized, the tree cap plug is
pulled to the surface and remediation operations may again be
performed on the intervals within the wellbore through the subsea
tree 104. Then, the tree cap plug may be reinstalled and production
operations performed.
[0032] Beneficially, the use of the circulating mechanism in
circulating tool may enhance the operations of the well. For
instance, the circulating tool may be used to remove a sealing
device, such as a plug, from the subsea tree 104 in about 40 hours,
while the previous methods, which are described above, may require
about 100 hours to remove the sealing device from the subsea tree
104. As a result, time and expense of the rig operations may be
reduced by one or more days in performing the remediation
operations for a specific well. Further, the circulating tool may
be used to displace fluids only in the production tubing string 128
and/or landing string 113 instead of fluids in the riser. That is,
the isolated region in riser 111 is displaced, but the remaining
riser 111 does not have to be displaced with the fluid utilized to
adjust the weight of the fluid above the sealing device. As a
result, the operational costs are reduced because the amount of
fluid displaced is less than other approaches that utilize the
riser 111. Also, the use of the landing string 113 to displace
fluids reduces potential damage to the completion through the use
of choke and/or kill lines, which may include trash or debris from
other remediation or installation operations. Thus, the use of the
circulating assembly 112 and landing string 113 provides enhanced
control on the quality and type of fluids utilized in the sealing
device removal and remediation operations.
[0033] For exemplary purposes, different embodiments of the
circulating tool and assembly are described below. For instance,
FIG. 3 illustrates an exemplary embodiment the subsea tree 104,
blowout preventer 110, and the circulating assemblies 112 being
coupled together. In this embodiment, the circulating tool may
include a mechanically actuated circulating mechanism, a
hydraulically actuated circulating mechanism, a magnetically
actuated circulating mechanism and/or an electrically actuated
circulating mechanism, which are shown in FIGS. 4A-4C and 5A-5B and
discussed further below. Accordingly, it should be appreciated that
these are merely exemplary embodiments, which may be modified to
provide the functionality described under the present
techniques.
[0034] FIG. 3 is an exemplary embodiment of the circulating
assembly 112 and blowout preventer 110 coupled to the subsea tree
104 of FIG. 1 in accordance with aspects of the present techniques.
In this embodiment, the subsea tree 104, circulating assembly 112
and blowout preventer 110 include various components or
subassemblies utilized to equalize pressure around a tubing hanger
plug 302 in the subsea tree 104. Accordingly, these components and
subassemblies are described further below.
[0035] The subsea tree 104 includes various components utilized to
provide access for remediation operations and manage the flow of
fluid from the formation 107, as is known in the art. For instance,
the subsea tree 104 has a body 304 that includes various sections
configured to couple with tools, such as the BOP 110 or circulating
assembly 112, the production tubing string 128 and a production
manifold (not shown) that interfaces with the production umbilical
105. One of the sections of the body 304 interfaces with tools,
such as the BOP 110 or circulating assembly 112, and engages a
tubing hanger 306 and a tubing hanger plug 302. The tubing hanger
plug 302 prevents the flow of fluids from the wellbore through this
access point. In addition, this section of the body 304 may include
a bypass passage 310 coupled to a bypass conduit 312 that provides
a fluid flow path from the interior of the subsea tree 104 above
the tubing hanger plug 302 to production conduits 314. Within
and/or associated with the conduits 312 and 314, various valves
316-322 and pressure monitors 323-324 may be utilize to manage the
flow of fluids through the subsea tree 104. These valves 316-322
and pressure monitors 323-324 may be controlled by control logic
326 to manage the flow of fluids, as is known in the art. Also, a
choke 327 may be positioned along the production conduit 314 to
manage the flow of fluids from the wellbore to the production
umbilical 105.
[0036] The blowout preventer (BOP) 110 includes various components
that are utilized to provide well control, which are also known in
the art. For instance, the BOP 110 includes an upper annular 330
and a lower annular 332 that form a seal with different types of
pipes. Also, the BOP 110 includes a shear/seal ram 334 that seals
together by cutting any tool or piping across that portion of the
BOP 110 and three VBRs (variable bore rams) 336, 338 and 340 that
are pipe rams configured to operate for various pipe diameters,
such as pipe in the range of 5 inches to 7 inches, for example. In
addition, the BOP 110 includes a choke line 342 with choke valves
343 and a kill line 344 with kill valves 345 that provide fluid
paths from the subsea tree 104 to reduce the fluid pressure for
well control. Further, the BOP 110 includes a tree connection
section configured to engage and form a sealed connection with the
subsea tree 104. This section may include threads internal to the
BOP 110 that engage with threads external to a section of the
subsea tree 104, an extension that engages with an H4 connector or
other suitable profile and/or hubs (i.e. defined in API
16A/17D).
[0037] The circulating assembly 112 includes various tools and
subassemblies that are utilized to engage with the subsea tree 104
and provide flow paths for fluids through the landing string 113 to
the subsea tree 104. For instance, the circulating assembly 112 may
include a tubing hanger running tool (THRT) 348 to latch to the
tubing hanger 306, a slick joint 350 coupled to umbilical line 352,
a shear joint pup 354 to go across the shear rams 334, a
circulating tool 356, a spacer pup 355 and a pack off subassembly
358. The THRT 348 may include a tool that unlatches the tubing
hanger or tree cap from the subsea tree 104 and makes a seal with
the tubing hanger and tree cap. The slick joint 350 may include a
gun drilled joint of pipe to pass hydraulic pressure. The shear
joint pup 354 may include a piece of pipe that has a pressure
rating and tensile strength that is below the ratings of the shear
ram 334. The circulating tool 356, which is shown in greater detail
in FIGS. 4A-4C and 5A-5B, may include hydraulic, electric and
mechanical mechanisms to provide a radial flow path between the
exterior and interior of the circulating tool 356. The spacer pup
355 may include a piece of pipe that has a pressure rating and is
adapted to pass hydraulic fluid through the interior of the spacer
pup 355, while the pack off subassembly 358 may include a gun
drilled joint of pipe adapted to pass hydraulic fluid through the
interior.
[0038] To equalize pressure around the tubing hanger plug 302, the
upper annular 330 may be expanded to form an isolated region or
annulus between a portion of the BOP 110, circulating assembly 112
and plug 302. Then, the circulating tool is adjusted into a
circulating position. If the circulating mechanism is mechanically
activated, this adjustment may include moving the landing string
113 to align openings 359 and to provide a fluid flow path 360 from
the interior of the landing string 113 to the isolated region.
Regardless, the valves 316, 317, 319 and 321 may be placed into the
open position, while the valves 318 and 320 are placed into the
closed position. With these valves 316-321 in the various
positions, fluid may flow between a location below the plug 302
through the conduits 312 and 314 along the fluid flow path 360 into
the isolated region. Thus, the fluid pressure within the isolated
region and within the subsea tree 104 below the tubing hanger plug
302 may equalize through the flow path 360.
[0039] To interact with a subsea tree 104 and BOP 110, the
dimensions of the circulating tool 356 is based upon various
factors. The factors may include the outer diameter of the
circulating tool 356, the internal diameter of the circulating tool
356 and the length of the circulating tool 356. The outer diameter
of the circulating tool 356 is limited by the internal diameter of
the BOP 110 and the amount of space required for the umbilical line
352. The inner diameter of the circulating tool 356 is limited by
the size of the sealing device to be removed, such as the tubing
hanger plug 302, tree cap plug, or packer, and the performance
rating of the tool (such as pressure, tension, compression, torque,
etc. The length of the circulating tool 356 may be limited by the
other assembly tools and specific positioning of the circulating
mechanism relative to the upper annular 330 in the BOP 110. Also,
the circulating tool 356 may be positioned above the shear/seal ram
334 to reduce any potential damage to the circulating tool 356 in
the event of a loss of well control. In addition, the length of the
components of the circulating tool 356 may be limited by the
movement of the circulating mechanism. Accordingly, these various
factors and other embodiment specific aspects are discussed below
in FIGS. 4A-4C and 5A-5B.
[0040] FIGS. 4A-4C are exemplary embodiments of the circulating
tool 356 having a circulating mechanism that is mechanically
actuated in accordance with embodiments of the present techniques.
In these embodiments 400a and 400b of the circulating tool 356,
which may be referred to as embodiments 400, the circulating
mechanism includes a first tubular member 402 having one or more
openings 406 and threads 407, and a second tubular member 404
having one or more openings 408 and threads 409. The tubular
members 402 and 404 may be made from metal or metal alloys and have
suitable strength. For instance, the tubular members 402 and 404
may have a differential pressure rating of up to 5,000 psi or up to
15,000 psi, operate in a temperature range of 32.degree. F.
(Fahrenheit) to 200.degree. F., a torque rating of 50,000
foot-pounds (ft-lbs), internal pressure rating of 15,232 psi
(pounds per square inch), and a tension rating of 1,149,234 lbs. As
such, the combined load rating for the embodiment may be as much as
621,000-pounds tension with an internal pressure of 15,000 psi and
torque of 50,000 ft-pounds. The openings 406 and 408 may be
configured to provide fluid flow paths that provide volume flow
that is greater than or equal to the volume flow through the
landing string 113, bypass passage 312 and bypass conduit 314. In
particular, the openings 406 and 408 may be about equal to the flow
area of the landing string to prevent any material wash out. The
threads 407 and 409 may be utilized to couple the circulating tool
to other tools, as is know in the art. In these embodiments 400,
the openings 406 and 408 are mechanically actuated by movement of
the landing string or wireline to align into a circulating
position, as shown in FIG. 4B, and to misalign in an isolating
position, as shown in FIG. 4A. The various components of the
embodiments 400 are shown below in greater detail.
[0041] In FIG. 4A, the first tubular member 402 and the second
tubular member 404 are in an isolating position. In this
configuration, the seals 410-412 isolate fluid flow from the
exterior and interior of the tubular members 402 and 404. The seals
410-412 may include molded seals, o-rings, t-rings, chevron packing
stack, poly-pak and/or other elastomeric and thermoplastic
materials. Also, in the isolating position, the second tubular
member 404 may include one or more recessed sections or slots 414,
while the first tubular member 402 may include guide members 416
that engage with the slots 414. The slots 414, which may be
straight slots or "J" slots, may be utilized to control the
position of the openings 406 and 408 relative to each other in the
various configurations. The guide members 416 may be a pin, screw,
rod or other suitable component that engages with the slot 414. In
this embodiment 400a, each of the guide members 416 is positioned
at one end of the respective slots 414 that extends the circulating
tool 400a to a length 418. In addition, it should be noted that one
or more biasing members (not shown) may be utilized to fix the
embodiment 400 into one of the positions. These may include shear
pins, collets, or other suitable members.
[0042] In FIG. 4B, the first tubular member 402 and the second
tubular member 404 are in the circulating position. In this
configuration, the guide member 416 moves a longitudinal distance
421 within the slot 414 to engage with another end of the slot 414.
This movement aligns the openings 406 and 408 to provide one or
more radial fluid flow paths between the exterior and interior of
the embodiment 400b. Further, in this circulating position, the
embodiment 400b is compressed to a length 420.
[0043] As noted above, the embodiments 400 may be adapted to
operate with the subsea tree 104 and BOP 110. As a result, the
factors, such as the outer diameter 422 of the embodiment 400, the
internal diameter 424 of the embodiment 400, the length of the
embodiment 400, may be adjusted to maintain certain dimensional
aspects of the circulating tool. For instance, the outer diameter
422 is limited by the internal diameter of the BOP 110, which may
be between 7 1/16 inches and 283/4 inches, or typically about 183/4
inches, and the amount of space required umbilical line 352, which
may be a single line or bundle of lines that are flexible enough
for the movement of the tubular members 402 and 404. Accordingly,
the outer diameter 422 is limited by the diameter of the BOP 110,
which may be between about 113/4 inches and 183/4 inches.
Similarly, the inner diameter 424 is limited by the size of the
sealing device, such as the tubing hanger plug, tree cap plug or a
packer, which is to be removed through the circulating tool 356.
That is, the inner diameter is larger than the sealing device to
provide for passage of the sealing device through the circulating
tool. For instance, the sealing device may be a plug that is about
4.692 inches or 4.73 inches. Accordingly, the inner diameter 424
may be in a range between about 0 inches and about 4.7 inches,
about 4.7 inches and about 10 inches, about 1.0 inches and about 10
inches or more preferably about 5.75 inches. The length of the
embodiment 400 may be limited by the location of the sealing
element in the BOP 110, the other tools in the circulating assembly
112, the location of the shear/seal ram 334 and the upper annular
330. For instance, if the upper annular 330 is the sealing element
and shear/seal ram 334 are separated by about 215 inches, then the
length of the embodiment 400 may be less than or equal to about 215
inches in the circulating position. As such, the length 420 is
highly variable and based upon the distance separation of
components of the BOP 110 and the other subassemblies in the
circulating assembly 112. Finally, the stroke length 421 of the
embodiment 400 may be limited to reduce wear on the seals 410-412
by limiting the movement of within the slot 414. For example, the
stroke length 421 may be between 6 inches and 12 inches, or
preferably about 9 inches.
[0044] As additional enhancements, the slot 414 may be a "J" slot
and/or include both a straight slot and a "J" slot. A "J" slot may
be utilized as a locking mechanism to fix the tubular members 402
and 404 into a specific configuration. For example, as shown in
FIG. 4C, a partial view of the second tubular member 404 is shown.
In this view, a straight slot 426 and a "J" slot 428 may be
positioned on one end of the tubular member 404. These slots 426
and 428 may be indicated on the tubular member 404 by a specific
marking, such as a "J" or a "I" to indicate the slot type. The
length of the slots 426 and 428 may be a length 430 that is the
stroke length 421 plus the width of the guide member 416.
Beneficially, the use of the slots 426 and 428 provide flexibility
in the operation of this embodiment 400 of the circulating tool
112. Further, in another embodiment, the slots 414 may be formed in
the first tubular member 402, while the second tubular member 404
may include the guide member 416 to engage the slots 414. The guide
members 416 may be a pin, screw, rod or other suitable component
that engages with the slot 414.
[0045] FIGS. 5A-5B are exemplary embodiments of the circulating
tool 356 having a circulating mechanism that is hydraulically
actuated in accordance with embodiments of the present techniques.
In these embodiments 500a and 500b of the circulating tool 356,
which may be referred to as embodiments 500, the circulating tool
includes a first tubular member 502 having one or more openings
506, an end cap 505 and threads 507 and 509. Also, the circulating
tool includes a circulating mechanism, which is a sleeve or second
tubular member 504 having one or more openings 508. It should be
noted that these embodiments 500 may include components that are
similar to the components described above in FIGS. 4A-4C. For
instance, the tubular members 502 and 504, openings 506 and 508,
threads 507 and 509 and seals 510-512 may be similar to the tubular
members 402 and 404, openings 406 and 408, threads 407 and 409 and
seals 410-412. However, in these embodiments 500, the openings 506
and 508 are adjusted by movement of the second tubular member 504
through the application of hydraulic pressure to align into a
circulating position, as shown in FIG. 5B, and to misalign in an
isolating position, as shown in FIG. 5A.
[0046] To provide the hydraulic actuation, the first tubular member
502 includes a recessed section 514 that is configured to receive a
piston 516. The piston 516 may be a raised portion of the second
tubular member 504 or a section of pipe welded to the second
tubular member 504. Seals 520 and 521, which may be similar to the
seals 510-512, may be utilized to form sealed chambers between the
piston 516 and the tubular members 502 and 504. In one chamber, a
return spring 524 may be positioned to bias the circulating
mechanism into the isolating position, as shown in FIG. 5A. In a
second chamber, a hydraulic conduit 526 may provide hydraulic fluid
to the chamber for hydraulic actuation of the piston. The hydraulic
conduit 526 is adapted to engage with piping or fluid flow lines,
which may be part of an umbilical line. As the pressure increases
in the second chamber, the piston 516 is moved a longitudinal
distance 532 to compress the spring 524 and align the openings 506
and 508, as shown in FIG. 5B.
[0047] As noted above, the embodiments 500 may be adapted to
operate with the subsea tree 104 and BOP 110. The factors to be
adjusted may include the outer diameter 528 of the embodiment 500,
the internal diameter 530 of the embodiment 500 and the length 518
of the embodiment 500. As noted above, the outer diameter 528,
internal diameter 530 and length 518 may include the same ranges
discussed above. However, in this embodiment 500, the length 518 is
the same for the isolating position and the circulating
position.
[0048] Further, it should be appreciated that the embodiments
discussed above may be modified to perform the same functionality.
For instance, the sleeve 504 in FIGS. 5A-5B may be modified to
interact with wireline instead of relying on hydraulic lines. In
addition, the sleeve 504 may also be modified to interact with an
electric motor installed in the recessed chamber 514 that is
coupled to electric lines in the control umbilical 352. As such, it
should be appreciated that different embodiments of the circulating
tool may be utilized to perform the present techniques.
[0049] Moreover, it should be appreciated that the other
embodiments of the hydraulically actuated circulating tool may be
utilized to further enhance the operation. For instance, the
embodiment of the tool in FIGS. 5A and 5B is "pressure biased" with
internal pressure. Assuming the hydraulic line is not in
communication with the annulus (enclosed area), internal pressure
may tend to act on the area between two seals on different
diameters. In other words, the internal pressure may tend to shift
the tool into different configurations or positions. In particular,
if the fluid inside the circulating tool is heavier than the fluid
used to activate the hydraulic system, adjustment of the
circulating tool may be slow. Conversely, if heavy fluid is used
for the hydraulic actuation, the circulating tool may tend to shift
between certain positions. Accordingly, balance seals exposed to
the tubing or annulus pressure may allow the hydraulic actuation to
work solely against the spring. An example of this type of
technology for use in a valve is described in DepthStar.RTM.
Tubing-Retrievable Safety Valve by Halliburton.
[0050] In addition, it should be noted that guide member and slot
may be include other embodiments. For instance, the slots may be
grooves with the guide member being a raised portion of the
circulating mechanism or second tubular member. Also, the
circulating tool may include locking devices to hold torque from 0
ft lbs of torque to greater than 50,000 ft lbs of torque. The
locking devices may include splines, wedges, screws, lugs, or keys
that prevent rotation inside of the circulating tool other than the
distance it takes to move between positions. These locking
mechanisms may be part of the either of tubular member or both of
the tubular members.
[0051] Also, it should be understood that the process to equalize
fluid pressure between the interior of a circulating assembly and a
location below a sealing device, which is described in the flow
chart 200, may be modified in different embodiments. For instance,
the adjustment of the circulating tool into the circulating
position in block 210 may be performed prior to the forming of the
isolated region in block 208. Also, the circulating of the fluid
through the circulating tool in block 212 may follow the adjustment
of the circulating tool in block 210, but be performed before the
formation of the isolated region 208. Further, the providing of the
fluid flow path between the circulating assembly 112 and the
location below the sealing device in the subsea tree 104 in block
214 may be performed before blocks 210 and 212, but after the
forming of the isolated region in block 208. Thus, the ordering of
the different steps within the process described in the flow chart
200 may be modified in other embodiments.
[0052] While the present techniques of the invention may be
susceptible to various modifications and alternative forms, the
exemplary embodiments discussed above have been shown by way of
example. However, it should again be understood that the invention
is not intended to be limited to the particular embodiments
disclosed herein. Indeed, the present techniques of the invention
are to cover all modifications, equivalents, and alternatives
falling within the spirit and scope of the invention as defined by
the following appended claims.
* * * * *