U.S. patent application number 15/899364 was filed with the patent office on 2019-02-21 for shortened tubing baffle with large sealable bore.
The applicant listed for this patent is Peak Completion Technologies, Inc.. Invention is credited to Bryan Fitzhugh, William Sloane Muscroft.
Application Number | 20190055811 15/899364 |
Document ID | / |
Family ID | 65359955 |
Filed Date | 2019-02-21 |
United States Patent
Application |
20190055811 |
Kind Code |
A1 |
Fitzhugh; Bryan ; et
al. |
February 21, 2019 |
Shortened Tubing Baffle with Large Sealable Bore
Abstract
Devices for controlling the flow of fluids past a location in a
wellbore and methods for using such devices are disclosed.
Embodiment devices are configured such that the throughbore is
maximized because of the devices' thin cross sectional length.
Embodiment devices may be optimized to expand into larger casing
sizes by use of a multi-part cone system while maintaining the thin
cross section. Embodiment devices may also permit the plug to be
communicated into the well with the flow control devices, reducing
the fluid volume required to treat well stages separated by the
disclosed embodiment devices.
Inventors: |
Fitzhugh; Bryan; (Midland,
TX) ; Muscroft; William Sloane; (Midland,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Peak Completion Technologies, Inc. |
Midland |
TX |
US |
|
|
Family ID: |
65359955 |
Appl. No.: |
15/899364 |
Filed: |
February 19, 2018 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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PCT/US16/47762 |
Aug 19, 2016 |
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15899364 |
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15621291 |
Jun 13, 2017 |
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PCT/US16/47762 |
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14844192 |
Sep 3, 2015 |
9677375 |
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15621291 |
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62207058 |
Aug 19, 2015 |
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62231532 |
Jul 9, 2015 |
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62045375 |
Sep 3, 2014 |
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62069794 |
Oct 28, 2014 |
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62117382 |
Feb 17, 2015 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 23/06 20130101;
E21B 33/1292 20130101 |
International
Class: |
E21B 33/129 20060101
E21B033/129; E21B 23/06 20060101 E21B023/06 |
Claims
1. A downhole tool having a run-in state and a set state, the
downhole tool comprising: A mandrel having in interior surface
defining a passage therethrough and an exterior surface; a plug
seat; a first setting ring; and an element, a cone having a first
angular surface and a second angular surface, a cone extension and
at least one slip positioned below the first setting ring and
around the mandrel; wherein in the set state, the at least one slip
engages the cone extension; and engagement of a plug on the plug
seat prevents fluid communication through the passage.
2. The downhole tool of claim 1 wherein a single piece comprises
the plug seat and the first setting ring.
3. The downhole tool of claim 1 wherein the cone extension engages
the first angular surface and the at least one slip engages the
second angular surface.
4. The downhole tool of claim 1 wherein, in the run-in state, the
cone extension and the at least one slip are positioned on opposing
sides of the cone.
5. The downhole tool of claim 1 further comprising a second setting
ring, wherein the downhole tool is changeable from the run-in state
to the set state by movement of the first setting ring toward the
second setting ring.
6. The downhole tool of claim 5 having a run-in state and a set
state, wherein the second setting ring telescopes over at least a
portion of the mandrel.
7. The downhole tool of claim 1 wherein, in the set state, at least
a portion of the cone extension is between a portion of the at
least one slip and the first angular surface.
8. The downhole tool of claim 1 comprising a connection between the
plug seat and the setting ring that is at least partially in fluid
isolation from the exterior of the tool.
9. The downhole tool of claim 1 comprising a connection between the
plug seat and the setting ring that is substantially in fluid
isolation from the exterior of the tool.
10. The downhole tool of claim 1 wherein, in the set state, the at
least one slip engages the cone extension radially outwardly of the
outer diameter of the cone.
11. A tubing baffle having a run-in state and a set state, the
tubing baffle comprising: A mandrel having in interior surface
defining a passage therethrough and an exterior surface; a plug
seat; a first setting ring and a bottom section; an element, and at
least one slip positioned below the setting ring and around the
mandrel; and a plug; wherein the plug is configured to engage the
plug seat to prevent fluid communication through the mandrel
passage; the plug is engaged with the tubing baffle in the run-in
state and in the set state.
12. The tubing baffle of claim 11 having an adaptor kit extension
comprising the plug, the adaptor kit extension communicating force
to the frac baffle to move the first setting and bottom section
toward one another when the frac baffle changes from the run-in
state to the set state.
13. The tubing baffle of claim 12 wherein the adaptor kit extension
may function as a check valve in the mandrel passage.
14. The tubing baffle of claim 11 wherein the plug comprises
material that degrades substantially faster than the mandrel.
15. The tubing baffle of claim 12 wherein at least one component of
the adaptor kit extension is degradable in aqueous fluids.
16. The tubing baffle of claim 12 wherein the adaptor kit extension
engages the bottom section when the tubing baffle moves from the
run-in state to the set state.
17. A method for installing a flow control device into a well, the
method comprising: connecting the flow control device to a wireline
string, the flow control device comprising a mandrel with an
element therearound, a plug seat, a plug in communication with the
plug seat, an upper setting ring, a slip, and a bottom section;
placing the flow control device into a well; conveying the flow
control device to a desired location in the well; moving the upper
setting ring and the bottom section toward one another; expanding
the slip radially outward to engage a casing in the well; releasing
the flow control device from the wireline string; and removing the
wireline string from the well.
18. The method of claim 17, the flow control device further
comprising a check valve, the check valve preventing fluid flow
through the downhole tool when fluid pressure adjacent to the plug
seat is greater than fluid pressure adjacent to the bottom section
and the conveying step comprises engaging the check valve to
prevent fluid communication through a throughbore of the flow
control device.
19. The method of claim 17, the flow control device further having
an adaptor kit extension comprising the plug, wherein the moving
step comprises transferring force from the wireline string to the
flow control device through the adaptor kit extension.
20. The method of the claim 17 wherein the plug comprises material
that degrades substantially more quickly than the mandrel.
21-28. (canceled)
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of application number
PCT/US16/47762 filed on Aug. 19, 2016 entitled "Shortened Tubing
Baffle with Large Sealable Bore" which claims priority to U.S.
Provisional Patent Application 62/207,058 filed on Aug. 19, 2015
entitled "Shortened Tubing Baffle with Large Sealable Bore" and to
U.S. Provisional Patent Application 62/231,532 filed on Apr. 12,
2016 entitled "Large Bore Baffle with Integral Degradable Plug";
and is a continuation-in-part of U.S. patent application Ser. No.
15/621,291 filed on Jun. 13, 2017 entitled Shortened Tubing Baffle
with Large Sealable Bore which is a continuation of U.S. patent
application Ser. No. 14/844,192, filed on Sep. 3, 2015 and entitled
"Shortened Tubing Baffle with Large Sealable Bore", now U.S. Pat.
No. 9,677,375, issued on Jun. 13, 2017, which claims the benefit of
U.S. Provisional Patent Application Ser. No. 62/045,375 entitled
"Shortened Bridge Plug with Large Sealable Bore" filed on Sep. 3,
2014; and of U.S. Provisional Patent Ser. No. 62/069,794 entitled
"Shortened Bridge Plug with Large Sealable Bore" filed on Oct. 28,
2014, and of U.S. Provisional Patent Application Ser. No.
62/117,382 entitled "Shortened Frac Baffle with Large Sealable
Bore" filed on Feb. 17, 2015; each of which foregoing applications
are incorporated by reference as if fully set out herein.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND
Field
[0003] Embodiments according to the present disclosure relate to
flow control devices for use in oil and gas wells, and particularly
to flow control devices used for isolating the portion of the well
above the device from portions below the device. Such flow control
devices may be used to isolate one region of the wellbore, and/or
tubing installed in the wellbore, from other portions thereof and
are commonly used in the completion of multiple formations accessed
by a single well, multiple stage completions of a single formation,
or other activities in which it is desirable to prevent fluid
communication across a desired location within the well.
Description of Related Art
[0004] Current devices, such as baffles, for preventing fluid
communication across a location in a well are not totally
satisfactory. Such devices may be limited to fluid isolation with
relatively low pressure differentials, have an unsatisfactorily
small (or non-existent) flow path therethrough when the device is
an "open" state, require active intervention--such as mill-out or
release--for their removal, utilize materials that take longer than
is acceptable to mill out (e.g. have unacceptable machinability),
have an excessive volume of material to be milled because of
cross-sectional thickness and/or length, or combinations of these
and other limitations.
[0005] Some fluid barriers, such as bridge plugs, must be removed
from the well, such as by drilling or milling out, before fluids
can flow back from the formation to the wellhead. The bridge plugs
function as fluid barriers in both directions, preventing fluid
flow not only from the wellhead to the previously treated
portion(s) of the well, but also from such treated portions to the
wellhead. Drilling out bridge plugs can be a time consuming and
expensive process involving workover rigs or coil tubing.
[0006] One alternative to bridge plugs is the frac baffle. These
devices have an open throughbore that can be sealed with an
appropriately sized ball, dart or other plug to prevent fluid flow
from the wellhead to the formation. Higher pressure on the wellhead
side of the baffle forces the plug into the baffle and the plug
releases when pressure equalizes across the baffle or when pressure
on the downwell side is greater than the upwell side. In this way,
frac baffles may permit reservoir fluids to flow to the wellhead
without any drilling out operation. Present frac baffle designs
have a throughbore that is unsatisfactorily narrow, leading to
clogging--such as "sanding up"--or other blockage following
completion of fracture treatments, such as during flowback.
Further, the narrow throughbore limits the thru tubing tools that
may pass through such baffles so that, even if such baffles may
remain during initial production, they are likely to require
drilling out when workover operations become necessary.
BRIEF SUMMARY
[0007] Embodiments of the present disclosure overcome the
difficulties described above and/or strike an improved balance
therebetween. Embodiment devices as described herein allow for
significantly larger throughbores when the device is in the open
state, making mill out an option rather than a necessity.
Embodiments may be constructed primarily of materials more
machinable than commonly used steels (e.g. such as P110
specification steels having a minimum 110 k psi yield strength and
steels of approximate yield strengths similar to certain ductile
irons such as L80 spec steels, having at least 80 k psi yield
strength). Such materials may include ductile iron, composite
materials, or others. Combined with the shortness and thin walls of
the baffles herein, devices of the present disclosure provide
improved milling time if the device must be removed.
[0008] Methods according to the present disclosure deploy a flow
control device--such as a device having an upward facing plug
seat--at a selected location in the tubing for use with plug and
perf operations or any other application that could utilize a ball
and seat for isolation. A seal is created between the flow control
device and the tubing, such as with a conventional packing element,
and at least one slip flanking the element is set to hold the flow
control device in place. The seat of the device does not create
isolation until a sealing element (ball, dart, plug) is landed
on/in the seat of the tool. A treatment, such as a fracture
treatment, can then be conducted through casing perforations upwell
of such seat. A subsequent tool may then be run in and set upwell
of those perforations and the process repeated. Plugs are not
required to pass through other seats before landing on the desired
seat, thus permitting the throughbore of each seat to have maximum
diameter--e.g., the throughbore is not reduced in size because of
the need to pass its corresponding plug through pre-installed seats
upwell of the desired seat location.
[0009] Further, while some embodiments according to the present
disclosure are configured for sealing by higher pressure on one
side of a plug engaged with the baffle, the invention as claimed is
not limited to such embodiments. Other configurations, such as
configurations in which sealing does not require such pressure
differential are envisioned. Such baffles have a seat configured to
receive a selected plug or plugs (such as a ball, needle, disk,
overshot, or other structure preventing, limiting, or controlling
fluid flow when engaged with the seat). Such embodiments may be
useful, for example, when closure of the baffle causes a pressure
differential to build across the seat after the plug has been
engaged.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
[0010] FIG. 1 is a sectional elevation of an embodiment baffle
according the disclosure herein.
[0011] FIG. 2 is a sectional elevation of the embodiment baffle of
FIG. 1 in the set position.
[0012] FIG. 2A is a partial sectional elevation of the baffle of
FIG. 2 more fully disclosing the region adjacent the upper
slip.
[0013] FIG. 3 is a sectional elevation of an alternate embodiment
baffle.
[0014] FIG. 4 is a sectional elevation of a of an alternative
embodiment baffle.
[0015] FIG. 5 is a sectional elevation of a run assembly showing
the baffle of FIG. 4 and a Wireline Adaptor Kit.
[0016] FIG. 6 is a sectional elevation of an alternative embodiment
baffle.
[0017] FIG. 7 is a sectional elevation of another alternative
embodiment baffle.
[0018] FIG. 8 is a sectional elevation of further alternative
embodiment baffle.
[0019] FIG. 9 is a sectional elevation of the embodiment of FIG. 8
in the set position.
[0020] FIG. 10A is a sectional elevation of the embodiment of FIG.
6 having an alternative embodiment setting assembly.
[0021] FIG. 10B is side view of an embodiment wireline adaptor kit
extension from FIG. 10A.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
[0022] When used with reference to the figures, unless otherwise
specified, the terms "upwell," "above," "top," "upper," "downwell,"
"below," "bottom," "lower," and like terms are used relative to the
direction of normal production and/or flow of fluids and or gas
through the tool and wellbore. Thus, normal production results in
migration through the wellbore and production string from the
downwell to upwell direction without regard to whether the tubing
string is disposed in a vertical wellbore, a horizontal wellbore,
or some combination of both. Similarly, during the fracing process,
fracing fluids and/or gasses move from the surface in the downwell
direction to the portion of the tubing string within the
formation.
[0023] FIG. 1 shows an embodiment flow control device 100 according
to the present disclosure. The embodiment of FIG. 1 comprises a
mandrel 110, slips 122 and 124, rings 132 and 134, element 130,
cone 140, bottom section 150 and ratchet ring 160. Mandrel 110
comprises at least one upper face 112, an interior surface 180 at
least partially defining the throughbore of the tool, and mandrel
teeth 170 positioned on at least part its exterior surface.
[0024] Slips 122, 124, rings 132, 134, and element 130 are arranged
around an outer surface of mandrel 110 between mandrel shoulder 121
and cone shoulder 127. Slip 122 is between mandrel shoulder 121 and
ring 132. Slip 124 lies between cone shoulder 127 and ring 134.
Rings 132, 134 are located on opposing ends of the element 130
between the element 130 and slip 122 or slip 124, respectively.
Either or both of slips 122, 124 may, in conjunction with rings
132, 134, function as an expansion ring to limit or prevent
extrusion of element 130 longitudinally between the outer surface
of the device 100 and any tubing in which it is installed.
[0025] In the embodiment of FIG. 1, ratchet ring 160, positioned in
a groove formed at least in part from cone 140, has a plurality of
teeth configured to engage mandrel teeth 170 on the outer surface
of mandrel 110. Ratchet ring is positioned adjacent to bottom
section 150 and one or more surfaces of bottom section 150 may form
at least part of the groove or other structure holding ratchet ring
160 in the desired location.
[0026] In operation, embodiments of the present disclosure may be
run in on wireline using a setting tool such as a conventional
Baker 10, Baker 20, or Go-Shorty hydraulic setting tool or other
setting tool. Such setting tools are known in the art. Such setting
tool, which may also include a suitable or custom adapter for the
specific embodiment, may be connected to the device via setting
shear pins connecting a setting mandrel to the bottom of the
baffle, such setting shear pins connecting the setting tool to the
embodiment device through one or more shear pin holes 152 in the
bottom section 150. The setting tool, or adaptor, may also have a
piston, such as a setting sleeve or setting nut, engaging the
setting mandrel at or near the upper face 112.
[0027] Once the setting tool is triggered, force is applied to the
piston to force the piston towards the setting shear pins.
Anti-preset shear pins 114 hold the mandrel 110 in place relative
to the cone 140 until the setting tool is triggered. The
anti-preset shear pins 114 are then broken by the force applied to
the mandrel 110, e.g the setting force of the piston is transferred
to the mandrel 110 such that upper face 112 is forced towards the
bottom section 150, reducing the distance between the mandrel
shoulder 121 and the cone shoulder 127. As the mandrel 110 moves in
response to actuation, the mandrel teeth 170 sequentially engage
the opposing teeth on ratchet ring 160, locking the mandrel 110 in
the actuated state (shown in FIG. 2).
[0028] Movement of the mandrel shoulder 121 towards the cone
shoulder 127 causes a reduction in the distance between the mandrel
shoulder 121 and upper ring shoulder 123 as well as reducing the
distance between lower ring shoulder 125 and cone shoulder 127.
These reductions apply outward pressure to slips 122, 124 via the
angular shoulders as can be seen in FIG. 2. Slips 122, 124 may be
c-rings or other type of split ring and therefore such outward
pressure causes the slips to expand and the slip teeth to engage
the tubing in which the device is to be installed. Further, the
longitudinal travel of the mandrel 110 is configured to have more
travel than is necessary for expansion of the slips 122, 124. In
this way, the element 130 can be compressed to provide a fluid
pressure seal against the same inner tubing surface against which
the slips 122, 124 become engaged.
[0029] In certain embodiments, the mandrel shoulder 121 will be
brought close to the ring shoulder 123. The angular profile of slip
122 may such that, when the slip 122 expands to engage the tubing,
mandrel shoulder 121 and ring shoulder 123 are held about 2 inches
apart or less, 1.5 inches or less or about 1 inch or less apart. In
some embodiments, slip 122 holds mandrel shoulder 121 and ring
shoulder 123 about one-half inch or less apart and in still further
embodiments less than about one-quarter inch apart.
[0030] The distance between mandrel shoulder 121 and ring shoulder
123 may dictate the length of mandrel 110 exposed to the high
pressure differential of the fracture or other treatment. When a
plug engages upper face 112 to create a fluid seal, the throughbore
defined by interior surface 180 of mandrel 110 is in fluid
isolation from slip 122 and the outer surface of mandrel 110
adjacent to slip 122. Pressure in the tubing, such as by pumps from
the surface, is applied to the outer surface of mandrel 110--from
the upper face 112 to the upper edge of element 130--but not the
inner surface of mandrel 110, creating a pressure differential
across the upper portion of the mandrel, including at exposed
length 117. The shorter the gap between mandrel shoulder 121 and
ring 123, the shorter the length of mandrel 110 exposed to the
pressure differential. By configuring the exposed length 117 to be
relatively short when the device is installed, the mandrel 110 may
withstand pressure differentials across its wall that are normally
predicted to collapse the mandrel 110. Ring 132 may not form a
fluid seal with mandrel 110, and therefore the exposed length 117
may include the region under ring 132 as well as the region between
mandrel should 121 and ring 132. Embodiments with a shortened
exposed length 117 may have an exposed length that is from about
3.0 inches to about less than 0.25 inches, more preferably less
than 2.0 inches. With exposed lengths 117 less than about 1 inch,
the ability of the mandrel to withstand collapse pressures may
increase substantially. In certain embodiments, the exposed length
117 is about 0.5 to about 0.25 inches or less when the tool is set,
but larger exposed lengths may be necessary if slip 122 must be
enlarged.
[0031] In some embodiments, the seat for engaging a plug, such as
upper face 112, is adjacent the exposed length of mandrel 110, such
as within about 0.5 to 1 inches. A solid plug, such as a ball may
provide support to both the upper face 112 and the exposed length
117 to prevent collapse at high pressure differentials across the
mandrel wall.
[0032] The advantages of the present embodiments become readily
apparent, allowing for a very short tool, as least as short as 8
inches prior to installation. Such shortened tool provides for more
rapid mill out than longer baffles. Further, because of the large
throughbore, drill out may not be necessary. Disintegrable plugs,
such as dissolvable frac balls, may be used in conjunction with
embodiments according to the disclosure herein, leaving the
throughbore of the device free from obstruction after sufficient
disintegration of the plugs because such plugs can then flow freely
out of the well through the installed embodiment baffles. Further,
disintegrable plus may completely dissolve or suspend in wellbore
fluids to be carried out of the well.
[0033] Further, it will be appreciated that, because embodiments
herein are, in effect, a unidirectional plug, the slips may be
biased to have greater holding strength to prevent movement in the
downwell direction (e.g. against pressure differentials caused by
higher fluid pressure at the upper face 112 relative to the fluid
pressure at the bottom section 150). Such an arrangement may allow
for the slip 124 to have a stronger "bite" to hold the device
against such differentials while the upper slip 122 has a weaker
bite.
[0034] One or more shear pin holes 152 may be maintained without a
shear pin, e.g. remain empty. Such empty shear pin holes may serve
as a flowback bypass, such as when a plug from a downstream seat
travels upwell to engage the bottom section 150. Such plug may be
large enough to close the opening in the bottom section 150--e.g.
block the throughbore by engaging bottom section 150--and an empty
shear pin hole will allow fluid to enter the throughbore, thereby
circumventing or bypassing such obstruction.
[0035] Embodiments with varying slips may be used. In addition to
the opposing sips illustrated in FIG. 1, the present disclosure
encompasses alternate embodiments such as configurations in which
both slips oppose movement of the device in a single direction or
in which the upper slip is absent and friction from the element
assembly holds the device in place against upwell movement.
Further, the c-ring slips may be substituted with many other slips
known in the art, including barrel slips--e.g. slips 222 and 224 of
FIG. 3.
[0036] FIG. 3 shows another embodiment downhole tool 200 according
to the present disclosure. The embodiment of FIG. 3 comprises a
mandrel 210, slips 222 and 224, rings 232 and 234, element 230,
cone 240, bottom section 250 and ratchet ring 260. Mandrel 210
comprises at least one upper face 212, an interior surface 280 at
least partially defining the through bore of the tool, and mandrel
teeth 270 positioned on at least part its exterior surface.
[0037] Slips 222, 224, rings 232, 234, and element 230 are arranged
around an outer surface of mandrel 210 between mandrel shoulder 221
and cone shoulder 227. Slip 222 is between mandrel shoulder 221 and
ring 232. Slip 224 lies between cone shoulder 227 and ring 234.
Rings 232, 234 are located on opposing ends of the element 230
between the element 230 and slip 222 or slip 224, respectively.
[0038] Ratchet ring 260, positioned in a groove formed at least in
part from cone 240, has a plurality of teeth configured to engage
mandrel teeth 270 on the outer surface of mandrel 210. It will be
appreciated that shoulder 227 of cone 240 may be flatter than
shoulder 127 of cone 140 as seen in FIG. 1. The angles of each of
the shoulders may be adjusted, or coordinated with different
element stacks, in order to optimize the strength with which the
slips 224 and 222 hold the tubing in which the device is installed
and/or the force applied to the element or element stack to create
a fluid seal. Ratchet ring 260 is positioned adjacent to bottom
section 250 and one or more surfaces of bottom section 250 may form
at least part of the groove or other structure holding ratchet ring
260 in the desired location.
[0039] Devices according to the disclosure herein may be configured
to withstand greater pressure differentials in one direction than
can be withstood in the other directions. The embodiment of FIG. 3
is configured to withstand, without moving in the well, a greater
net force to the plug side of the tool, e.g. the side including
upper face 212, than the tool can withstand against the bottom
side, the side including bottom section 250, of the tool. Such net
force is typically applied by a higher fluid pressure on one end of
the tool than is applied to the other end. For example, during
fracing operations, fluid pressure may be applied against the
downhole tool 200 and a plug sealing against the upper face 212,
causing a pressure differential across the tool 200 and thereby
applying a net force against the plug side of tool 200. A pressure
differential applying net force in the opposing direction may also
be formed, such as during flowback or production operations, if a
second ball, plug, or debris trapped downwell of the tool engages
the bottom section 250 of the embodiment of FIG. 3. However, the
pressure differential created across a tool during flowback or
production operations is typically less than a pressure
differential from fracturing operations.
[0040] Second slip 224 is arranged to engage a casing, liner, or
other tubular in order to prevent movement of the tool in response
to net force against plug side of the tool. In order to withstand
the larger net force that may occur during a fracing operation,
second slip 224 has a larger gripping force, which may result from
optimizing the gripping surface area, such as by increased number
of teeth, the inclusion of alternative or additional gripping
features, or other optimization.
[0041] In addition, the element stack may come in different
configurations. The element stack in FIG. 1 has a ring 132, 134,
which may be a metal ring, around either side of the element. The
embodiment of FIG. 3 has a metal ring 232, 234 on either side of
the element 230. However, a Teflon.RTM. ring 233, 235 is interposed
between the metal ring 232, 234, respectively, and element 230.
Other element stacks that are or become known in the art are also
within the scope of the present disclosure.
[0042] FIG. 4 shows another embodiment device 300 according to the
present disclosure comprising a mandrel 310, slips 322 and 324,
rings 332 and 335, backup ring 334, element 330, cone 340, bottom
section 350, and ratchet housing 375 which includes ratchet ring
360. Ratchet housing 375 is connected to bottom section 350 and
slidingly engaged with mandrel 310 such that ratchet housing 375
and bottom section 350 telescope over mandrel 310 (or mandrel 310
telescopes into the ratchet housing 375 and bottom section 350)
when the flow control device is set in the tubing. Ratchet housing
375 engages slip 324 such that the ratchet housing 375 may apply
force to slip 324, pushing slip onto cone 340 at the angular
surface 327 of cone 340. This forces slip 324 radially outward and
applies longitudinal force to cone 340, which in turn applies force
to element 330 for creating a fluid seal against the tubing.
[0043] Mandrel 310 comprises at least one upper face 312, an
interior surface 380 at least partially defining the throughbore of
the tool, and mandrel teeth 370 positioned on at least part its
exterior surface. Mandrel 310 may have an enlarged end 315 which
may be of a single piece with the remainder of the mandrel and
function as a setting ring. It will be appreciated that the
compressed element 330 exerts force back towards the upper and
lower setting rings--enlarged end 315 and lock ring housing 375 in
FIG. 3--in an attempt to relax from its compressed state. The
slips, including slip 322 when present, may redirect such force
into the tubing in which the device is set. Slip 322 may thereby
reduce or substantially reduce the tensile load placed on the
mandrel 310 via the setting ring, further facilitating the thinness
of the device wall, including the thin exposed length of the
mandrel.
[0044] It will be appreciated that enlarged section 315 provides
both the plug seat along upper face 312 and functions as a setting
ring. In other words, the setting ring comprises the plug seat in
some embodiments. Similar arrangements can been with respect to the
enlarged sections 115, 215, 515, and 615 and their respective plug
seats 112, 212, 512, and 612. The plug seat must have a minimum
thickness in order to effectively seal with a plug. Further, it is
desirable, and in some cases necessary, that the plug seat have
sufficient strength, material strength coupled with thickness, to
withstand the forces of a plug landing thereon at relatively high
speeds. The plug seat then must withstand the force exerted on the
plug by the fracturing fluids, force exceeding 100,000 lbs, for a
four inch ball at 10,000 psi differential pressure. Embodiments in
which the setting ring comprises the plug seat permit a thinner
wall because the necessary thickness of the plug seat is at least
partially combined in, rather than added to, the necessary
thickness of the setting ring.
[0045] Further, preferred embodiments herein provide that the
setting ring and plug seat are of one piece with the mandrel. Such
configuration allows, as discussed above, the thickness of the
setting ring to provide thickness for the plug seat. Further, there
is no fluid communication into a region between an inner surface of
the setting ring and outer surface of the mandrel (e.g. a threaded
connection of setting ring to mandrel). Prior art devices have
threaded setting rings which allow fluid communication between the
inner surface of the setting ring and the outer surface of the
mandrel. Such arrangement both elongates the exposed section and
precludes sealing of the plug against the setting ring due to leaks
paths through the threads and "behind" the ball. Preventing such
leak paths may be accomplished by using seals, such as o-rings
between separately connected setting ring or setting ring/plug seat
combinations and the use of such seals is within the scope of
embodiments herein.
[0046] Slips 322, 324, rings 332, 335, backup ring 334 and element
stack 330 are arranged around an outer surface of mandrel 310
between mandrel shoulder 321 and ratchet housing 375. Slip 322 is
between mandrel shoulder 321 and ring 332. Slip 324 lies between
cone shoulder 327 and ratchet housing 375. Rings 332, 335 are
located on opposing ends of the element stack 330 between the
element stack 330 and slip 322 or backup ring 334, respectively.
Rings 332, 335 may be of any number of materials depending on the
desired application. In some embodiments rings 332, 335 may be of
ductile iron or other material. Back up rings such as back up ring
334 are also known in the art. Certain embodiment back up rings may
be opposing c-rings made of ductile iron, elastomeric materials
such as poly-ether-ether-ketone (PEEK) or other suitable
elastomers, or an array of other materials.
[0047] Ratchet ring 360, positioned in a groove formed at least in
part from ratchet housing 375, has a plurality of teeth configured
to engage mandrel teeth 370 on the outer surface of mandrel 310.
Anti-preset shear pin 314 engages both ratchet housing 375 and
mandrel 310, preventing telescoping down of the tool, and therefore
setting of slips 322, 324 and of element 330, until the shear pin
is broken. It will be appreciated that shoulder 327 of cone 340 may
have a different angle than shoulder 127 of cone 140 as seen in
FIG. 1. The angles of each of the shoulders may be adjusted, or
coordinated with different element stacks, in order to optimize the
strength with which the slips, 124, 324 in FIG. 1 and FIG. 3,
respectively, grab the tubing in which the downhole tool is
installed. Ratchet ring 360 is positioned adjacent to bottom
section 350 and one or more surfaces of bottom section 350 may form
at least part of the groove or other structure positioning ratchet
ring 360.
[0048] As discussed above, devices according to the present
disclosure may be configured to withstand greater pressure
differentials in one direction than can be withstood in the
opposing direction. The embodiment of FIG. 4 is configured to
withstand, without moving in the well, a greater net force to the
plug side of the device, e.g. the side including upper face 312,
than the device can withstand against the bottom side, the side
including bottom section 350, of the device. Such net force is
typically applied by a higher fluid pressure on one end of the
device than is applied to the other end. For example, during
fracing operations, fluid pressure may be applied against the fluid
control device 300 and a plug (not shown) sealing against the upper
face 312, creating a large pressure differential across the device
300 and thereby applying a net force against the plug side of
device 300. A pressure differential applying net force in the
opposing direction may also be formed, such as during flowback or
production operations, if a second ball, plug, or other debris
trapped downwell of the device engages the bottom section 350
thereof. However, the pressure differential created across a baffle
during flowback or production operations, even if the lower end of
the baffle becomes sanded off or otherwise clogged, is typically
smaller than a pressure differential from fracturing
operations.
[0049] Further, the presence of the upper slip, though not required
in all embodiments, may facilitate through tubing workover
operations. After such operations are completed, the through tubing
and any bottom hole assembly, or "BHA", attached thereto must be
removed. Such tubing or BHA may tag, hang up, or otherwise engage
the lower end of the device, such as device 300. The presence of
upper slip 322 may prevent movement of the device 300 in the tubing
in response to such engagement.
[0050] In the embodiment of FIG. 4, a second slip 324 is arranged
to engage a casing, liner, or other tubular in order to prevent
movement of the tool in response to net force against plug side of
the tool, e.g. the side of the tool where seat 312 is located. In
order to withstand the larger net force that may occur during
fracing operation, second slip 324 has a larger exterior surface,
between 1 and 1.25 inches in width in some embodiments, and is
configured to provide greater holding force than the first slip 322
which is placed on the upwell side of the embodiment of FIG. 4 when
such embodiment is used as a frac baffle.
[0051] Element stacks for tools according to the present disclosure
may also come in different configurations. The element stack in
FIG. 1 has a ring 132, 134, which may be a metal ring, around
either side of the element. The embodiment of FIG. 3 has a metal
ring 232, 234 on either side of the element 230. However, a
Teflon.RTM. ring 233, 235 is interposed between the metal ring 232,
234. The element stack of FIG. 4 may comprise an element 331 of 80
durometer rubber flanked by rings 337, 338 of 90 durometer rubber
between element 331 and rings 332, 335, respectively. Other element
stacks that are or become known in the art are also within the
scope of the present disclosure and such element may be chosen
based on any particular application of the fluid control
device.
[0052] Devices according the present disclosure may be configured
for installation into casing or other tubing of various sizes. In
the run-in position, e.g. before the tool is set, the outer
diameter of the tool must be smaller than the smallest diameter of
the tubing through which the tool is run and into which it is
installed. Further, the element and the slips must have sufficient
capability to expand within the tubing to form a sufficient fluid
seal and grip the tubing wall, respectively, to withstand the
anticipated differential pressure expected to be created across the
tool. Still further, the mandrel must be configured to withstand
the collapse forces from pressure differentials anticipated for the
tool, the tool being designed to limit and/or avoid pressure
differentials applying a burst force. Embodiment tools of the
present disclosure have been shown to have pressure ratings of at
least 4000 psi, such as the embodiment tool in FIGS. 1 to 10,000
psi for the embodiment tools in FIGS. 4 and 6 utilizing a barrel
slip as the lower slip.
[0053] Further, embodiment tools tested have achieved a 10,000 psi
pressure rating using ductile iron of grades with minimum yield
strength of 70 ksi and radial thickness of about 0.44 inches (about
0.875 inches diametrically), permitting the borehole 380 diameter
to exceed 70% of the casing diameter in 4.5'' and 5.5'' casing
sizes.
[0054] In some embodiment tools, the pressure rating of 10,000 psi
is achieved with a mandrel made of ductile iron and having very
thin walls at the exposed length. Specifically, ductile iron with a
yield strength of at least 70 k, and in certain tests 74.5 k, psi
was used in a mandrel, such as mandrel 310 with wall thickness of
about 0.188 inches along the exposed length and through the
portions of the mandrel engaging the sealing stack, cone 340,
ratchet housing 375. These mandrels withstood pressure
differentials of 10,000 psi or slightly greater. In actual
fracturing procedures in a wellbore, embodiment tools according to
FIG. 4, including an exposed length 317 wall thickness of 0.188
inches, withstood fracturing pressure differentials averaging over
8100 psi for more than 2.5 hours. In certain embodiments, the
element, slips, cone, and ratchet ring have a wall thickness of
about 0.25 inches.
[0055] It will be appreciated that the inner diameter of a flow
control device of the present disclosure is determined by three
factors: the drift diameter of the tubing in which the device is to
be installed, the ratio chosen for the outer diameter of the device
relative to the drift diameter, and the wall thickness of the
device itself. The outer diameter of the device will range from
about 95% of the drift diameter to about 98% of the drift diameter
for the tubing size and/or weight with the smallest inner diameter
and, more preferably from about 96.5% of the drift diameter to
97.5% of the drift diameter, including devices having ratios of
about 97% of the drift diameter. Thus, for devices according to the
present disclosure with the largest throughbore for a given casing
size, the inner diameter may be about 98% of the drift diameter
minus 0.875 inches--the 0.875 inches corresponding to two times the
thickness of one wall. Thinner walls may be achievable using higher
yield materials, but such thinner walls may increase drill out time
without providing an appreciably larger throughbore. For embodiment
devices configured to span multiple casing weights, the diameter of
the throughbore may range from about 88% of drift minus 0.875
inches up to 98% of drift minus 0.875 inches for a device designed
to span three casing weights. For devices designed to span two
casing weights, the inner diameter may range from about 92% of
drift minus 0.875 inches to about 98% of drift minus 0.875 inches
in some embodiments or from about 94% of drift minus 0.875 inches
to about 98% of drift minus 0.875 inches.
[0056] For devices spanning multiple casing sizes/weights, it may
be desirable to increase the thickness of the walls in order to
increase outward travel of the slips, e.g. slips 322, 324 of FIG.
4. The outward--radial, or towards the tubing in which a device is
installed--travel of the slips may be limited, at least in part, by
the angular surface 327 of cone 340 for lower slip 324 or by the
angular surface 321 of the setting ring for the upper slip 322.
Making the angular surfaces 321, 327 deeper, such as by thickening
the cone and/or making the slips radially thicker can increase the
ability of the slips 322, 324 to travel outward and engage the
tubing. For devices in 5.5'' casing, for example, to span casing
sizes from 17# to 23#, it may be desirable to increase the outward
stroke of the slips by about 0.25 inches diametrically for a device
with an O.D. suitable for use in 23# casing. This may be done by
increasing the thickness of the cone by 0.25 inches or by
increasing the thickness of the cone and the slips by a combined
0.25 inches, e.g. by thickening each 0.125 inches diametrically.
Such an arrangement may lead to wall thickness of one wall about
0.5 inches to about 0.67 inches. For a device spanning two casing
weights, the outward travel increases by about 0.115 inches. Thus,
the wall thickness may increase by about 0.03 to 0.06 inches (e.g.
up to 0.47 inches or 0.50 inches) when compared to a device
configured for only one casing weight in 5.5'' outer diameter
casing. In 4.5'' inch casing, a device spanning three casing sizes
may, where desired, have a wall thickness of about 0.46 inches to
about 0.49 inches.
[0057] The thin wall enabled by devices according to the present
disclosure allows the larger throughbore sizes of these baffles.
Prior art baffles have wall thicknesses much larger, at least about
0.55 inches (radially, 1.10 inches diametrically) using steel in
the mandrel and about 0.78 inches (radially, 1.56 inches
diametrically) with an iron mandrel.
[0058] FIG. 5 illustrates an embodiment device 300, such as from
FIG. 4, assembled on a wireline adapter kit (WLAK) as it might be
run into a well. Upper face 312, bottom section 350, and shear pin
holes 352 are shown in FIG. 5 for reference.
[0059] The WLAK comprises an outer adapter crossover 415 connected
to setting sleeve 410 which is in turn connecting to setting nut
440. Setting nut has angular surface 442 which complements upper
face 312. WLAK further comprises an inner adapter crossover 420
connected to one end of WLAK mandrel extension 430 and WLAK mandrel
470 is connected to the opposing end of WLAK extension mandrel
430.
[0060] Setting shear pins 354 connect bottom section 350 to WLAK
mandrel 470. In some embodiments, WLAK mandrel 470 may include
shear trap 450. Such shear trap may allow for connection of shear
pin 354 to WLAK mandrel around a lower shoulder of shear pin 354.
The lower shoulder of the shear pin has a greater diameter than the
hole in WLAK mandrel 470 and shear trap 450 through which shear pin
354 passes. Thus, when setting shear pin 354 is broken, the
threaded portion of the shear pin remains in shear pin holes 352
and the sheared off portion of shear pin 354 is contained by WLAK
mandrel 470 in the shear trap 450. Bypass holes 357, which may be
shear pin holes 352 without shear pins placed therein, are shown in
FIG. 5 to illustrate their location relative to other components of
the baffle 300.
[0061] WLAK mandrel extension 430 may contain a check valve, such
as a ball 460 and seat 445 check valve. Embodiment devices such as
disclosed in FIG. 4 may be particularly useful in wellbores with
long lateral or horizontal sections. During run-in prior to
installation, the devices may "fall" through the vertical section
of the well and then may be pumped through a lateral section.
Devices with larger throughbores "fall" more readily because of the
decrease in fluid volume displacement caused by the device. Ports
412, 422, 432 allow fluid communication between the various annuli
of the assembly, facilitating the flow of fluids therebetween and
further facilitating fall of the assembly in a vertical
section.
[0062] The smaller volume displacement of large throughbore devices
means pumping the device along the lateral section may require more
time. The check valve of the assembly in FIG. 5 allows for the
throughbore to be open when the assembly is falling in the vertical
section because fluid pressure on the WLAK mandrel 470 side of the
assembly is greater than on the outer adapter crossover 415 side,
pushing the ball 460 off seat 445 and allowing fluid to flow
through the throughbore. When the assembly reaches the lateral
section of the wellbore, fluid pressure is applied to the well,
such as by pumps at the surface, causing pressure to be higher at
the outer adapter crossover 415 side of the device than at the WLAK
mandrel 470 side, forcing the ball 460 into seat 445 and preventing
fluid flow through the throughbore. The check valve enables the
throughbore to go from an open state to a closed state, increasing
the fluid displacement of the assembly and allowing a given
pressure differential to move the assembly at a higher rate of
speed. The higher speed decreases the run-in time required for the
device to reach its desired location.
[0063] Once the desired position is reached, the setting tool is
actuated. The setting tool may force the outer adapter crossover
415 downward (e.g. toward shear pin 354) while the inner adapter
crossover 420 is held in place. This forces setting nut 440
downward as well, applying force to mandrel (310 in FIG. 4) which
shears anti-preset shear pin 314 and moves the mandrel 310 into
bottom section 350, expanding the slips 322, 324 and compressing
the element 330 as discussed above, thereby setting the baffle.
When the force required to further telescope the bottom section 350
over mandrel 310 exceeds the strength of sheer pins, 354, the sheer
pins break and release the WLAK from device 300. The setting tool
and WLAK can then be removed, where desired, and operations may
proceed.
[0064] Embodiment devices may be very short, having lengths less
than eight inches and as short as six inches for embodiments
holding 4000 psi and as little as 11 inches, or even 10.4 to 10.5
inches, prior to installation, for embodiments rated to about 8500
psi or 10,000 psi. Embodiment tools may telescope down
substantially when set, reducing in length as much as about 2.0 to
about 2.25 inches from the run-in position to the set position for
embodiments according to FIG. 4 and FIG. 6.
[0065] It is desirable that mill out times for embodiment devices
be less than 1 hour, equivalent to about 18 inches of device length
for embodiments according to the present disclosure. Preferably,
mill out times will be less than 45 minutes, or about 15 inches in
length. Even more preferably, mill out times will be less than
about 30 minutes, or about 12 inches or less in length. It will be
appreciated that mill out times will vary depending on the specific
milling conditions used--e.g. type of mill, conveyance on jointed
pipe or coil tubing, location of the milled device in the well, and
other factors.
[0066] Mill out time is not the only consideration in determining
device length. Specifically, longer devices may be desirable if
higher pressure rating is needed because longer element stacks,
longer cones, or longer slips may permit pressure ratings above
10,000 psi in some embodiments. However, the required device length
for a particular pressure differential may be kept to a minimum
using devices according to the disclosure herein as compared to
prior art baffles.
[0067] Another embodiment flow control device is shown in FIG. 6,
comprising a mandrel 510, slips 522 and 524, ring 532, element 530,
cone 540, bottom section 550, and ratchet housing 575 which
includes ratchet ring 560. Ratchet housing 575 is connected to
bottom section 550 and slidingly engaged with mandrel 510 such that
ratchet housing 575 and bottom section 550 telescope over mandrel
510 (or mandrel 510 telescopes into the ratchet housing 575 and
bottom section 550) when the flow control device is set in the
tubing. Ratchet housing 575 engages slip 524 such that the ratchet
housing 575 may apply force to slip 524, pushing slip onto cone 540
at the angular surface 527 of cone 540. This forces slip 524
radially outward and applies longitudinal force to cone 540, which
in turn applies force to element 530 for creating a fluid seal
against the tubing.
[0068] Mandrel 510 comprises at least one upper face 512, an
interior surface 580 at least partially defining the throughbore of
the tool, and mandrel teeth 570 positioned on at least part of its
exterior surface. Mandrel 510 may have an enlarged end 515 which
may function as a setting ring.
[0069] Slips 522, 524 (which may be hardened), ring 532, and
element stack 530 are arranged around an outer surface of mandrel
510 between mandrel shoulder 521 and ratchet housing 575. Slip 522
is between mandrel shoulder 521 and ring 532. Slip 524 lies between
cone shoulder 527 and ratchet housing 575. Ring 532 may be of any
number of materials known in the art depending on the desired
application. In some embodiments rings 532 may be of a ductile
material such as ductile iron or other material.
[0070] Ratchet ring 560, positioned in a groove formed at least in
part from ratchet housing 575, has a plurality of teeth configured
to engage mandrel teeth 570 on the outer surface of mandrel 510.
Anti-preset shear pin 514 engages both ratchet housing 575 and
mandrel 510, preventing telescoping down of the tool, and therefore
setting of slips 522, 524 and element 530 until the shear pin is
broken. It will be appreciated that shoulder 527 of cone 540 may be
optimized to different angles depending on the needed pressure
rating of the flow control device. For example, the angles of the
shoulder may be adjusted, or coordinated with different element
stacks, in order to optimize the strength with which the slips 524
grab the tubing in which the downhole tool is installed. Ratchet
ring 560 is positioned adjacent to bottom section 550 and one or
more surfaces of bottom section 550 may form at least part of the
groove or other structure holding ratchet ring 560 in the desired
location.
[0071] As discussed above, devices according to the present
disclosure may be configured to withstand greater pressure
differentials in one direction than can be withstood in the other
directions. The embodiment of FIG. 6 is configured to withstand,
without moving in the well, a greater net force to the plug side of
the tool, e.g. the side including upper face 512, than the tool can
withstand against the bottom side, the side including bottom
section 550, of the tool. Such net force is typically applied by a
higher fluid pressure on one end of the tool than is applied to the
other end. For example, during fracing operations, fluid pressure
may be applied against the downhole tool 500 and a plug sealing
against the upper face 512 (plug not shown), creating a large
pressure differential across the tool and thereby applying a net
force against the plug side of tool 500. A pressure differential
applying net force in the opposing direction may also be formed,
such as during flowback or production operations, if a second ball,
plug, or debris, trapped downwell of the tool engages the bottom
section 550 of the tool. However, the pressure differential created
across a tool during flowback or production operations is typically
lower than a pressure differential from fracturing operations.
[0072] Second slip 524 is arranged to engage a casing, liner, or
other tubular in order to prevent movement of the tool in response
to net force against plug side of the tool, e.g. the side of the
tool where upper face 512 is located. In order to withstand the
larger net force that may occur during fracing operation, second
slip 524 may have an optimized exterior surface, such as toothed
surface between 1 and 1.25 inches in width in some embodiments, to
provide greater holding force than the similarly configured, but
narrower, first slip 522 which is placed on the upwell side of the
embodiment of FIG. 6.
[0073] FIG. 6 illustrates an embodiment element stack 530 in which
the lower element stack ring 538 is widened. Such embodiment may be
constructed without a ring such as ring 335 or a backup ring such
as back up ring 334, both illustrated in FIG. 4. The lower element
stack ring 538 may be of 95 durometer rubber or other rubber of
suitable mechanical characteristics. Further, cone 540 may have a
cone lock, such as shear pin 544, to prevent movement of the cone
prior to actuation of the setting tool such as is described in
relation to FIG. 5, and connected to the embodiment of FIG. 6 by
shear pins 554.
[0074] Lower section 550 may have an inner surface 555, which may
be adjacent to shear pin holes 552, with a diameter slightly
smaller (e.g. 0.030 inches) than the inner diameter of the mandrel
510. Such inner surface 555 with smaller diameter will prevent
plugs, such as frac balls, located below the flow control device
from lodging within the mandrel and blocking flow therethrough--any
such plug which can pass inner surface 555 can also pass through
the larger throughbore of the mandrel. In embodiments containing
such an inner surface 555, it will be appreciated the throughbore
of the tool will be reduced by a corresponding amount.
[0075] Upper face 512 and lower section 550 may be crenelated. The
crenels of upper face 512 may be coordinated with the crenels of
the lower section 550 for a tool to be installed above the flow
control device. Such crenels operate as a clutch, similar to a
muleshoe on certain prior art frac plugs, preventing a device or
component from spinning, such as if engaged by a mill. Such crenels
aid with mill out when multiple tools are installed, as is known in
the art.
[0076] Another embodiment flow control device 600 is shown in FIG.
7, comprising a mandrel 610, slips 624, element 630, cone 640,
bottom section 650, and ratchet housing 675 which includes ratchet
ring 660. Ratchet housing 675 is connected to bottom section 650
and slidingly engaged with mandrel 610 such that ratchet housing
675 and bottom section 650 telescope over mandrel 610 (or mandrel
610 telescopes into the ratchet housing 675 and bottom section 650)
when the flow control device is set in the tubing. Ratchet housing
675 engages slip 624 such that the ratchet housing 675 may apply
force to slip 624, pushing slip onto cone 640 at the angular
surface 627 of cone 640. This forces slip 624 radially outward and
applies longitudinal force to cone 640, which in turn applies force
to element 630 for creating a fluid seal against the tubing.
[0077] Mandrel 610 comprises at least one upper face 612, an
interior surface 680 at least partially defining the throughbore of
the tool, and mandrel teeth 670 positioned on at least part of its
exterior surface. Mandrel 610 may have an enlarged end 615 which
may function as a setting ring.
[0078] Slips 624 (which may be hardened) and element stack 630 are
arranged around an outer surface of mandrel 610 between mandrel
shoulder 690 and ratchet housing 675. Slip 624 lies between cone
shoulder 627 and ratchet housing 675. Ring shoulder 690 may
function, among other things, as a thimble to help prevent swabbing
of elastomeric components, such as portions of element 630, off of
the mandrel and/or to increase the sealing surface of element 630
and mandrel 610.
[0079] Ratchet ring 660, positioned in a groove formed at least in
part from ratchet housing 675, has a plurality of teeth configured
to engage mandrel teeth 670 on the outer surface of mandrel 610.
Anti-preset shear pin 614 engages both ratchet housing 675 and
mandrel 610, preventing telescoping down of the tool, and therefore
setting of slips 624 and element 630 until the shear pin is broken.
It will be appreciated that shoulder 627 of cone 640 may be
optimized to different angles depending on the needed pressure
rating of the flow control device. For example, the angles of the
shoulder may be adjusted, or coordinated with different element
stacks, in order to optimize the strength with which the slips 624
grab the tubing in which the downhole tool is installed.
[0080] Ratchet ring 660 is positioned adjacent to bottom section
650 and one or more surfaces of bottom section 650 may form at
least part of the groove or other structure holding ratchet ring
660 in the desired position.
[0081] During fracing operations, fluid pressure may be applied
against the downhole tool 600 and a plug sealing against the upper
face 612 (plug not shown), creating a pressure differential across
the tool and thereby applying a net force against the plug side of
tool 600. A pressure differential applying net force in the
opposing direction may also be formed, such as during flowback or
production operations, if a second ball, plug, or debris, trapped
downwell of the tool engages the bottom section 650 of the tool.
However, the pressure differential created across a tool during
flowback or production operations is typically lower than a
pressure differential from fracturing operations.
[0082] Slip 624 is arranged to engage a casing, liner, or other
tubular in order to prevent movement of the tool in response to net
force against plug side of the tool, e.g. the side of the tool
where upper face 612 is located. In order to withstand the larger
net force that may occur during fracing operation, slip 624 may
have an optimized exterior surface, such as toothed surface between
1 and 1.25 inches in length in some embodiments.
[0083] The embodiment of FIG. 7 does not incorporate thimble rings
(such as rings 332 and 335 of FIG. 4) or expansion rings (such as
upper slip 322 and back up ring 335). Element stack 630 has both an
upper element stack ring 637 and a lower element stack ring 638
that are widened relative to the element stack rings 337, 338 of
FIG. 4. The lower element stack ring 638 may be of 95 durometer
rubber or other rubber of suitable mechanical characteristics.
Further, cone 640 may have a cone lock, such as shear pin 644, to
prevent movement of the cone prior to actuation of the setting tool
such as is described in relation to FIG. 5, and connected to the
embodiment of FIG. 7 by shear pins 654.
[0084] Lower section 650 may have an inner surface 655, which may
be adjacent to shear pin holes 652, with a diameter slightly
smaller (e.g. 0.030 inches) than the inner diameter of the mandrel
610. Such inner surface 655 with smaller diameter will prevent
plugs, such as frac balls, located below the flow control device
from lodging within the mandrel and blocking flow therethrough--any
such plug which can pass inner surface 655 can also pass through
the larger throughbore of the mandrel. In embodiments containing
such an inner surface 655, it will be appreciated the throughbore
of the tool will reduced by a corresponding amount.
[0085] Upper face 612 and lower section 650 may be crenelated. The
crenels of upper face 612 may be coordinated with the crenels of
the lower section 650 for a tool to be installed above the flow
control device. During drilling out, the portion of the device 600
below the slips may be pushed down the well until it reaches the
bridge plug, baffle, or other device installed in the well below
it. The crenels of the bottom sub 650 may engage crenels or other
complimentary feature at the top of the next device. Such
engagement may operate as a clutch to prevent spinning, improving
efficiency when milling the device.
[0086] FIG. 8 illustrates certain features of other embodiment
tools. The embodiment tool 700 of FIG. 8 has a mandrel 710, element
stack 730, slip 724, ratchet housing 775 and bottom sub 750
arranged generally as described for the embodiment in FIGS. 6 and 7
above. The embodiment of FIG. 8 includes an upper expansion ring
790, upper element ring 732 and shear ring 796. Further, lock ring
760 is configured to engage teeth on the second diameter 794 of
mandrel 710. In some embodiments, shear pin 744 may hold the cone
740 in the run in position until force is applied to set the tool.
Shear pins 754 may releasably connect the tool 700 with a WLAK or
other device.
[0087] The outer surface of 710 mandrel may have a first diameter
792 and a second diameter 794, the second diameter 794 being
smaller than the first diameter 792. The element or element stack
730 and cone 740 are positioned around the first diameter 792 and
the lower slip 724 is positioned around the second diameter 794.
The second diameter allows increased thickness for both cone 740
and slip 724 without increasing the gauge, the maximum outer
diameter, of the tool 700. Thicker cones and/or slips, permitting
increased radial travel for the slips, facilitate setting of the
slips in casing with larger internal diameter relative to the outer
diameter of the tool. For example, the embodiment of FIG. 8 may
have a pressure rating of 10,000 psi set in casing approximately
8-10% larger than the gauge of the tool. An embodiment tool such as
found in FIG. 6, with the same gauge and internal diameter, may
have a significantly lower pressure rating because the teeth of the
slips 724 are unable to penetrate the casing to the same degree.
Thus, the embodiment of FIG. 8 may be preferable in wells
discovered to have over-torqued connections, or other obstructions,
which reduce the effective drift of the casing string to a value
below the nominal drift of the tubing which makes up such casing
string.
[0088] During setting of the slip 724, the slip 724 engages the
casing and the slip teeth may penetrate the casing. The force of
the slip 724 against the casing is also applied radially inwardly
from the slip 724 to the cone 740. If the contact area between the
cone 740 and slip 724 becomes unacceptably small, the cone 740 may
fail. Thickening of the cone 740 permits an increase in the contact
area between the cone 740 and the slip 724 when the slip 724 is
set. Such increase in available contact area allows for the inward
force to be dispersed over a sufficient area of the cone 740 to
prevent cone failure.
[0089] Increasing thickness of the cone 740, however, may
unacceptably increase the gauge of the tool 700. The embodiment of
FIG. 8 addresses this concern by using two surfaces of the cone
740, one with positive slope and one with negative slope, for
supporting the slip 724. Such an arrangement preserves the cone 740
surface area over which the inward force of the slips 724 is
spread. In the embodiment of FIG. 8, cone 740 is flanked by slip
724 and cone extension 736 and has a first angular surface 727 and
a second angular surface 728.
[0090] Cone extension 736 may be an expansion ring and has a slip
support surface 785 with an angle corresponding to the first
angular surface 727 of cone 740. Cone extension 736 has an angular
cone engagement surface 782 in contact with the second angular
surface 728 of cone 740 and a ring engagement surface 784 in
contact with a surface of element ring 735. As the bottom section
750 and the plug seat 712 are moved towards one another, slip 724
is moved up first angular surface 727, expanding outwardly toward
the casing. Cone extension 736 is squeezed between element ring 735
and second angular surface 728 to move cone extension 736 radially
outward toward the casing. After sufficient movement, first end 786
of slip 724 passes the end of angular surface 727. The movement of
cone extension 736 places slip support surface 785 in position to
engage the first end 786 of slip 724 while cone extension 736
remains engaged with second angular surface 728. In some
embodiments, the cone extension 736 will contact the slip 724 at a
position, and/or around a circumference or other perimeter, that is
radially outward from the outer diameter 741 of cone 740.
[0091] FIG. 9 shows the embodiment of FIG. 8 in the set position.
Slip 724 is engaged with the cone extension 736 which is in turn
engaged on the second angular surface of cone 740. Slip 724 also
remains partially engaged on first angular surface 727 of the cone
740. Thus, inward force from slip 724 is applied to a surface of
other than first angular surface 727 of cone 740. Further, in this
embodiment, slip 724 is engaged with, and supported by, a surface
that is radially outward of the gauge for the cone 740.
[0092] The use of the shear screws, or other releasable element for
connecting the WLAK in the bottom section (e.g. to items 150, 250,
350, 550, 650 and 750) may help facilitate flexibility in materials
selected for producing some embodiments according the present
disclosure. Specifically, setting of the tool will involve
principally and, in some embodiments substantially only,
compressive forces as the mandrel and bottom sub are forced
together to set the slips and the element. Some embodiments
according to the present disclosure will experience compressive
forces which exceed tension forces by a large margin, allowing use
of materials which withstand compression loads much better than
tension loads. Thus, materials with lower tensile strengths,
including composite or other materials, may be useful for
manufacture of the mandrel or other components.
[0093] Generally, the component parts of devices herein are made
from ductile iron having a minimum yield strength of 45k psi. The
slips may be made of hardened steel to improve their gripping
characteristics. Further, as discussed herein, certain parts, such
as the mandrel or cone may be made from materials with higher yield
strengths, such as ductile iron with a minimum yield strength of at
least 70 k psi. Further, it will be appreciated that some
components may be made from composite materials or other materials
good with machinability, even when the yield strengths of such
materials are relatively low compared to commonly used steels.
[0094] FIG. 10A illustrates an embodiment device 500, such as from
FIG. 6, assembled on an alternative wireline adapter kit (WLAK)
comprising degradable material for certain portions. Upper face
512, bottom section 550, and bypass holes 557 are shown in FIG. 10A
for reference.
[0095] The WLAK may be generally configured according to the WLAK
of FIG. 5. An outer adapter crossover (shown as item 415 in FIG. 5)
may be connected to setting sleeve 810 which is in turn connecting
to setting nut 840. Setting nut 840 has at least one surface which
complements an opposing surface on the top of mandrel 510, which
may be seating surface 512 or another surface. The WLAK further
comprises an inner adapter crossover 820 connected to degradable
plug 825 which is connected to one end of WLAK mandrel extension
830, which may also be made of degradable materials. Lower adaptor
870 is connected to the opposing end of WLAK mandrel extension
830.
[0096] Lower adaptor may engage a surface of bottom section 550,
such as through circumferential shoulder 873, for applying setting
force. Such arrangement may eliminate the need for shear pins to
connect bottom section 550 to lower adaptor 870. Bypass holes 557
are shown in FIG. 10A to illustrate their location relative to
other components of the baffle 500. Such bypass holes may increase
the available fluid flow area from the outside of the tool 500 to
the interior flowpath when the bottom adaptor 870 is engaged with
bottom section 550.
[0097] FIG. 10B illustrates one embodiment degradable WLAK
extension 800. The illustrated embodiment of degradable WLAK
extension 800 may include degradable plug 825, degradable mandrel
extension 830, and degradable lower adaptor 870. Inner adaptor
crossover 820 may be releasably connected to the degradable plug
825, and such releasable connection can be configured to shear,
break, or otherwise release in response to the selected setting
force on the flow control device 510. Inner adaptor crossover 820,
and the remainder of the wireline string, may be released from the
device 500 while the degradable WLAK extension 800 remains with the
flow control device 500.
[0098] Degradable WLAK extension 800 may be configured to function
as a check valve. For example, if WLAK mandrel extension 830 is
sufficiently long, degradable plug 825 may be able to move relative
to angular surface 512. When the fluid pressure below flow control
device 500 is greater than the fluid pressure above flow control
device 500, plug 825 may be pushed off the angular surface 512,
facilitating fluid flow through the interior flowpath. When fluid
pressure above the flow control device 500 is greater, degradable
plug 825 is pressed into angular surface 512, inhibiting fluid flow
through the interior flowpath and allowing the wireline string,
including WLAK and flow control device 800 to be pumped down the
well, such as along a lateral section of a well towards the
toe.
[0099] Once the desired position is reached, the setting tool is
actuated. The setting tool may force the outer adapter crossover
and setting sleeve 810 downward (e.g. toward bottom section 550)
while the inner adapter crossover 820 is held in place. This forces
setting nut 840 downward as well, applying force to mandrel (510 in
FIG. 6) which shears anti-preset shear pin 514 and moves the
mandrel 510 into bottom section 550, expanding the slips 522, 524
and compressing the element 530 as discussed above, thereby setting
the baffle. When the force required to further telescope the bottom
section 550 over mandrel 510 exceeds the strength of the releasable
connection, the connection releases the WLAK from the WLAK
extension, such as degradable WLAK extension 800. The setting tool
and WLAK can then be removed, where desired, and operations may
proceed.
[0100] Once the tool is set and the wireline string, including the
WLAK and the setting tool, is removed from the well, fluid pressure
applied to the degradable plug 825 pushes the plug into the angular
surface 512, sealing the interior flowpath of the fluid control
device 500. This eliminates the need to drop a ball or other plug
from surface to seal against the flow control device 500. Fluids
above the flow control device 500 are diverted into perforations,
open ports, or other openings in the tubing string immediately upon
application of surface pressure to the fluid column rather than
flowing through the flow control device to segments below the
device. Such arrangement may reduce the amount of water or other
fluids required for treating one or more stages of the well using
flow control devices such as the embodiments described herein or
other embodiment baffles.
[0101] Other geometries for the degradable WLAK extension, or any
of the parts thereof, are within the scope of the present
disclosure provided that such devices provide a seal inhibiting
fluid communication through the interior flowpath when fluid
pressure is higher above the device than below device; are made of
degradable materials such that the interior flowpath becomes at
least substantially unobstructed due to degradation of the WLAK
extension and/or its component; and the WLAK extension is effective
in transferring and/or applying the forces necessary to change the
flow control device from the run-in state to the set state.
[0102] Devices according to the present disclosure are described
with reference to specific embodiments. Alternatives to the
described arrangements will be apparent from a review of the
embodiments of the disclosure and such alternatives are within the
scope of the invention as claimed. While the embodiments may be
described as being made of ductile iron or ductile iron having a
particular yield strength, the invention as claimed is not limited
to embodiments so constructed. Further certain materials are
described according to terms such as dissolvable, degradable, or
disintegrable. It will be appreciated that wellbore conditions and
the treatment will affect the specific material used and
embodiments within the scope of the invention as claimed may
incorporate any such material regardless of whether such material
is characterized as degradable, dissolvable, disintegrable,
melting, decomposing, breaking down, or any term reflecting the
disappearance of the assembly or component.
* * * * *