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Patent 2487012 Summary

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(12) Patent: (11) CA 2487012
(54) English Title: METHOD AND APPARATUS TO REDUCE DOWNHOLE SURGE PRESSURE USING HYDROSTATIC VALVE
(54) French Title: PROCEDE ET APPAREIL PERMETTANT DE REDUIRE LES AUGMENTATIONS SUBITES DE LA PRESSION DE FOND AU MOYEN D'UNE SOUPAPE HYDROSTATIQUE
Status: Deemed expired
Bibliographic Data
(51) International Patent Classification (IPC):
  • E21B 21/08 (2006.01)
  • E21B 17/00 (2006.01)
  • E21B 21/10 (2006.01)
  • E21B 34/06 (2006.01)
  • E21B 34/10 (2006.01)
  • E21B 34/14 (2006.01)
  • E21B 43/10 (2006.01)
(72) Inventors :
  • GIROUX, RICHARD (United States of America)
  • HAUGEN, DAVID M. (United States of America)
  • HOSIE, DAVID (United States of America)
(73) Owners :
  • WEATHERFORD TECHNOLOGY HOLDINGS, LLC (United States of America)
(71) Applicants :
  • WEATHERFORD/LAMB, INC. (United States of America)
(74) Agent: DEETH WILLIAMS WALL LLP
(74) Associate agent:
(45) Issued: 2008-01-15
(86) PCT Filing Date: 2003-05-29
(87) Open to Public Inspection: 2003-12-11
Examination requested: 2004-11-23
Availability of licence: N/A
(25) Language of filing: English

Patent Cooperation Treaty (PCT): Yes
(86) PCT Filing Number: PCT/US2003/016800
(87) International Publication Number: WO2003/102367
(85) National Entry: 2004-11-23

(30) Application Priority Data:
Application No. Country/Territory Date
10/157,743 United States of America 2002-05-29

Abstracts

English Abstract




An apparatus (100) for reducing pressure surges in a wellbore comprising a
body having a bore (124) therethrough, the bore providing a fluid path for
wellbore fluid between a first and second end of the body, at least one fluid
path (122) permitting the wellbore fluid to pass between the bore and an
annular area formed between an outer surface of the body and the walls of a
wellbore therearound, and a number of closure mechanisms (110) whereby the at
least one fluid path is selectively closable to the flow of fluid.


French Abstract

L'invention concerne un appareil (10) servant à réduire les augmentations subites de pression dans un puits de forage. Cet appareil comprend : un corps traversé par un orifice (124) qui constitue un chemin pour le liquide du puits de forage entre une première et une deuxième extrémité dudit corps ; au moins un chemin (122) qui permet au liquide du puits de forage de passer entre cet orifice et une zone annulaire ménagée entre une surface extérieure du corps et les parois d'un puits de forage qui entourent ce corps ; ainsi qu'un nombre de mécanismes de fermeture (110). Ce/ces chemin(s) peut/peuvent être fermé(s) sélectivement pour empêcher l'écoulement de fluide.

Claims

Note: Claims are shown in the official language in which they were submitted.




17


CLAIMS:


1. A method of reducing fluid surge in a tubular string, comprising:
running the string into a wellbore the string having a surge reduction
apparatus,
the apparatus including:
a body having a bore therethrough, the bore providing a fluid path from a
lower end to an upper end of the body;
at least one fluid bypass path permitting the wellbore fluid to pass from
the lower end of the body to an annular area formed between an outer surface
of
the body and the walls of a wellbore therearound; and
whereby the at least one fluid bypass path is selectively and redundantly
closable to the flow of fluid; permitting the wellbore fluid that enters the
lower end
of the body during running of the string to flow through the at least one
fluid
bypass path; and
closing the at least one fluid bypass path, whereby redundant closing includes

the use of a breakable piston sleeve and at least one member of the group
consisting of
rupturing a disc at hydrostatic pressure and breaking a breakable plug.

2. A method of reducing fluid surge in a tubular string, comprising:
running the string into a wellbore the string having a surge reduction
apparatus,
the apparatus including:
a body having a bore therethrough, the bore providing a fluid path from a
lower end to an upper end of the body;
at least one fluid bypass path permitting the wellbore fluid to pass from
the lower end of the body to an annular area formed between an outer surface
of
the body and the walls of a wellbore therearound; and
whereby the at least one fluid bypass path is selectively and redundantly
closable to the flow of fluid; permitting the wellbore fluid that enters the
lower end
of the body during running of the string to flow through the at least one
fluid
bypass path; and
closing the at least one fluid bypass path, whereby redundant closing includes

the use of a breakable piston sleeve and at least one member of the group
consisting of
rupturing a disc at hydrostatic pressure and transporting a sleeve from the
surface.



18


3. A method of reducing fluid surge in a tubular string, comprising:
running the string into a wellbore the string having a surge reduction
apparatus,
the apparatus including:
a body having a bore therethrough, the bore providing a fluid path from a
lower end to an upper end of the body;
at least one fluid bypass path permitting the wellbore fluid to pass from
the lower end of the body to an annular area formed between an outer surface
of
the body and the walls of a wellbore therearound; and
whereby the at least one fluid bypass path is selectively and redundantly
closable to the flow of fluid; permitting the wellbore fluid that enters the
lower end
of the body during running of the string to flow through the at least one
fluid
bypass path; and
closing the at least one fluid bypass path, whereby redundant closing includes

the use of a breakable piston sleeve and at least one member of the group
consisting of
the use of a breakable plug and transporting a sleeve from the surface.

4. A method of reducing fluid surge in a tubular string, comprising:
running the string into a wellbore the string having a surge reduction
apparatus,
the apparatus including:
a body having a bore therethrough, the bore providing a fluid path
between a first and second end of the body;
at least one fluid path permitting the wellbore fluid to pass between the
bore and an annular area formed between an outer surface of the body and the
walls of a wellbore therearound; and
whereby the at least one fluid path is selectively closable to the flow of
fluid by introduction of a mechanical force causing a breakable piston sleeve
to
displace; and
closing the at least one fluid path.

5. The method of claim 4, whereby the at least one fluid path is selectively
closable to
the flow of fluid by at least three different closing mechanisms.

6. A bypass valve for use in a downhole assembly, comprising:



19


a body having a bore therethrough, the bore providing a fluid path between a
first
and second end of the body;
at least one fluid bypass path permitting the wellbore fluid to pass between
the
bore and an annular area formed between an outer surface of the body and the
walls of
a wellbore therearound; and
a breakable piston sleeve capable of displacing to close the at least one
fluid
bypass path to the flow of fluid upon introduction of a mechanical force to
the breakable
piston sleeve.

7. The bypass valve of claim 6, whereby the at least one fluid path is
selectively closable
to the flow of fluid by at least three different closing mechanisms.

Description

Note: Descriptions are shown in the official language in which they were submitted.



CA 02487012 2004-11-23
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METHOD AND APPARATUS TO REDUCE DOWNHOLE
SURGE PRESSURE USING HYDROSTATIC VALVE
BACKGROUND OF THE INVENTION

Field of the Invention

The present invention generally relates to an apparatus and a method for
reducing
downhole surge pressure while running a liner into a wellbore. More
particularly, the
invention relates to an apparatus and a method for reducing surge pressure by
opening and closing ports to allow fluid and mud flow to flow within an
annulus
between the wellbore and a circulation tool.

Description of the Related Art

For a long time, the oil-well industry has been aware of the problem created
when
lowering a liner string at a relatively rapid speed in drilling fluid. This
rapid lowering
of the liner string results in a corresponding increase or surge in the
pressure
generated by the drilling fluid below the liner string. A liner string being
lowered in to
a wellbore can be analogized to a tight fitting plunger being pushed in to a
tubular
housing. Although there is a small annular clearance between the liner and the
wellbore, the fluid bypass rate is limited. The faster the liner is lowered,
the more
fluid builds up below it due to the limited bypass and this creates an
increased
pressure or surge below the liner as it is lowered in to the wellbore. Of
particular
concern is surge related damage due to exposed formation below the liner
string.
This surge pressure has been problematic to the oil-well industry in that it
has many
detrimental effects. Some of these detrimental effects are 1) lost volume of
drilling
fluid; it is not unheard of to lose 50,000 or more barrels of fluid while
running the
liner, wherein present costs are $40 to $400 a barrel depending on its
mixture, 2)
resultant weakening and/or fracturing of the formation when this surge
pressure in
the borehole exceeds the formation fracture pressure, particularly in highly
permeable formations, 3) loss of cement to the formation during the cementing
of the
liner in the borehole due to the weakened and, possibly, fractured formations
which
result from the surge pressure on those formations, and 4) differential
sticking of the
drill string or liner being run into a formation during oil-well operations,
that is, when
the surge pressure in the borehole is higher than the formation fracture
pressure, the


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2

loss of drilling fluid to the formation allows the drill string or liner to be
pulled against
the permeable formation downhole thereby sticking the drill string or liner to
the
permeable formation.

This surge pressure problem is further exasperated when running tight
clearance
liners or other apparatus in the existing casing. For example, clearances
between a
typical liner's Outer Diameter (O.D.) and a casing's Inner Diameter (I.D.)
are'/2" to
'/a". The reduced annular area in these tight clearance liner runs results in
correspondingly higher surge pressures and heightened concerns over their
resulting
detrimental effects.

Typically, surge pressures are minimized by decreasing the running speed of
the drill
string or liner downhole to maintain the surge pressures at acceptable levels.
An
acceptable level is a level at least where the drilling fluid pressure,
including the
surge pressure, is at least less than the formation fracture pressure. The
problem
with decreasing running speed is that more time is required to complete the
liner
placement. That is economically disadvantageous in today's environment where
drilling rig rates can be as high as $300,000.00 per day.

U.S. Pat. No. 5,960,881, discloses a downhole surge pressure reduction system
to
reduce the pressure buildup while running in liners. The surge reduction
device
disclosed therein is located immediately above the top of the liner. Plugging
of the
float valve at the lower end of the liner can, render the surge pressure
reduction
system of the '881 patent ineffective.

U.S. Pat. No. 2,947,363, proposes a fill-up valve for well strings that
includes a
movable sleeve in a housing. As taught by the '363 patent, after a
predetermined
amount of fluid has been admitted, a ball is dropped on the sleeve and
pressure
applied to move the sleeve downwardly to misalign the ports to a closed port
position. Fingers on the sleeve are stated to interlock with teeth to stop
upward
movement of the sleeve. While the ball could be moved up the housing by an
upward flow of pressurized fluid, the ball cannot be blown or forced
downwardly
through the sleeve. Therefore, this fill-up valve does not provide full
opening for inner
drill string work to be accomplished at a depth below the fill-up valve.


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3

U.S. Pat. No. 3,376,935, proposes a well string that is partially filled with
fluid during
a portion of its descent into a well and, thereafter, selectively closed
against the entry
of further fluid while descent of the well string continues ('935 patent, col.
1, ins 25 to
47). As best shown in FIGS. 3 to 5 of the '935 patent, a ball seats on a ball
seat to
move the sleeve downwardly to a closed port position. Upon a predetermined
pressure the seat deforms, as shown in FIG. 5, to allow the ball to pivot the
flapper
valve downwardly and pass out of the housing 3 ('935 patent, col. 6, Ins 32 to
60).
The flapper check valve prevents flow of fluid (e.g. drilling fluid) up
through the
housing ('935 patent, col. 4, ins 60 to 73), whether or not the sleeve is in
the open
port position (FIG. 3) or the closed port position (FIGS. 2, 4 and 5).
Additionally, as
best shown in FIGS. 1 and 2, the inside diameter of the sleeve is less than
the inside
diameter of the drill string or pipe interior, thereby creating a restriction
in the string.
While this tool allows movement of fluids from the annulus, adjacent the ports
of the
tool, to flow up the drill string, the surge pressure created by apparatus
uses, below
the tool, is not alleviated.

U.S. Pat. No. 4,893,678, proposes a multiple-set downhole tool and method of
use of
the, tool. While confirming the oil-well industry desire for "full bore"
opening in
downhole equipment, the '678 patent proposes the use of a ball to move a
sleeve to
misalign a port in the sleeve and a passage in the housing. Additionally,
while the
ball can even be "blown out," the stated purpose of the apparatus in the '678
patent
is to activate a tool, and more particularly, to inflate an elastomeric packer
('678
patent, col. 1, ins 20 to 25 and col. 3, in 14 to col. 4, In 42), not to
reduce surge
pressure while running a drill string with a casing liner packer or other
apparatus
downhole.

A Model "E" "Hydro-Trip Pressure Sub" No. 799-28, distributed by Baker Oil
Tools, a
Baker Hughes company of Houston, Tex., is installable on a string below a
hydraulically actuated tool, such as a hydrostatic packer to provide a method
of
applying the tubing pressure required to actuate the tool. To set a
hydrostatic packer,
a ball is circulated through the tubing and packer to the seat in the "Hydro-
Trip
Pressure Sub," and sufficient tubing pressure is applied to actuate the
setting
mechanism in the packer. After the packer is set, a pressure increase to
approximately 2,500 psi shears screws to allow the ball seat to move down
until


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4

fingers snap back into a groove. The sub then has a full opening, and the ball
passes
on down the tubing.

U.S. Pat. No. 5,244,044, proposes a similar catcher sub using a ball to
operate
pressure operated well tools in the conduit above the catcher sub. However,
neither
the Baker nor the '044 tool provides for reduction of surge pressure by
diverting fluid
flow into the annulus between the drill string and casing.

SUMMARY OF THE INVENTION

The present invention relates to a downhole surge pressure reduction system
for use
in the oil-well industry. Typically, the tool that is the subject of the
invention is
disposed at an upper end of a string of tubulars or liner to be cemented in a
wellbore.
Installed below the tool is typically a liner hanger running tool that
temporarily holds
the liner string in the wellbore prior to cementing.

More specifically, this invention relates to an apparatus and a method for
reducing
surge pressure while running tubulars into a wellbore. In one embodiment, the
invention provides a means of pre-selecting a desired hydrostatic wellbore
pressure
at which a rupture disc will burst causing wellbore fluid to activate a piston
that will
seal a number of bypass ports. With the piston activated, the tool is
effectively
closed, and the circulation tool may proceed with cementing or other needed
processes.
Alternatively, the tool may be closed by shearing a breakable plug. Shearing
of the
breakable plug allows fluid to activate the piston in the same manner as if a
rupture
disc had burst. Both the rupture disc and the breakable plug, or knock-off
plug, are
forms of frangible members.
In other embodiments, the tool comprises numerous closure members for sealing
the
circulation or bypass ports. Particularly, these closure members may consist
of a
breakable piston sleeve or a sleeve lowered or dropped from the surface. Also
required is a closing mechanism that consists of the closure member as well as
the
equipment required to orient and place the closure member. As envisioned, the
tool
may be closable by more than one method. Thus, it is one object of this
invention to
provide a tool capable of reducing pressure surges in a wellbore wherein the
tool
itself is selectively closable.


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i

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present
invention are
attained and can be understood in detail, a more particular description of the
invention, briefly summarized above, may be had by reference to the
embodiments
thereof which are illustrated in the appended drawings. It is to be noted,
however,
that the appended drawings illustrate only typical embodiments of this
invention and
are not to be considered limiting of its scope, for the invention may admit to
other
equally effective embodiments.

Figure 1 is an elevation view of the present invention schematically showing
the
circulation tool described herein located within a representative borehole.

Figure 2 is a partial section view of a single operation tool, envisioned in
one
embodiment of this invention, prior to make-up. As shown, the threaded sleeve
is in
an open position allowing an operator access to the rupture disc, not shown,
and a
knock-off pin, or break plug. Also visible are the bypass ports in an open
position.

Figure 3 is a partial section view of a single operation tool, envisioned in
one
embodiment of this invention, after make-up. This view is also representative
of
the tool in use downhole prior to rupturing of the disc, and actuation of the
piston.
Also visible are the bypass ports in an open position.

Figure 4 is a partial section view of a single operation tool, envisioned in
one
embodiment of this invention, after the rupture disc has blown, and showing
the
piston in its downward position closing off the bypass ports.

Figure 5 is a partial section view of a single operation tool, envisioned in
one
embodiment of this invention, with a shear bar used to shear the knock-off pin
as an
alternative method to allow fluid flow into the cavity.

Figure 6 is a partial section view of an electrically operated single
operation tool, a
separate embodiment of the present invention.

Figure 7 is a partial section view of the electrically operated single
operation tool,
after the heating coil has melted or burned the wire. As shown, the small
piston or
plug that was being held in place and sealing the hydrostatic pressure chamber
from


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6

the lower atmospheric chamber has lowered and thus allowed the wellbore fluid
a
pathway to enter the lower atmospheric chamber.

Figure 8 is a partial section view of the tool showing an alternative non-
hydraulic
method of closing the bypass ports. In this view, the bypass ports are
mechanically
closed by way of a bridge sleeve that has been lowered from the surface by
means
of a running tool.

Figure 9 is a partial section view of the previous tool showing the bridge
plug in
position and the bypass ports closed.

Figure 10 is a partial section view of another embodiment of the present
invention, in
this case, showing another alternative non-hydraulic method of closing the
bypass
ports. In this embodiment, the piston sleeve consists of an upper body and a
lower
body connected by means of a shear pin. As visible on the lower piston body is
a
recess or undercut that will mate with the running tool's spring loaded dogs.
The
running tool will shear the lower piston body away from the upper piston body
and
place the lower piston body in position to seal the bypass ports.

Figure 11 is a partial section view of the previous embodiment wherein the
running
i
tool has mated with the lower piston body's recesses.

Figure 12 is a partial section view of the tool showing the lower piston body
sealing
the bypass ports. As shown the lower piston body has upper and lower o-rings
and
a locking mechanism that prevents the lower piston body from moving
longitudinally
within the tool.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Generally shown in Figure 1 are some of the components of the system of the
present invention. Visible are a representative rig 2 at the surface 6 of the
earth, a
borehole 10, a formation 4, an exposed formation 14, and a working string 8
above
the tool of the present invention 100. Schematically, fluid flows 12 through
the bore
124 of the tool 100 and out the bypass ports 122 if open.

Figure 2 is a partial section view of a single operation tool 100 prior to
make-up. As
shown, the tool 100 comprises a bore 124 that provides a path for wellbore
fluid to


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7

flow through the interior of the tool 100. At a lower end of the tool 100 are
a series of
bypass ports 122 that when open, as shown, allow a portion of the fluid
entering the
tool 100 to be diverted into an annulus between the drill string and casing
(not
shown). It is this additional fluid flow around the outer diameter of the tool
100 that
reduces the induced surge pressure as the tool and a string of liners are run
into a
wellbore full of fluid.

At an upper end of the tool 100 is located a rupture disc (not shown) that can
be
selected to burst at a predetermined pressure correlating to a predetermined
depth
within the wellbore. The rupture disc, a frangible member, fails due to a
pressure
differential between the wellbore fluid and an upper atmospheric chamber (not
shown) formed around the rupture disc when the access sleeve 114 is closed. In
operation, an operator would select the depth at which he needs the
circulating tool
to close, and from that he could correlate the pressure at which that depth
would be
associated with given all the known fluid and wellbore factors. The rupture
disc 120
and knock-off pin 112 can be installed, inspected, and changed on the rig
floor or
anytime prior to the tool 100 being lowered into the wellbore.

Also at the upper end of the tool 100 is an access sleeve 114 that is
threadedly
connected to the tool 100 and covers a knock-off pin 112 and the rupture disc.
Surrounding the pin and rupture disc are a series of upper and lower o-rings
145 that

seal the upper atmospheric chamber when the access sleeve 114 is in the closed
position.

The knock-off pin 112, another frangible member that is also known as a break
plug,
is designed to be a fail-safe to the rupture disc 120, a back-up that if
needed can be
sheared by a shear-bar or tube 128 (Figure 5) or similar device, known to
those in
the field. In this manner the bypass ports 122 are designed to be redundantly
closeable, that is closeable by more than one means.

Figure 3 is a partial section view of the single operation tool 100 after make-
up. The
tool is made-up by installing the pre-selected rupture disc 120 and break plug
112,
then threadedly closing the sleeve in order to form the atmospheric chamber
defining a
flow cavity 133. Visible is the rupture disc 120 located adjacent to the knock-
off pin 112.


CA 02487012 2007-02-08

8
In this view, the access sleeve 114 has been lowered, closed, or sealed; and,
the tool is now ready to be run into a wellbore with a string of liners.

The access sleeve 114 is threadedly connected to the tool 100 between the flow
housing 130 and
an upper sub 116 of the tool 100 and allows access to the break plug 112 and
rupture disc 120. In
the open position both the disc 120 and the break plug or pin 112, can be
inspected, changed,
removed, etc. In the closed position the access sleeve 114 seals off the pin
and disc from external
pressures and only allows inner wellbore fluid to act on them. Also of
significance is that the access
sleeve 114, when closed, creates the flow cavity 113. The flow cavity 113 is
the annulus between
the outer edge of the rupture disc 120 and the inner wall of the access sleeve
114. This flow cavity
113 is linked to a flow path 150 that allows the fluid to act on a piston 110
and a piston set pin 125.
To further seal the flow cavity 113 there are a series of o-rings 145, or
other similar sealants, located
above and below the flow cavity 113. Further, a plug 111 may permit fluid
access to the cavity 113
during assembly of the tool 100 and later seal the cavity 113 from external
pressures.

In normal operation, the fluid, at a pre-set pressure would flow through the
rupture disc 120 and into
the flow cavity 113. From there the fluid passes into the flow path 150 to
actuate the piston 110.
Alternative to the rupture disc 120, a shear bar 128 could be dropped from the
surface and thus
actuate the fluid flow through the knock-off pin 112 and into the flow cavity
113. The piston 110 is
actuated when the fluid pressure overcomes the piston set pin 125 force
holding the piston 110 to
the flow housing 130. Once this preset force is overcome, the piston 110 moves
downward until its
shoulder 140 comes to rest against the lower sub 106. A bumper ring 107
attached to the piston's
shoulder 140 makes contact with the lower sub 106 and this ring 107 cushions
and dampens the
vibrations caused by the piston 110 impacting the lower sub 106. When the
shoulder 140 of the
piston is sitting on the lower sub 106, the lower portion of the piston 110
having o-rings 108
disposed thereon effectively seals the bypass ports 122.

After fluid enters the flow cavity 113 through either the void caused by the
burst of the rupture disc
120 or by the knock-off pin's 112 interior annulus, the fluid will flow
through the flow cavity 113 and
into the flow path 150 to act on the top of the piston 110. The piston 110,
when not acted upon by
the wellbore fluid pressure, is held in place by a piston set pin 125 attached
to a non-moving flow
housing 130. Once fluid enters the flow path 150, the fluid pressure will
cause the piston set pin 125
to shear thus releasing the piston 110 in a rapid downward motion. The
piston's shoulder 140


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9

will bottom out on a lower sub 106, located above the bypass ports 122. The
piston
110 accordingly seals the bypass ports 122 and fluid flow is then only
permitted
through the bore 124 of the tool 100.

Figure 4 is a side view of the same single operation tool after the rupture
disc 120
has burst, and showing the piston 110 in its downward position sealing off the
bypass ports 122. The piston 110, as shown, has bottomed-out and its shoulder
140
is resting on the lower sub 106. In this position, the piston 110 effectively
closes the
bypass ports 122 and prevents further fluid from flowing into the annulus by
way of
the ports 122.

Figure 5 shows a side view of an alternative method, or redundant manner, of
operating the tool by means of a shear bar 128 used to shear the knock-off pin
112
and allow fluid flow into the flow cavity 113. In this view the fluid has
entered the
flow cavity 113 by way of the inner annulus or bore of the knock-off pin 112.
From
there the fluid flows and acts on the piston in the same manner as if it had
burst the
rupture disc 120. The shear bar 128 is generally annular in nature.

Figure 6 is a partial section view of an electrically operated single
operation tool. In
this embodiment, the tool 100 is remotely shifted to a closed position due to
the
response of an electric signal. As with the preferred embodiment described
above,
this tool goes in the hole in an open position.

In this embodiment, a series of ports 160 connect the bore 124 with a
hydrostatic
pressure chamber 175. The hydrostatic pressure chamber 175 contains a heating
coil 170 and a wire 185 holding a frangible member, in this instance, a small
piston
180. The upper surface of the small piston 180 forms the lower boundary of the
hydrostatic pressure chamber 175. As named, the hydrostatic pressure chamber
175 fills with fluid and maintains the pressure of that fluid which is the
same pressure
of the fluid flowing through the bore 124. A small piston 180 along with a
number of
o-rings 190 seal the hydrostatic pressure chamber 175 from the lower
atmospheric
chamber 109. In this manner, a pressure differential is maintained between the
top
surface of the small piston 180 that is exposed to the wellbore fluid and the
bottom
surface of the small piston that is exposed to atmospheric pressure.


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In operation, a signal is sent from the surface, e.g. mud pulse, pipe pinning,
fiber
optics, magnetically charged fluid pumped from the surface, electric wire line
run
internally or externally to the tool, or other method known to those in the
field, that
causes a battery pack (not shown) to activate the heating coil 170 which is
wrapped
5 around the wire 185 holding the small piston or plug 180. The wire 185
holding the
small piston 180 is essentially keeping the hydrostatic pressure from pushing
the
small piston 180 into the lower atmospheric chamber 109 before it is required.

When heated, the wire 185 is weakened and eventually breaks or loosens to a
point
that it can no longer support the small piston 180 and the hydrostatic
pressure acting
10 upon it. Thus, the heating of the wire 185 causes the small piston 180 to
enter the
lower atmospheric chamber 109, exposing the piston 110 to hydrostatic
pressure.
As in the preferred embodiment, the hydrostatic head overcomes the force of
the
piston set pin 125 and causes the piston 110 to move downward and seal the
bypass ports (not shown). As an alternative, a break plug 112 is attached to
the
lower atmospheric chamber 109. If the signal fails to activate the battery
pack a tube
or shear bar, as in Figure 5, can be dropped from the surface closing the
tool.

As shown in Figure 7, the heating coil 170 has melted or weakened the wire 185
such that the hydrostatic pressure acting upon the top surface of the small
piston
180 forces the small piston 180 into the lower atmospheric chamber 109.
Wellbore
fluid is then allowed to make contact with the piston 110 and in the same
manner as
that described above, the piston 110 is forced downward and the bypass ports
(not
shown) are sealed.

This embodiment may also be segmented such that a series of the tool described
immediately above would be connected together, thus allowing for multiple or
repeatable closings and openings. A first piston would close the bypass ports
in the
same manner as that described above in a single signal operated device.
However,
a second unique operation signal could then be sent to the tool and a second
piston
could be operated to open a lower set of bypass ports. The lower set of bypass
ports are closed when a third signal is sent from the surface to move a third
piston to
close the tool. Additional opening and closing segments could be mated
together in
order to satisfy the needs of the operators. Advantageous to this system is
its
repeatability, its ability to open or close the bypass fluid path more than
once.


CA 02487012 2007-02-08

WO 03/102367 PCT/liS03/16800
Il

In yet another embodiment, not shown, the invention allows for multiple, or
repeatable, openings and closings of the bypass ports during a single run
downhole.
In this embodiment, the use of a ratcheted sleeve, akin to that shown in
Figures 4
and 5A-5F of the '331 patent, would allow the tool to be repeatedly set in
either an
open or closed position while downhole. U.S. Pat. Nos. 5,743,311, and
6,116,336, refer to milling systems that allow for the repeated openings and
closing of annular ports through the use of a ratcheted sleeve assembly.

When running downhole it would be advantageous to be able to close the bypass
ports 122 of the tool 100 if increased flow and or fluid is required in the
annulus
between the drill string or tool, or liner and the casing. In this embodiment,
a
ratcheted sleeve and accompanying piston assembly would be configured such
that
an operator on the surface could increases or decreases the fluid pressure in
order
to set the bypass ports in an open or closed position. In this manner the
closing
member could be selectively positioned for the desired result.

In order to accomplish the aforementioned, the tool 100, in addition to having
bypass
ports 122 would incorporate a piston assembly as taught in the pre-mentioned
patents. The piston assembly would comprise a hollow body with a hollow piston
mounted for reciprocal up and down rotative movement therein. The hollow body
having an inwardly projecting lug.

The lug would project through the body into a multi-branched slot of a sleeve.
A
ratcheted sleeve connected to the piston having a branched slot therearound
which
is moveable on the lug so that the ratcheted sleeve and the piston are movable
to a
plurality of positions. The branch slot having a plurality of positions
including a
plurality of recesses and positions for setting the tool, for instance there
would be at
least one position for circulate, and at least one position for non-
circulating. The
branched slot within the ratcheted sleeve would extend around the entire
sleeve for
cycling the piston assembly.

In this manner, an operator on the surface could run the tool 100 downhole,
and if
needed could close and reopen the bypass ports 122 at any time prior to
reaching
his intended depth. Thus this embodiment provides for a cycling, and
consequently


CA 02487012 2007-02-08

WO 03/102367 PCT/US03/16800
12
an infinite number of openings and closings of the bypass ports 122. The
operator
may selectively move the closing member in a back and forth manner, opening
and
closing the bypass ports 122 at will.

To further describe this embodiment, the piston assembly would have a top
bushing
threadedly connected to the piston body. A bottom bushing would be connected
to a
lower end of the piston body. A piston would be movably mounted in a bore of
the
piston body. A spring abuts an upper end of the lower bushing and pushes
against
(upwardly) a thrust bearing set at a bottom of the ratchet sleeve (see FIG. 3C
of the
'0331 patent). A thrust bearing set is disposed between a top of the ratchet
sleeve
and the lower end of the piston (see FIG. 3B of the '0331 patent). The use of
thrust
bearings inhibits undesirable coiling of the spring and facilitates rotation
of the
ratchet sleeve. The thrust bearing sets may include a typical thrust bearing
sandwiched between two thrust washers.

As described, this embodiment allows for multiple openings and closings of the
bypass ports during a single run downhole by means of a piston assembly which
is
responsive to increases and decreases in fluid pressure from the surface in
order to
ratchet a slotted lug into set positions correlating to whether the bypass
ports 122
are open or shut.

Figure 8 is a partial section view of the tool showing an alternative non-
hydraulic
method of closing the bypass ports 122. In this embodiment, the bypass ports
122
are mechanically sealed by way of a bridge sleeve 500 that has been lowered
from
the surface by means of a running tool assembly. As a mechanical alternative,
yet
another alternative means, to closing the bypass ports 122 the bridge sleeve
500
may be lowered or dropped from the surface. In this manner, if the rupture
disc 120
or break-plug 112 fails to either operate or close the bypass ports 122 by way
of a
hydraulically operated piston i 10 shown in Figures 2-4, the bridge sleeve 500
could
be lowered into the wellbore via wire-line, slick-line, coiled tubing, or
other suitable
means. Additionally, the bridge sleeve may be used in the event that a shear
bar or
tube 615 as described in Figure 5 fails to close the bypass ports 122. During
run-in,
the bridge sleeve 500 attaches onto the end of the running tool. Once in
position, the
bridge sleeve 500 locks onto a bottom sub 650 by means of a split ring latch
510.


CA 02487012 2007-02-08

WO 03/102367 PCT/US03/168011
13
The bridge sleeve itself has a series of upper and lower o-rings 520 to assist
in
fluidly sealing the bypass ports 122. In further description, the bridge
sleeve 500
comprises an upper and lower end. At the upper end, an under-cut 530 is formed
so
that the running tool assembly can latch onto the bridge sleeve 500. At the
lower
end of the bridge sleeve 500, a split-ring latch 510 is present which locks
into the
bottom sub 650 of the tool. The split-ring latch 510 locks the bridge sleeve
500 into
the bottom sub 650 of the tool and prevents the bridge sleeve 500 from moving
in an
upward direction once positioned. To further prevent movement of the bridge
sleeve
500, particularly in a downward direction, the bridge sleeve 500 is designed
with a lip
525 that mates with an interior shoulder 502 of the piston 110. Thus, once
positioned, the bridge sleeve 500 mechanically and fluidly seals the bypass
ports
122.

After lowering the bridge sleeve 500 into position, the split-ring latch 510
locks into
the bottom sub 650. The running tool assembly is then pulled-up on and the
bridge
sleeve 500 is released so that the running tool assembly can be retrieved from
the
wellbore leaving the bridge sleeve 500 attached and locked to the tool.

In further description, the running tool assembly comprises at least an upper
body
600, a latching member 610, a mid-housing 640, and a lower body 620. A shear
pin
630 holds the mid-housing 640 and lower body 620 of the running tool assembly
together. The mid-housing 640 is threadedly connected to the upper body 600.
Disposed between the upper and lower bodies is a latching member 610 that is
designed to lock into the under-cut 530 of the bridge sleeve 500. The lower
body
620 is formed with a lower profile member such that upon raising the running
tool
assembly, the profile member will grasp the latching member 610 and release
the
latching member 610 from the bridge sleeve 500.

In operation, when retrieving the running tool, an upward force shears the
shear pin
630 and allows the lower body 620 to move in relationship to the latching
member
610. While in movement, the lower body 620 engages the latching member 610 and
the entire assembly is brought to the surface.

Figure 9 is a partial section view of the previous tool showing the bridge
plug in
position and the bypass ports 122 closed. As shown, the bride sleeve 500 is
locked


CA 02487012 2007-02-08

Vb'O 03/102367 PCT/US03/16800
14

into the bottom sub 650. The upper and lower o-rings 520 of the bridge sleeve
ensure that the bridge sleeve 500 maintains a sealing relationship with the
tool so
that no fluid may flow through the bypass ports 122 when it's in position.

Figure 10 is a partial section view of another embodiment of the present
invention
showing an alternative non-hydraulic method of closing the bypass ports 122.
In this
embodiment, the piston consists of an upper body 900 and a lower body, or
closing
sleeve, 920 connected by means of a shear pin 910. As visible on the lower
piston
body 920 is a recess or undercut 915 that will mate with a key seat tool (not
shown).
By way of mechanical force, the key seat tool will shear the lower piston body
920
away from the upper piston body 900.

In operation, a frangible member may not operate and an altemative non-
hydraulic
means of closing the bypass ports 122 is needed. As described herein and
above,
the features of this tool 100 allow more than one means of closing the bypass
ports
122.

The detachable closing sleeve 920 requires the tool to be internally modified
from
the previous embodiments and/or closing methods. In this design, if the tool
fails to
close hydraulically then the key seat tool, part of a closing mechanism, is
run into the
wellbore on preferably coil tubing, electric wire line, or slick line with a
set down
acting jar, such as a spang jar.

To further describe this embodiment, the key seat tool, shown in Figure 11,
typically
comprises a spring loaded set of dogs that essentially spring into a specific
profile.
The key seat tool latches into the undercuts 915 of the lower piston body 920.
Application of impacts from the jars shears the pin 910 and moves the lower
piston
body, or closing sleeve, 920 down to seal the bypass ports 122. The closing
sleeve
122 latches into the lower sub 106 by means of a detent ring 917, and the key
seat
tool is then retrieved. With the key seat tool out of the hole, normal
cementing
operations can proceed, including the use of standard cementing darts to
launch
cementing plugs in the liner.

To further describe the key seat tool 300, the key seat tool comprises an
upper
housing, a bottom housing 320, a back plate 305, springs 310, and keys or dogs
315. The upper and lower housings are threadedly connected to the back plate
305.


CA 02487012 2004-11-23
WO 03/102367 PCT/US03/16800
The back plate contains recesses or positions for springs 310. Located and
placed
on top of the springs 310 are keys or dogs 315. These keys are designed to
mate
with the undercut profiles of with the closing sleeve 920.

In operation, the key seat tool will latch onto the recess 915 of the closing
sleeve 920
5 and with an application of force from the running tool, the closing sleeve
920 will
separate from the upper piston body 900 and move into a sealingly position
around
the bypass ports 122. The closing sleeve 920 contains upper and lower o-rings
912
to seal the bypass ports 122. Additionally, the closing sleeve 920 also
contains a
detent ring 917. The detent ring 917 remains compressed while the closing
sleeve
10 920 is in relation with the upper piston body 900, as shown. After the
closing sleeve
920 has been separated from the upper piston body 900 via the key seat tool,
the
detent ring 917 will maintain contact with the lower sub 106 until it reaches
an
annulus. At that position, the detent ring 917 expands outwardly and locks the
closing sleeve 920 into position. Once the closing sleeve 920 is locked in a
sealingly
15 position around the bypass ports 122, the key seat tool is disengaged from
the
closing sleeve 920 and brought back to the surface.

Figure 11 is a partial section view of the previous embodiment wherein the key
seat
tool 300 has mated with the closing sleeve's 920 recesses or undercuts 915.
The
tool features a spring 310 loaded set of dogs 315 that latch into the recesses
or
undercuts of the inner diameter profile of the closing sleeve 915. As shown,
the
dogs' profiles are such that when the key seat tool 300 is retrieved from the
bore
124, the dogs can disengage the closing sleeve's undercuts 915.

Figure 12 is a partial section view of the tool showing the lower piston body
or
closing sleeve 920 sealing the bypass ports. As shown, the closing sleeve 920
has
upper and lower o-rings 912 and a locking mechanism, a detent ring 917, which
prevents the closing sleeve from moving longitudinally within the tool. In
this position
the closing sleeve is covering the bypass ports and along with its upper and
lower o-
rings 917 a fluid seal is achieved thus allowing fluid flow only through the
bore 124 of
the tool.

As the forgoing illustrates, the invention reduces downhole surge pressure
while
running a liner string into a wellbore. It achieves that result by allowing
fluid which


CA 02487012 2004-11-23
WO 03/102367 PCT/US03/16800
16
flows through the relatively large inner diameter of the liner during run-in
to exit the
smaller inner diameter of the run-in string and travel through the annulus
between
the run in string and the wellbore. More particularly, the foregoing
illustrates a surge
reduction tool that incorporates redundancy into the means in which the tool
may be
operated, as well as, incorporating repeatable openings and closings. While
the
foregoing is directed to the preferred embodiment of the present invention,
other and
further embodiments of the invention may be devised without departing from the
basic scope thereof, and the scope thereof is determined by the claims that
follow.

Representative Drawing
A single figure which represents the drawing illustrating the invention.
Administrative Status

For a clearer understanding of the status of the application/patent presented on this page, the site Disclaimer , as well as the definitions for Patent , Administrative Status , Maintenance Fee  and Payment History  should be consulted.

Administrative Status

Title Date
Forecasted Issue Date 2008-01-15
(86) PCT Filing Date 2003-05-29
(87) PCT Publication Date 2003-12-11
(85) National Entry 2004-11-23
Examination Requested 2004-11-23
(45) Issued 2008-01-15
Deemed Expired 2021-05-31

Abandonment History

There is no abandonment history.

Payment History

Fee Type Anniversary Year Due Date Amount Paid Paid Date
Request for Examination $800.00 2004-11-23
Application Fee $400.00 2004-11-23
Maintenance Fee - Application - New Act 2 2005-05-30 $100.00 2005-05-20
Registration of a document - section 124 $100.00 2005-05-24
Maintenance Fee - Application - New Act 3 2006-05-29 $100.00 2006-04-26
Maintenance Fee - Application - New Act 4 2007-05-29 $100.00 2007-04-17
Final Fee $300.00 2007-10-17
Maintenance Fee - Patent - New Act 5 2008-05-29 $200.00 2008-04-21
Maintenance Fee - Patent - New Act 6 2009-05-29 $200.00 2009-04-20
Maintenance Fee - Patent - New Act 7 2010-05-31 $200.00 2010-04-14
Maintenance Fee - Patent - New Act 8 2011-05-30 $200.00 2011-04-13
Maintenance Fee - Patent - New Act 9 2012-05-29 $200.00 2012-04-11
Maintenance Fee - Patent - New Act 10 2013-05-29 $250.00 2013-04-10
Maintenance Fee - Patent - New Act 11 2014-05-29 $250.00 2014-04-09
Registration of a document - section 124 $100.00 2014-12-03
Maintenance Fee - Patent - New Act 12 2015-05-29 $250.00 2015-05-06
Maintenance Fee - Patent - New Act 13 2016-05-30 $250.00 2016-05-04
Maintenance Fee - Patent - New Act 14 2017-05-29 $250.00 2017-05-03
Maintenance Fee - Patent - New Act 15 2018-05-29 $450.00 2018-05-09
Maintenance Fee - Patent - New Act 16 2019-05-29 $450.00 2019-04-01
Maintenance Fee - Patent - New Act 17 2020-05-29 $450.00 2020-03-31
Registration of a document - section 124 2020-08-20 $100.00 2020-08-20
Registration of a document - section 124 $100.00 2023-02-06
Owners on Record

Note: Records showing the ownership history in alphabetical order.

Current Owners on Record
WEATHERFORD TECHNOLOGY HOLDINGS, LLC
Past Owners on Record
GIROUX, RICHARD
HAUGEN, DAVID M.
HOSIE, DAVID
WEATHERFORD/LAMB, INC.
Past Owners that do not appear in the "Owners on Record" listing will appear in other documentation within the application.
Documents

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Document
Description 
Date
(yyyy-mm-dd) 
Number of pages   Size of Image (KB) 
Abstract 2004-11-23 2 65
Claims 2004-11-23 10 302
Drawings 2004-11-23 12 265
Description 2004-11-23 16 890
Representative Drawing 2004-11-23 1 17
Cover Page 2005-02-17 1 40
Description 2007-02-08 16 905
Claims 2007-02-08 3 101
Representative Drawing 2007-12-19 1 9
Cover Page 2007-12-19 2 46
Correspondence 2005-02-15 1 27
PCT 2004-11-23 3 87
Assignment 2004-11-23 3 108
Correspondence 2005-04-07 1 32
Assignment 2005-05-24 6 233
Fees 2005-05-20 1 37
Fees 2006-04-26 1 33
Prosecution-Amendment 2006-08-08 5 235
Prosecution-Amendment 2007-02-08 14 711
Fees 2007-04-17 1 36
Correspondence 2007-10-17 1 36
Fees 2008-04-21 1 35
Assignment 2014-12-03 62 4,368