U.S. patent application number 13/860738 was filed with the patent office on 2013-11-07 for downhole plug.
The applicant listed for this patent is WELLTOOLS LIMITED. Invention is credited to Paul Hilliard, Dominic Michael Hoben, Jeffrey Paul Knight.
Application Number | 20130292119 13/860738 |
Document ID | / |
Family ID | 46177149 |
Filed Date | 2013-11-07 |
United States Patent
Application |
20130292119 |
Kind Code |
A1 |
Hilliard; Paul ; et
al. |
November 7, 2013 |
DOWNHOLE PLUG
Abstract
A downhole plug for plugging and method of controlling fluids
within a borehole in an oil and/or gas well. The downhole plug has
a body having a throughbore for the passage of fluids. The plug
also has a mechanical anchoring device that can radially expand an
anchoring member on an outer surface of the body to lock the body
in a fixed axial position within the borehole and an annular
sealing device that can radially expand a sealing member on the
outer surface of the body to seal an annulus formed between the
outer surface of the body and an inner surface of the borehole. The
plug also has a throughbore plugging device that can change
configuration between a first open configuration in which the
throughbore of the body permits the passage of fluid, and a second
closed configuration in which the throughbore resists the passage
of fluid.
Inventors: |
Hilliard; Paul; (Fife,
GB) ; Knight; Jeffrey Paul; (Aberdeenshire, GB)
; Hoben; Dominic Michael; (Edinburgh, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
WELLTOOLS LIMITED |
Fife |
|
GB |
|
|
Family ID: |
46177149 |
Appl. No.: |
13/860738 |
Filed: |
April 11, 2013 |
Current U.S.
Class: |
166/285 ;
166/135 |
Current CPC
Class: |
E21B 33/129 20130101;
E21B 33/1292 20130101; E21B 33/1295 20130101; E21B 33/128 20130101;
E21B 33/1294 20130101 |
Class at
Publication: |
166/285 ;
166/135 |
International
Class: |
E21B 33/127 20060101
E21B033/127 |
Foreign Application Data
Date |
Code |
Application Number |
Apr 11, 2012 |
GB |
1206381.4 |
Claims
1. A downhole plug for plugging a borehole in an oil and/or gas
well, the downhole plug comprising: a body having a throughbore
adapted to permit the passage of fluids through the throughbore; a
mechanical anchoring device adapted to radially expand an anchoring
member on an outer surface of the body to lock the body in a fixed
axial position within the borehole; an annular sealing device
adapted to radially expand a sealing member on the outer surface of
the body to seal an annulus formed between the outer surface of the
body and an inner surface of the borehole; and a throughbore
plugging device adapted to change configuration between a first
open configuration in which the throughbore of the body permits the
passage of fluid, and a second closed configuration in which the
throughbore resists the passage of fluid.
2. A downhole plug according to claim 1, wherein the mechanical
anchoring device has gripping formations for locking the body in a
fixed axial position within the borehole.
3. A downhole plug according to claim 2, wherein the gripping
formations comprise teeth or abrasive material.
4. A downhole plug according to claim 1, wherein the mechanical
anchoring device comprises one or more wedge devices in the form of
slips having tapered surfaces adapted to expand the radial
dimensions of the anchoring member due to relative axial movement
of the slips.
5. A downhole plug according to claim 4, wherein the slips are
moveable axially by an actuator of the mechanical anchoring device,
the anchoring device being moveable axially relative to the
body.
6. A downhole plug according to claim 4, wherein the slips are
moveable axially by a piston of the mechanical anchoring device,
the anchoring device being moveable axially relative to the
body.
7. A downhole plug according to claim 1, wherein the anchoring
member is a grapple device having collet fingers attached to the
mechanical anchoring device in a cantilever manner, free ends of
the fingers are movable radially outwards from an axis of the body
into contact with the inner surface of the borehole.
8. A downhole plug according to claim 7, wherein the other ends of
the fingers are connected by a ring.
9. A downhole plug according to claim 1, wherein the throughbore
plugging device comprises a plugging member adapted to engage on a
seat within the throughbore of the body.
10. A downhole plug according to claim 9, wherein the throughbore
plugging device has a sealing arrangement in the form of an annular
seal set in an inner surface of the throughbore adjacent to the
seat.
11. A downhole plug according to claim 1, wherein the inner surface
of the borehole is the inner surface of casing located in the
borehole.
12. A downhole plug for plugging a borehole in an oil and/or gas
well, the downhole plug comprising: a body having a throughbore
adapted to permit the passage of fluids through the throughbore; a
mechanical anchoring device adapted to radially expand an anchoring
member on an outer surface of the body to lock the body in a fixed
axial position within the borehole; an annular sealing device
adapted to radially expand a sealing member on the outer surface of
the body to seal an annulus formed between the outer surface of the
body and an inner surface of the borehole; a throughbore plugging
device adapted to change configuration between a first open
configuration in which the throughbore of the body permits the
passage of fluid, and a second closed configuration in which the
throughbore resists the passage of fluid; and wherein the
mechanical anchoring device comprises one or more wedge devices in
the form of slips having tapered surfaces adapted to expand the
radial dimensions of the anchoring member due to relative axial
movement of the slips.
13. A downhole plug according to claim 12, wherein the anchoring
device comprises an upper slip, a lower slip and a grapple
sleeve.
14. A downhole plug according to claim 12, wherein the slips have
inwardly facing opposed faces.
15. A downhole plug according to claim 14, wherein the inwardly
facing opposed faces have tapered edges.
16. A method of controlling fluids within a borehole of an oil
and/or gas well, the method comprising providing a well control
device having a body with a throughbore for fluid passage through
the body, a mechanical anchoring device for anchoring the body in a
fixed axial position within the borehole, an annular sealing device
for sealing the annulus between the body and the borehole and a
bore plugging device for closing the fluid pathway through the
body, wherein the method comprises the steps of: running the body
into the borehole; activating the mechanical anchoring device in
order to fix the body in the borehole and resist axial movement of
the body within the borehole; activating the annular sealing device
to seal the annulus between the body and the borehole, thereby
substantially resisting passage of fluid within the annulus past
the annular sealing device; and plugging the throughbore in the
body to resist fluid passage through the throughbore.
17. A method of controlling fluids according to claim 16, wherein
the mechanical anchoring device comprises an anchoring member on an
outer surface of the body and the borehole has an inner surface,
the step of activating the annular sealing device includes sealing
the annulus between the outer surface of the body and the inner
surface of the borehole.
18. A method of controlling fluids according to claim 16, wherein
the annular sealing device is moved from a radially unexpanded
configuration to a radially expanded sealing configuration by
setting weight down on the well control device after the mechanical
anchoring device has been activated and the body is locked in a
fixed axial position within the borehole.
19. A method of controlling fluids according to claim 16, wherein
the step of activating the mechanical anchoring device includes
expanding the mechanical anchoring device.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims the benefit of Great Britain
patent application number 1206381.4 filed on 11 Apr. 2012, the
disclosure of which is hereby incorporated by reference.
RELATED ART
[0002] 1. Field of Invention
[0003] This invention relates to an apparatus and method for the
control of fluids in an oil and/or gas well, typically in the form
of a downhole plug used to close the wellbore.
[0004] 2. Brief Discussion of Related Art
[0005] The production of oil and/or gas from a downhole well
involves drilling of a borehole through a formation containing
production fluids, typically oil or gas, to be recovered through
the borehole. As is known in the art, the upper lengths of borehole
are drilled and then typically cased with a tubular casing cemented
in place to prevent inward collapse of the walls of the borehole.
Drilling operations then resume using a narrower diameter drill bit
deployed through the casing, which drills a further length of the
borehole into the formation below the casing. Sequential radial
steps in the inner diameter of the borehole can be formed in this
manner, until the production zone of the reservoir is reached, and
the production fluids can be recovered using a production string of
tubulars deployed through the radially stepped central bore of the
casing.
[0006] Reservoir fluids to be produced from the well are normally
pressurised, and it is known to use drilling fluid to control
sudden pressure changes in the borehole during drilling. Drilling
fluid (also sometimes called drilling mud) usually comprises a
dense liquid, which helps to contain the reservoir fluids within
the borehole, and has many other functions, such as lubricating the
bit, and washing entrained cuttings back to surface. Typical simple
drilling fluids can include water, but often drilling fluids are
highly engineered fluids with a high density designed to resist
blowouts and other undesirable pressure changes as the drillbit
cuts through the formation.
[0007] Sometimes the drillbit cutting through the formation to
create a new borehole encounters cavities in the formation. These
cavities can present significant challenges for well control,
particularly affecting the practice of pumping well control fluids
such as drilling fluid through the drillstring in order to control
wellbore pressures. Certain large cavities have such a high volume
that the drilling fluid pumped into them simply flows away from the
borehole through the cavity or is otherwise lost from the borehole,
and is then ineffective to control the wellbore pressure changes,
and to perform its other functions. Without reliable pressure
control, such a well often has to be plugged and abandoned, and an
alternative path must be drilled, typically by side-tracking out of
the existing borehole above the cavity.
[0008] Embodiments of the present invention typically provide a
wellbore plugging tool and a method for plugging a wellbore.
INTRODUCTION TO THE INVENTION
[0009] According to the present invention, there is provided a
downhole plug for plugging a borehole in an oil or gas well, the
downhole plug comprising: [0010] a body having a throughbore
adapted to permit the passage of fluids through the throughbore;
[0011] a mechanical anchoring device adapted to radially expand an
anchoring member on the outer surface of the body, to lock the body
in a fixed axial position within the borehole; [0012] an annular
sealing device adapted to radially expand a sealing member on the
outer surface of the body, to seal an annulus formed between the
outer surface of the body and the inner surface of the borehole;
and [0013] a throughbore plugging device adapted to change
configuration between a first open configuration, in which the
throughbore of the body of the tool permits the passage of fluid,
and a second configuration in which the throughbore resists passage
of fluid.
[0014] Typically the body has a central axial throughbore, and has
upper and lower connections at opposite ends of the body,
communicating with the throughbore, and adapted to connect the body
to a string of tubulars within the well. Typically the downhole
plug is run within a drillstring, above a bottom hole assembly, and
typically within a cased borehole. Typically the body is adapted to
operate within conventional sizes of casing, for example casing
with an outer diameter (OD) of 95/8 inch, 7 inch and 5-51/2
inch.
[0015] The downhole plug may be referred to as a tool.
[0016] Typically the mechanical anchoring device is provided on the
outer surface of the body of the tool, and is adapted to expand the
anchoring member radially into contact with the inner surface of
the casing in which the tool is being run. Typically the outer
surface of the mechanical anchoring device has gripping formations
adapted to grip the inner surface of the casing and resist axial
movement of the body of the tool when the mechanical anchoring
device is engaged. Typically the gripping formations can comprise
teeth, or other abrasive or high friction formations or materials,
which bite into the inner surface of the borehole, typically into
the inner surface of the casing.
[0017] Typically the mechanical anchoring device comprises one or
more wedge devices typically in the form of slips or the like
having tapered surfaces adapted to expand the radial dimensions of
the anchoring member as a result of relative axial movement of the
slips. Typically the slips are moved axially by an actuator of the
mechanical anchoring device that moves axially relative to the body
of the tool, and which typically takes the form of a piston.
Typically the mechanical anchoring device comprises pairs of
opposed slips, typically having opposed tapers on upper and lower
axial facing surfaces of the anchoring member. The anchoring member
is typically in the form of a grapple device having collet fingers
attached to the mechanical anchoring device in a cantilever manner,
allowing the free ends of the fingers to move radially outwards
from the axis of the body into contact with the inner surface of
the borehole. Typically the other ends of the fingers are connected
by a ring. Typically the mechanical anchoring device resists axial
movement of the body of the tool in both axial directions across
the device. Typically the mechanical anchoring device is adapted to
expand as a result of axial force in either direction.
[0018] Typically the annular sealing device comprises a resilient
sleeve adapted to radially expand on an outer surface of the body,
typically as a result of axial movement of an actuator relative to
the resilient sleeve. Typically the resilient sleeve seals against
the inner surface of the casing, substantially preventing fluid
flow through the annulus between the inner surface of the casing
and the outer surface of the body.
[0019] Typically the annular sealing device is actuated by an
actuating mechanism which changes the configuration of the annular
sealing device between a first configuration, in which the
resilient sleeve is radially unexpanded and does not engage the
walls of the borehole, and a second configuration, in which the
resilient sleeve has radially expanded to seal between the inner
surface of the borehole (e.g. the casing) and the outer surface of
the body. Typically the actuator mechanism causes axial sliding of
different body parts relative to one another between the first and
second configurations, typically compressing the ends of the
resilient sleeve together, and causing the outward radial expansion
of the resilient sleeve. Typically the annular sealing device is
activated by setting weight down on the body from the surface, and
can be de-activated by picking up weight on the body. Typically the
annular sealing device resists fluid passage within the annulus in
both directions across the device. Typically the annular sealing
device is adapted to expand as a result of axial force in either
direction.
[0020] Typically the annular sealing device is moved from the
radially unexpanded configuration to its radially expanded sealing
configuration by setting weight down on the tool after the
mechanical anchoring device has been activated and the body is
locked in a fixed axial position within the borehole.
[0021] Typically the throughbore plugging device comprises a
plugging member adapted to engage on a seat within the throughbore
in the body. Typically, the throughbore plugging device has a
sealing arrangement, typically in the form of an annular seal set
in the inner surface of the throughbore adjacent to the seat,
typically above the seat, and typically arranged such that when the
throughbore plugging member is engaged with the seat, it is sealed
against the annular sealing member in order to close the
throughbore, and resist fluid passage through the throughbore.
Typically the throughbore plugging device substantially prevents
fluid passage through the throughbore of the body. Typically the
throughbore plugging device resists fluid passage through the
throughbore in both axial directions across the device.
[0022] The invention also provides a method of controlling fluids
within a borehole of an oil or gas well, the method comprising:
[0023] providing a well control device having a body with a
throughbore for fluid passage through the body, a mechanical
anchoring device for anchoring the body in a fixed axial position
within the borehole, an annular sealing device for sealing the
annulus between the body and the borehole and a bore plugging
device for closing the fluid pathway through the body, wherein the
method comprises: [0024] running the body into the borehole; [0025]
activating the mechanical anchoring device in order to fix the body
in the borehole and resist axial movement of the body within the
borehole; [0026] activating the annular sealing device to seal the
annulus between the outer surface of the body and the inner surface
of the borehole, thereby substantially resisting passage of fluid
within the annulus passed the annular sealing device; and [0027]
plugging the bore through the body to resist fluid passage through
the bore.
[0028] The mechanical anchoring device may comprise an anchoring
member on an outer surface of the body and the borehole may have an
inner surface. The step of activating the annular sealing device
may include sealing the annulus between the outer surface of the
body and the inner surface of the borehole.
[0029] The annular sealing device may be moved from a radially
unexpanded configuration to a radially expanded sealing
configuration by setting weight down on the well control device
after the mechanical anchoring device has been activated and the
body is locked in a fixed axial position within the borehole.
[0030] The step of activating the mechanical anchoring device
includes expanding the mechanical anchoring device.
[0031] The various aspects of the present invention can be
practiced alone or in combination with one or more of the other
aspects, as will be appreciated by those skilled in the relevant
arts. The various aspects of the invention can optionally be
provided in combination with one or more of the optional features
of the other aspects of the invention. Also, optional features
described in relation to one embodiment can typically be combined
alone or together with other features in different embodiments of
the invention.
[0032] Various embodiments and aspects of the invention will now be
described in detail with reference to the accompanying figures.
Still other aspects, features, and advantages of the present
invention are readily apparent from the entire description thereof,
including the figures, which illustrates a number of exemplary
embodiments and aspects and implementations. The invention is also
capable of other and different embodiments and aspects, and its
several details can be modified in various respects, all without
departing from the spirit and scope of the present invention.
Accordingly, the drawings and descriptions are to be regarded as
illustrative in nature, and not as restrictive. Furthermore, the
terminology and phraseology used herein is solely used for
descriptive purposes and should not be construed as limiting in
scope. Language such as "including," "comprising," "having,"
"containing," or "involving," and variations thereof, is intended
to be broad and encompass the subject matter listed thereafter,
equivalents, and additional subject matter not recited, and is not
intended to exclude other additives, components, integers or steps.
Likewise, the term "comprising" is considered synonymous with the
terms "including" or "containing" for applicable legal
purposes.
[0033] Any discussion of documents, acts, materials, devices,
articles and the like is included in the specification solely for
the purpose of providing a context for the present invention. It is
not suggested or represented that any or all of these matters
formed part of the prior art base or were common general knowledge
in the field relevant to the present invention.
[0034] In this disclosure, whenever a composition, an element or a
group of elements is preceded with the transitional phrase
"comprising", it is understood that we also contemplate the same
composition, element or group of elements with transitional phrases
"consisting essentially of", "consisting", "selected from the group
of consisting of", "including", or "is" preceding the recitation of
the composition, element or group of elements and vice versa.
[0035] All numerical values in this disclosure are understood as
being modified by "about". All singular forms of elements, or any
other components described herein are understood to include plural
forms thereof and vice versa.
BRIEF DESCRIPTION OF THE DRAWINGS
[0036] An embodiment of the invention will now be described by way
of example only and with reference to the accompanying drawings, in
which:
[0037] FIG. 1 shows a side view of a downhole plug in accordance
with one embodiment;
[0038] FIG. 2 shows a side section view of the device of FIG.
1;
[0039] FIG. 3 shows an end view of the FIG. 1 device;
[0040] FIG. 4 shows a side view of an upper part of the FIG. 1
device showing a throughbore plugging device for closing a bore of
the FIG. 1 device;
[0041] FIG. 5 shows a sectional view of FIG. 4;
[0042] FIG. 6 shows an end view of the FIG. 4 arrangement;
[0043] FIG. 7 shows an exploded view of the FIG. 4 arrangement;
[0044] FIG. 8 shows a side view of the lower part of the FIG. 1
device, comprising a mechanical anchoring device and annular
sealing device;
[0045] FIG. 9 shows a side sectional view of FIG. 8;
[0046] FIG. 10 shows an end view of FIG. 8; and
[0047] FIG. 11 shows an exploded view of FIG. 8.
DETAILED DESCRIPTION
[0048] Referring now to the drawings, apparatus for controlling the
flow of fluid in a borehole in the form of a downhole plug has a
body B, provided with a throughbore T extending between opposite
ends of the body B, the two ends of the body B having box and pin
connectors as are known in the art for connecting the body B into a
string of tubulars in an oil or gas well. Typically, the body B is
connected within a drill string D, typically above a bottom hole
assembly and drill bit, and is typically run into a wellbore within
a casing string C, terminating at the lower end of the casing
string with a casing shoe through which the drill string D is
deployed. Typically the body B can have stabilisers and/or
centralisers on its outer surface in order to space the body B away
from the walls of the casing C. In the drawings, the upper end of
the plug nearest the well head and the surface is shown on the
left, and the lower end is shown on the right, closest to the
bottom of the well, although the skilled person will understand
that in deviated wells, the "upper" end can be at the same depth or
physically deeper than the "lower" end as a result of deviation of
the borehole, so the terms "up", "down", "upper" and "lower" refer
the depth of penetration in the borehole, rather than the actual
depth below the wellhead and similar terms should be interpreted
accordingly.
[0049] The body B comprises a plug sub 10 comprising a throughbore
plugging device, a seal sub 30 comprising an annular sealing
device, and an anchor sub 50 comprising a mechanical anchoring
device, all of which are sequentially arranged from an upper part
of the body B to a lower part but, in other embodiments, the order
of the subs 10, 30, 50 can be changed. At the upper end of the body
B, the plug sub 10 has an outer housing 11 formed in three sections
11a, 11b and 11c, having screw thread connections between the end
housing portions 11a and 11c and the central housing portion 11b,
typically also allowing metal to metal seals to be formed between
the housing portions. The assembled housing 11 has a throughbore T
which houses a sliding sleeve 12 which is biased upwardly within
the bore T by a spring 13 held in compression between an upwardly
facing end of the central portion 11b, and the downwardly facing
surface of a dog collar 15 disposed in the annulus between the
outer surface of the sleeve 12 and the inner surface of the upper
portion of housing 11a. The dog collar 15 has a series of
circumferentially spaced recesses typically spaced substantially
equidistantly around the circumference, and typically passing
radially through the wall of the collar 15, to receive dogs 16,
which are typically adapted to move radially outward from the
collar to locate within an annular dog recess 17 in the outer
surface of the sleeve 12. Above the dog recess 17, the sleeve 12
has a shear pin recess 18 adapted to receive the inner end of at
least one shear pin 20 passing through the body of the upper
portion 11a of the housing, which serves to keep the sleeve 12
fixed axially in the configuration shown in FIG. 5, with the spring
13 held in compression between the dog collar 15 and the central
portion 11b of the housing. Typically the shear pins 20 are
arranged in pairs around the circumference.
[0050] At the other end of the central portion 11b, the lower
portion 11c has a seal recess to house a chevron type seal 19 which
is disposed (optionally in radial compression) between the inner
surface of the housing portion 11c, and the outer surface of the
sleeve 12. Other types of seal can be used in other embodiments.
Typically the seal 19 is radially compressed between the sleeve 12
and the housing portion 11c, and denies fluid passage within the
annular space between the housing 11 and the sleeve 12.
[0051] The lower portion 11c of the housing typically has a
stabiliser S which is typically adapted to space the body of the
plug B radially from the walls of the tubular casing.
[0052] The upper portion of the housing 11a has at least one radial
port 21 passing through the wall of the housing 11a above the shear
pins 20 connecting the throughbore T with the exterior of the plug
body B. When the inner ends of the shear pins 20 are located within
the shear pin recess 18, the sleeve 12 is held in the position
shown in FIG. 5, in which the upper end of the sleeve 12 covers the
ports 21. Typically the annulus between the sleeve 12 and the
housing 11 is sealed, for example by O-ring seals, located above
the ports 21, and by the seals 19 below them, in order to prevent
fluid passing from the throughbore T through the ports 21 and
reaching the exterior of the body B when the sleeve 12 is in the
FIG. 5 position. The ports 21 can be circumferentially spaced
around the body B, typically at a 180.degree. spacing as shown in
FIG. 5.
[0053] The shear pins 20 can be typically circumferentially spaced
around the body B, typically at substantially equidistant spacing
around the circumference, or alternatively, in some configurations,
some of the bores in axial alignment with the shear pin 20 can be
formed as simple ports, to permit additional fluid communication
between the throughbore T and the exterior of the tool.
[0054] Below the shear pins 20, the wall of the upper portion 11a
has an additional radial port 22 connecting the throughbore T with
the exterior of the tool in the same way as the port 21, and
typically terminating on the inner surface of the housing portion
11a within a recess on the inner surface of the housing 11.
[0055] The spring 13 typically has a spring sleeve 14 which
surrounds the outer surface of the spring 13 within the annulus
between the sleeve 12 and the upper housing portion 11a, in order
to restrict the maximum compression of the spring 13. In the FIG. 5
configuration, the upper housing portion 11a connects the sleeve 12
and the housing 11 by means of the shear pins 20, so that the dogs
16 are pressed radially inwards into the recess 17 in the housing,
thereby locking the collar 15 to the sleeve 12 in the FIG. 5
configuration. When the shear pins 20 are sheared as will be
described below, the sleeve 12 is free to move axially downwards
within the throughbore T, until the collar 15 abuts the upper edge
of the spring sleeve 14, and the dogs 16 are axially aligned with
the recess on the inner surface of the housing, at which point the
dogs 16 are free to move radially outwardly into the recess, and
typically have ramped inner surfaces adapted to facilitate that
radial movement, so that they move radially clear of the sleeve 12,
allowing continued downward axial movement of the sleeve 12
independently of the collar 15 within the throughbore T. Thus, upon
shearing of the pins 20, the sleeve 12 can move axially down the
throughbore T to bottom out at the upwardly facing shoulder at the
lower end of the lower portion 11c.
[0056] The upper end of the sleeve 12 has a seat 25 to receive and
seat a throughbore sealing device such as a dart or cylinder which
has a solid structure with no throughbore and is adapted to close
of fluid communication within the throughbore T. The throughbore
sealing device may be referred to as a plugging member. The dart 26
is adapted to engage on the seat 25 as will be described below and
has an outer surface adapted to seal against the seal 19 when the
sleeve 12 has bottomed out on the upwardly facing shoulder at the
lower end of the lower portion 11c. The seal 19 may be an annular
seal and may be set in an inner surface of the throughbore T,
adjacent to the seat 25.
[0057] Referring now to FIGS. 8 to 11, a seal sub 30 and anchor sub
50 are connected below the lower portion 11c of the housing 11 of
the plug sub 10. The seal sub 30 and anchor sub 50 are shown in
this embodiment as an interdependent assembly, but can typically
also be provided as separate subs within the plug. The seal sub 30
comprises a housing 31 having an outer diameter that is continuous
with that of the housing 11, and having a throughbore T
communicating with the throughbore T in the housing 11. The lower
end of the housing 31 has a flat shoulder abutted against a sealing
member in the form of a resilient sleeve 35. The resilient sleeve
35 is slid over the outer surface of an inner tubular mandrel that
is connected to the lower surface of the housing 31 by means of a
screw thread connection and typically by seals so that the housing
31 and the mandrel 40 essentially move as a single unit. The
resilient sleeve 35 is optionally adapted to slide axially and to
rotate relative to the inner tubular mandrel 40, and is adapted to
be deformed as will be described below from its radially
un-extended configuration shown in FIGS. 8 to 11, in which the
outer diameter of the resilient sleeve 35 is essentially the same
as the outer diameter of the housing 31 and housing 11, to a
radially expanded configuration in which the outer diameter of the
resilient sleeve 35 has been radially expanded away from the axis
of the throughbore T, to press against the inner surface of the
casing wall surrounding the body B, thereby sealing the annulus
between the body B and the casing C.
[0058] The inner tubular mandrel 40 also supports certain
components of the anchor sub 50, which are mounted on the outer
surface of the inner tubular mandrel 40 in the same way as the
resilient sleeve 35.
[0059] In particular, the anchor sub 50 comprises an anchoring
member having upper and lower slips 52, 53 and a grapple sleeve 55.
The slips 52 and 53 are typically in the form of sleeves that are
slid over the inner tubular mandrel 40, and which are rotationally
and axially movable relative to the inner tubular mandrel 40 so
that they slide on its outer surface. The inwardly facing opposed
faces of the slips 51 and 52 have tapered edges. The grapple sleeve
55 is disposed on the outer surface of the upper slip 51. The
grapple sleeve 55 is typically in the form of a circumferential
arrangement of collet fingers 56 which are attached together only
at their upper ends by means of a grapple ring 57, leaving their
lower ends unattached, in a cantilever arrangement, and free to
move radially relative to the axis of the throughbore T. As best
shown in FIG. 9, the inner faces of the fingers 56 have a tapered
profile at their lower ends, which is typically tapered in at least
one direction, but optionally, as shown in the current example, the
section profile of the lower end of the fingers 56 can have a taper
in two directions, typically at an angle matching the tapered
opposing ends of the slips 51 and 52. As is shown in FIG. 9 when
the slips 51 and 52 are spaced axially apart from one another, the
tapered profile at the inner ends of the fingers 56 rests within
the V shaped recess provided by the opposing tapered ends of the
slips 51 and 52. Axial sliding movement of the slips 51 and 52
towards one another (or the sliding movement of one slip towards
the other) closes the gap, and pushes the lower ends of the fingers
56 radially outwards away from the axis of the throughbore T as a
result of the taper. Likewise, when the slips 51 and 52 move apart
from one another, the recess between them deepens, allowing the
cantilevered lower ends of the fingers 56 to move back into the
recess, thereby adopting the radially unexpanded configuration
shown in FIG. 9 once more.
[0060] At the lower end of the inner tubular mandrel 40, a piston
sleeve 41 which is received within a larger diameter portion of the
lower end of the inner tubular mandrel 40, and is typically
connected to the inner tubular mandrel 40 by means of shear pins 42
passing through the wall of the enlarged portion of the inner
tubular mandrel 40, and locating in an annular recess at the top of
the piston 41. The piston 41 is typically sealed to the inner
surface of the bore of the inner tubular mandrel 40, and has a
throughbore allowing fluid communication with the throughbore T.
The shear pins 42 are typically arranged in pairs around the
circumference of piston, and between adjacent pins 42, there are
typically provided ports (not shown in FIG. 9) at the same axial
position, permitting fluid communication between the throughbore T
and the annulus between the piston 41 and the mandrel 40.
[0061] Beneath the shear pins 42, the piston sleeve 41 includes at
least one additional shear pin 43, but typically, as is shown in
this arrangement, there can be several pins 43, typically arranged
in a circumferentially spaced pairs, passing radially through the
wall of the inner tubular mandrel 40, and terminating in slots on
the outer surface of the piston 41. Seals above and below the ports
in line with the pins 42 prevent fluid passage between the
throughbore T and the outside of the plug while the piston 41 is
held by the shear pins 42 in the upper configuration shown in FIG.
9.
[0062] The upper face of the piston 41 has a seat for a ball or
dart etc., adapted to be dropped from surface. The diameter of the
seat on the piston 41 is smaller than the diameter of the seat 25
on the sleeve 12, so a smaller ball adapted to seat on the piston
41 and cause its axial movement within the large lower portion of
the inner tubular mandrel 40 can pass through the seat 25 in the
sleeve 12 without activating it.
[0063] The lower end of the inner tubular mandrel 40 has a catcher
device 45 adapted to catch the piston 41 and its activating device
such as a ball etc. and prevent its onward travel axially within
the body B. The catcher device 45 has slots extending radially
through its outer walls, allowing passage of fluid through the
slots 46 into the annulus between the catcher device 45 and the
lower housing 54 of the anchor sub 50.
[0064] The outer surface of the lower housing 54 typically has a
stabiliser S.
[0065] Dropping a ball on the seat of the piston sleeve 41 prevents
fluid passage through the bore of the piston sleeve 41 and builds
up pressure above it. The pressure differential shears the pins 42,
freeing the piston sleeve 41 to move axially down the bore T
towards the catcher device 45. However, the piston is held by the
shear pins 42 above the catcher 45. As will be described later, the
catcher 45 prevents onward axial travel of objects through the bore
T but allows fluid passage past it via the slots 46 and annulus
between the catcher device 45 and the lower housing 54. Axial
downward movement of the piston sleeve 41 uncovers the ports in
line with the pins 42, allowing fluid communication between the
throughbore T and an annulus formed and sealed between the outer
surface of the radially enlarged lower portion of the inner tubular
mandrel 40, and the inner surface of the lower slip 52. Seals (for
example O-ring seals) are typically provided above and below the
outer opening of the ports and pins 42, so the communication of
pressurised fluid from the throughbore T to the annulus between the
inner tubular mandrel 40 and the lower slip 52 creates a piston
effect on the lower slip resulting from the difference in the
sealed diameters on the lower slip 52, causing it to move axially
upwards, closing the gap between the slips 51 and 52, and thereby
causing the free ends of the fingers 56 on the grapple sleeve 55 to
move radially outwards, expanding until they contact and grip the
inner wall of the casing C surrounding the body B.
[0066] The outer surfaces of the fingers 56 typically have gripping
formation such as teeth, abrasive surfaces such as tungsten
carbide, or resilient devices etc. adapted to increase friction
between the grapple sleeve 55 and the inner surface of the casing
C. The angle of the taper can be adjusted to increase or decrease
the extent of radial expansion of the grapple sleeve 55 in
accordance with the desired annular spacing between the body B and
the inner surface of the casing C.
[0067] Therefore, dropping the ball on the piston 41 causes
actuation of the grapple sleeve 55 to grip the inner surface of the
casing C and resist (typically substantially prevent) axial
movement of the grapple sleeve 55 within the borehole.
[0068] Typically the inner surface of the lower slip 52 has a
ratchet surface 58 and the inner surface of the lower slip 52 has a
cooperating ratchet device 59 abutting against a downward facing
shoulder on the inside of the lower slip 52, which restricts axial
movement to a single direction, i.e. upwards movement of the lower
slip 52 relative to the inner tubular mandrel 40. Therefore, once
the lower slip 52 moves up a notch in the ratchet surface 58, it
cannot move down even if the pressure that caused the initial
upward movement reduces. Therefore, the anchoring device can
typically be actuated by pressuring up within the throughbore to a
significantly higher pressure than would be encountered normally,
causing upward movement of the lower slip 52 in a single direction
by virtue of the ratchet mechanism 58, 59 until the anchoring
member comprising the grapple sleeve 55 is securely set preventing
further axial movement of the portion of the string below the
grapple sleeve 55.
[0069] After the mechanical anchoring device has been set by
expanding the anchoring member comprising the grapple sleeve 55
radially outwards to contact and grip the inner surface of the
casing C, the string below the set anchoring device is essentially
immovably anchored by the grapple sleeve 55, but the string above
the set grapple sleeve 55 is still axially moveable within the
borehole. Accordingly, setting weight down from the surface on the
set grapple sleeve 55 slides the housing 31 and the inner tubular
mandrel 40 to which it is attached axially down relative to the set
grapple sleeve 55, causing the resilient sleeve 35 to be compressed
between the movable housing 31 and the upper end of the immovable
upper slip 51. This results in radial expansion of the resilient
sleeve 35 from the radially unexpanded configuration shown in FIG.
9, to a radially expanded configuration, in which it engages
against the inner surface of the casing C, and forms an annular
seal thereby resisting passage of fluid past the seal.
[0070] Setting weight down in this manner typically further
energises the expansion of the grapple sleeve 55 as a result of the
interaction between the tapered surface at the lower end of the
upper slip 51, urging the tapered inner surfaces of the fingers 56
to push them further radially outwards against the inner surface of
the casing C. At the same time, the weight of the string from
surface is transferred through the housing 31 to the inner tubular
mandrel 40, causing the ratchet mechanism 58, 59 to retain the plug
in the radially expanded configuration with the resilient sleeve 35
radially expanded when the weight from surface is removed.
Therefore, the action of setting down weight from surface typically
activates the annular sealing device causing the sealing member
provided by the resilient sleeve 35 to seal off the annulus,
typically in both directions, thereby substantially preventing
fluid from passing the expanded seal provided by the resilient
sleeve 35, even when the weight is removed.
[0071] Once the mechanical anchoring device and the annular sealing
device have been set as described above, the throughbore T is
typically sealed by dropping a dart from surface, to land on the
seat 25 of the sleeve 12, causing the shear pins 20 to shear, and
allowing the downward travel of the sleeve 12 such that the dogs 16
move into the recess on the inner surface of the upper portion 11 a
of the housing, and free the sleeve 12 to travel all the way down
to the bottom of the plug sub 10. When the sleeve 12 is bottomed
out on the upwardly facing shoulder at the lower end of the lower
portion housing 11c, the dart 26 is typically engaged against the
chevron seal 19, thereby preventing fluid passage within the
throughbore T.
[0072] Thus, the plug sub is typically activated by a subsequent
action performed from surface once the mechanical anchoring device
and the annular sealing device have been set.
[0073] Accordingly each step of the procedure, mechanical
anchoring, annular sealing, and plugging of the throughbore, can
typically be independently actuated, and testing of each step can
be performed before subsequent actuations of the other
components.
[0074] Thus the plug 10 described permits mechanical anchoring
within the borehole, annular sealing between the string and the
borehole, and plugging of the throughbore that had previously
allowed fluid transfer through the string, in order to plug the
well.
[0075] Optionally, the plug sub 10 can be provided with a
disconnect device further up the string, which can optionally be of
conventional design, and can typically be provided immediately
above the plug sub 10, allowing disconnect of the string above the
plug after its activation and testing. Typically the plug can be
simply left in its activated state for many years, allowing
possibility to revisit the plug for reversal of the abandonment
procedures if desired, or for testing and monitoring of the
efficacy of the seal. Alternatively, the well can be permanently
abandoned by cementing above the set plug after setting and testing
procedures have been concluded and the casing string above the plug
has been recovered if desired.
[0076] A typical sequence of operation of the above described
embodiment will now be described.
[0077] In a typical operational sequence, during normal drilling
operations, one sign of the drillbit encountering a large cavity is
an increase in losses of drilling fluid, typically accompanied by a
reduction or absence of returns of fluid to the surface, and
sometimes by a reduction in resistance on the bit. When this
occurs, it is generally ineffective to continue to pump drilling
fluid through the drillstring, because as it egresses from the
drillbit, it simply flows away into the cavity, rather than washing
back up the annulus between the drillstring and the borehole. In
this situation, one option is to use Loss Circulation Materials
(LCMs) such as wood fibre, calcium carbonate, ground nut shells,
ground cellulose, shredded cedar fibre. Other LCMs can optionally
be used.
[0078] Loss Circulation Materials (LCM) are typically pumped
through a PBL tool or similar by-pass to try to stem the loss of
drilling fluid, and pumping of LCM through the drillstring and into
the borehole normally constitutes the first attempt at resolution
of borehole problems exhibiting unusually high losses of drilling
fluid. Typically a PBL tool is mounted on the drillstring below the
plug described above and above the Bottom Hole Assembly (BHA).
Sometimes pumping LCM is successful and in that situation normal
drilling can resume. However, in the event that pumping LCM through
the PBL tool does not cure the drilling fluid losses the string is
typically pulled back until the plug sub is above the casing shoe,
and located within the casing string C. At this point, a small
diameter ball is dropped from surface to seat on the piston sleeve
41, and to activate the mechanical anchoring device. Typically, the
axial movement of the sleeve 41 in response to the ball seating on
the top of the sleeve 41 can be limited by shear pins 43, which
have their radially inner ends captive in the slot formed on the
outer surface of the piston sleeve 41. Shear pins 43 can be
provided as a single pin, or as pairs of pins, typically spaced at
180.degree. of circumferential spacing around the piston sleeve 41
as shown in FIG. 9, but multiple pairs of shear pins can optionally
be provided as shown in FIG. 11. Typically the shear pins 43 can
have a higher rating than pins 42, so can retain the sleeve 41
against further axial movement at a pressure threshold that shears
the weaker upper pins 42. Therefore, dropping the ball typically
moves the sleeve 41 axially downwards within the bore of the anchor
sub 50, until the pins 43 have reached the tops of the slots on the
outer surface of the piston sleeve 41, and the ports in between the
shear pins 42 have been exposed, allowing the upward movement of
the lower slip 52 as a result of the differential piston area
between the different diameters of seal. However, further increase
in pressure on the fluid in the throughbore T above the seated ball
can shear the pins 43, driving the piston sleeve 41 into the
catcher device 45, and permitting fluid bypass in the throughbore T
as a result of the slots 46 in the catcher 45.
[0079] When the first ball is dropped to activate the anchor by
uncovering the ports in axial alignment with the pins 42, the
throughbore T is effectively occluded, and it is no longer possible
to drop further balls past the plug 10 in order to activate tools
below it.
[0080] Once the mechanical anchoring device has been set, the
weight is set down in the string above the plug 10 to activate the
annular sealing device to seal off the annulus between the
drillstring and the casing. At this point, the fluid pressure can
optionally be increased within the throughbore in order to shear
the shear pins 43, and drive the piston sleeve 41 into the catcher
device 45, in order to regain pumping ability across the plug sub
10, by virtue of the slots 46 in the catcher device 45 allowing
fluid passage in the throughbore past the catcher 45. This permits
continued pumping if required, and retains some ability to operate
parts of the string below the activated annular sealing device and
mechanical anchor. If remedial operations are unsuccessful, a
decision may be taken at this time to seal the well and side track
above it. At this point, the dart 26 is typically dropped from
surface and lands on the seat 25 on the sleeve 12, causing it to
move axially down to seal off the bore by means of the chevron
seals 19 interacting with the outer surface of the solid dart 26.
This opens the circulation ports 21 above the annular sealing
device 30 to allow circulation of fluids in the string and into the
annulus above the packer. If required, the disconnect above the
plug 10 can be operated, typically by dropping a further ball onto
a seat in the disconnect device as is known in the art, leaving the
plug sub 10 and BHA anchored in place downhole. The strings above
the anchored plug sub 10 can then be pulled out of hole, and
optionally cement can be pumped through the drill pipe to set a
permanent plug above the packer assembly.
[0081] In certain embodiments, the plug sub 10 can incorporate a
fishing neck facing upwards, to facilitate fishing, unlatching and
retrieval of the plug sub 10 and BHA if required, on a separate
fishing trip, if cement is not pumped.
[0082] Modifications and improvements can be incorporated without
departing from the scope of the invention.
* * * * *