U.S. patent number 3,848,668 [Application Number 05/210,727] was granted by the patent office on 1974-11-19 for apparatus for treating wells.
This patent grant is currently assigned to Otis Engineering Corporation. Invention is credited to Phillip S. Sizer, Carter R. Young.
United States Patent |
3,848,668 |
Sizer , et al. |
November 19, 1974 |
APPARATUS FOR TREATING WELLS
Abstract
A method of and apparatus for treating wells to provide surface
controlled subsurface safety systems in the wells, whether
previously completed wells or newly completed wells. A method and
apparatus is provided for installing receptacles in the well flow
conductors below the surface for receiving surface controlled
subsurface safety valves therein for controlling undesired flow
from the well in the event of emergency, disaster or accident
damaging the well surface flow controlling system or threatening
the integrity thereof. Also, a method and apparatus is provided for
installing a hanger for well flow conductors in the well casing
below the surface for supporting the flow conductor or conductors
in the well casing below the surface and then installing the
receptacles in the well flow conductors below the surface for
receiving surface controlled subsurface safety valves therein.
Inventors: |
Sizer; Phillip S. (Dallas,
TX), Young; Carter R. (Lewisville, TX) |
Assignee: |
Otis Engineering Corporation
(Dallas, TX)
|
Family
ID: |
22784043 |
Appl.
No.: |
05/210,727 |
Filed: |
December 22, 1971 |
Current U.S.
Class: |
166/72; 166/299;
166/55 |
Current CPC
Class: |
E21B
34/14 (20130101); E21B 33/047 (20130101); E21B
43/14 (20130101); E21B 34/105 (20130101); E21B
29/02 (20130101); E21B 43/10 (20130101); E21B
2200/04 (20200501) |
Current International
Class: |
E21B
34/00 (20060101); E21B 29/00 (20060101); E21B
33/047 (20060101); E21B 33/03 (20060101); E21B
29/02 (20060101); E21B 43/02 (20060101); E21B
43/10 (20060101); E21B 43/14 (20060101); E21B
34/14 (20060101); E21B 34/10 (20060101); E21B
43/00 (20060101); E21b 023/00 () |
Field of
Search: |
;166/277,313,297-299,315,55,55.1,71,72,125 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Brown; David H.
Claims
What is claimed and desired to be secured by Letters Patent is:
1. Apparatus for treating a well having one or more flow conductors
therein to install a surface controlled subsurface safety valve in
each such flow conductor of the well for controlling flow from the
well therethrough which includes: guide and support means
insertable through each well flow conductor to engage the flow
conductor at a point below which it is desired to part said
conductor for removal of the upper portion of said conductor
thereabove leaving the lower portion of the conductor in place in
the well; means for parting the upper portion of each original flow
conductor from the remainder thereof left in place in the well at
the selected point in the flow conductor for removal of the upper
portion of the flow conductor from the well while leaving the lower
portion engaged with and supported by the guide support means;
means including replacement flow conductor means for each separate
flow conductor of the well having surface controlled safety valve
means therein insertable into the well telescoped over the guide
and support means into engagement with the upper end of the lower
portion of the flow conductor left in place in the well and having
connecting means for connecting said replacement flow conductor
means with the upper end of the original flow conductor left in the
well engaged with and supported by the guide and support means over
which said replacement flow conductor means is telescoped, said
guide and support means being removable from within the replacement
flow conductor means after said replacement flow conductor means
has been connected to the upper end of said original low conductor
left in place in the well for removal of said guide and support
means from the well; and control means at the surface connected to
each of the subsurface safety valve means and operative in response
to predetermined conditions sensed in the well or at the surface
for actuating each of said safety valve means to cause the same to
move to closed position upon the occurrence of such predetermined
sensed conditions, whereby wells may be provided with surface
controlled subsurface safety valve apparatus without disturbing the
flow conductors below the point of parting and removing the upper
portion thereof and without disturbing the remainder of the flow
conductor and well apparatus left in place in the well
therebelow.
2. Apparatus of the character set forth in claim 1 wherein the
control means at the surface comprises separate control means for
controlling each of the subsurface safety valve means
independently.
3. Apparatus of the character set forth in claim 1 wherein the
connecting means connecting each said replacement flow conductor
means with the upper end of the each original flow conductor left
in place in the well comprises: first connector means on one and
second connector means on the other of said replacement flow
conductor means and said original flow conductor left in place in
the well releasably engageable to connect said replacement flow
conductor means in sealed flow communication with the upper end of
said original flow conductor left in place in the well whereby well
fluids flowing upwardly through said original flow conductor left
in place in the well will be directed through said replacement flow
conductor means and the subsurface safety valve means therein to
control the flow of such well fluids from the well.
4. Apparatus of the character set forth in claim 3 wherein said
first connector means comprises a receptacle and said second
connector means comprises a latching mechanism means insertable in
and removable from said receptacle in locked sealing position
therein to permit insertion and removal of said replacement flow
conductor means and the safety valve means in said well without
disturbing said original flow conductor with which said replacement
flow conductor means is connectable.
5. Apparatus of the character set forth in claim 1 wherein the
means for parting each of said original flow conductors comprises:
mechanical cutter means having knives engageable with each said
original flow conductor for severing the original flow conductor at
said selected point below the surface of the earth while said guide
and support means remains in place connected with the upper end of
said lower portion of the original tubing left in place in the well
to permit the severed upper portion to be removed from the well
over the guide means.
6. Apparatus of the character set forth in claim 1 wherein the
means for parting each of said original flow conductors comprises:
chemical cutter means for directing a chemical to a selected area
of the wall of said original flow conductor to produce controlled
localized cutting of said flow conductor at said selected point
below the surface before said guide and support means is lowered
into and connected with the upper end of said lower portion of the
original tubing left in place in the well to permit the severed
upper portion to be removed from the well over the guide means.
7. Apparatus of the character set forth in claim 1 wherein said
guide and support means includes: gripping means at the lower end
of guide and support means releasably engageable with each original
flow conductor at a desired subsurface level in the well below that
at which the low conductor is to be parted before, during, and
after said original flow conductor is parted at said selected level
therein.
8. Apparatus for treating a well having a flow conductor in place
therein which includes: guide and support means insertable through
each well flow conductor and having gripping means thereon to
releasably engage the flow conductor at a point below which it is
desired to part said conductor for removal of the upper portion of
said conductor from the well leaving the lower portion of the
conductor in place in the well; means for parting the flow
conductor in the well at said point below the surface; means for
removing the upper portion of the flow conductor parted from the
remainder thereof; a replacement upper flow conductor insertable
into the well telescoped over said guide and support means after
the upper parted portion of the original conductor has been
removed; means for connecting said replacement upper flow conductor
at its lower end with the upper end of said lower portion of the
original flow conductor left in place in the well; and flow
controlling means in said replacement upper flow conductor for
controlling flow from the well through the original flow conductor
left in place in the well and the replacement upper flow conductor
connected thereto in response to sensed predetermined
conditions.
9. The apparatus of claim 8 wherein the flow controlling means
includes: surface controlled subsurface safety valve means
connected in said replacement upper flow conductor; and control
means at the surface and connected to the subsurface safety valve
means and operative in response to predetermined conditions sensed
in the well or at the surface to actuate said safety valve means to
move to closed position upon the occurrence of such predetermined
sensed conditions.
10. The apparatus of claim 9 wherein said subsurface safety valve
means includes: a landing receptacle forming a part of said
replacement upper flow conductor and having a lock recess therein;
and said safety valve has locking members thereon engageable with
the lock recess in said landing receptacle when said safety valve
is disposed therein said safety valve being insertable in and
removable from said landing receptacle through said replacement
upper flow conductor.
11. Apparatus for installing a flow controlling safety system in a
well having a flow conductor in place therein extending from a
producing earth formation to the surface, including: means for
parting said flow conductor at a desired point in the well and
removing the upper portion of the flow conductor above the point of
parting from the well and leaving the portion of the flow conductor
below the point of parting in place in the well to form a lower
flow conductor means disposed in said well with its lower end in
flow communication with the producing earth formation; replacement
upper flow conductor means disposable in said well and having
surface controlled subsurface safety valve means therein; first
connecting means on the lower end of said replacement upper flow
conductor means; second connecting means on the upper end of said
lower flow conductor means coengageable with said first connector
means for releasably connecting the lower end of said upper flow
conductor means in flow communication with the upper end of said
lower flow conductor means; control means at the surface connected
to said subsurface safety valve means and operative in response to
predetermined conditions sensed in the well or at the surface for
actuating said subsurface safety valve means to cause the same to
move to closed position upon the occurrence of such predetermined
sensed conditions; and means for releasing said first connecting
means at the lower end of the upper flow conductor means from the
second connecting means on the upper end of the lower flow
conductor means whereby said upper flow conductor means and the
subsurface safety valve means therein are removable from the well
without disturbing said lower flow conductor means.
12. A system for treating a well having one or more flow conductors
therein to install a surface controlled subsurface safety valve in
each such flow conductor of the well for controlling flow from the
well therethrough which includes: support and guide means
insertable in and removable from each of such flow conductors
extending from the surface to a desired subsurface level to engage
and support each of such flow conductors thereat while the upper
portion of such conductors above such level is parted therefrom and
removed from the well and to guide a replacement flow conductor
means into flow communicating engagement with a selected original
flow conductor; means for parting the upper portion of each of the
original flow conductors above such desired subsurface level from
the remainder thereof left in place in the well for removal from
the well while said support and guide means is in place engaged
with the upper end of said lower portion of said well flow
conductor; means including a replacement flow conductor means for
each separate flow conductor of the well having surface controlled
subsurface safety valve means therein insertable over said support
and guide means into the well into engagement with the upper end of
the lower portion of said flow conductor left in place in the well
and having connecting means for connecting said replacement flow
conductor means with the upper end of the original flow conductor
left in place in the well while said original flow conductor is
engaged by said support and guide means; and separate control means
at the surface connected to each of the subsurface safety valve
means and operative in response to predetermined conditions sensed
in the well or at the surface for actuating each of said safety
valve means to move to closed position upon the occurrence of such
predetermined sensed conditions, whereby said well may be provided
with surface controlled subsurface safety valve apparatus without
disturbing the flow conductors below the point of parting and
removing the upper portion thereof and without disturbing the
remainder of such flow conductors and well apparatus left in place
in the well therebelow.
13. A system for treating a well having one or more flow conductors
therein to install a surface controlled subsurface safety valve in
at least one such flow conductor of the well for controlling flow
from the well therethrough which includes: means for removing an
upper portion of at least one of the original flow conductors
including guide and support means insertable through the upper
portion of said one or more of said original flow conductors to
engage said original flow conductor at a point below that at which
the conductor is to be separated to permit removal of the upper
portion leaving the lower portion in place in the well, and means
for parting said original flow conductor at said selected point to
permit removal of the upper portion thereof from the well over the
support and guide means engaged with the lower portion left in
place in the well; means including replacement flow conductor means
for said at least one flow conductor having surface controlled
subsurface safety valve means therein insertable over said support
and guide means into the well into engagement with the upper end of
the lower portion of said flow conductor left in place in the well
and having releasable connecting means for connecting said
replacement flow conductor means with the upper end of the
remainder of said at least one of the original flow conductors left
in place in the well while said support and guide means is engaged
with said remainder of said original flow conductor; and control
means at the surface connected to each of the subsurface safety
valve means and operative in response to predetermined conditions
sensed in the well or at the surface for actuating each of said
safety valve means to move to closed position upon the occurrence
of such predetermined sensed conditions, whereby said well may be
provided with surface controlled subsurface safety valve apparatus
in at least one of said original flow conductors without disturbing
said flow conductor below the point of parting and removing the
upper portion thereof and without disturbing the remainder of the
flow conductors and well apparatus left in place in the well.
14. The system of claim 13 wherein the connecting means for
connecting the replacement flow conductor to the upper end of the
remainder of the original flow conductor left in place in the well
includes: first locking and sealing means on one and second locking
and sealing means on the other of said replacement flow conductor
means and the upper portion of said remainder of the original flow
conductor left in place in the well coengageable to connect said
replacement flow conductor means in sealed flow communication with
said upper portion of said remainder of the original flow conductor
whereby well fluids flowing upwardly through said remainder of said
original flow conductor will be directed through said replacement
flow conductor means and through the safety valve means connected
therein to control the flow of such well fluids from the well.
15. The system of claim 14 wherein said first locking and sealing
means comprises receptacle means having a lock shoulder and a
sealing surface therein; and said second locking and sealing means
comprises: expansible and retractable lock members and seal means
insertable in said receptacle means and engageable with said lock
shoulder and seal surface; and means for disconnecting said lock
members from said shoulder for separation of said first and second
lock means from each other to permit removal of the replacement
upper flow conductor from the well.
16. Apparatus for treating a well having one or more flow
conductors therein to install a surface controlled subsurface
safety valve in each such flow conductor of the well for
controlling flow from the well therethrough which includes: means
for parting and removing the upper portion of each original flow
conductor from the remainder thereof left in place in the well
comprising guide and support means insertable through the flow
conductor into place in the flow conductor and connected at its
lower end to said flow conductor at a point below that at which the
flow conductor is to be parted, and means for parting said flow
conductor above such connection after said guide and support means
has been positioned in said flow conductor, to separate the upper
portion of the flow conductor from the lower portion of the
original flow conductor to be left in place in the well, whereby
the upper separated portion of the flow conductor may be removed
from the well bore while the guide means is left in place in and
supporting the upper end of the lower portion of the original flow
conductor left in place in the well; means including replacement
flow conductor means for each separate flow conductor of the well
having surface controlled subsurface safety valve means therein
insertable into the well telescoped over the guide and support
means into engagement with the upper end of the lower portion of
said flow conductor left in place in the well and having connecting
means for connecting said replacement flow conductor means with the
upper end of said original flow conductor left in place in the well
connected with and supported by said guide and support means; said
guide and support means being disconnectable from said lower
portion of said original flow conductor and removable from the well
after said replacement flow conductor means has been connected with
the upper end of said lower portion of said original flow
conductor; and control means at the surface connected to each of
the subsurface safety valve means and operative in response to
predetermined conditions sensed in the well or at the surface for
actuating each of said safety valve means to cause the same to move
to closed position upon the occurrence of such predetermined sensed
conditions, whereby wells may be provided with surface controlled
subsurface safety valve apparatus without disturbing the flow
conductors below the point of parting and removing the upper
portion thereof and without disturbing the remainder of the flow
conductor and well apparatus left in place in the well therebelow.
Description
SUBJECT MATTER AND OBJECTS OF THE INVENTION
This application is related to the coassigned copending application
of Henry J. James and Carter R. Young, Ser. No. 270,977, filed July
12, 1972, for Method of and Apparatus for Treating and Completing
Wells.
This invention relates to new and useful improvements in methods of
and apparatus for equipping wells with surface controlled
subsurface safety valves, either before or after the well has been
completed in the usual manner.
Heretofore, when a well has been completed it has been necessary to
remove the tubing string or strings from within the well bore in
the casing, first killing the well, unseating the packers, and then
removing the string and packers and other fittings from the well
prior to installing new strings of pipe, refitted or new packers,
subsurface safety valve receptacles and control fluid lines for the
valves, then reinstalling the tubing hanger and surface controls
and flow lines, including an exit fitting for the control fluid
pressure line at the surface before the well could be returned to
production. This is an expensive and time consuming operation, and
may result in damage to the producing formation of the well as a
result of the loading fluid used and other operations performed in
making the revised installation. Such operations are expensive due
to the heavy equipment and the long period of time required for
their performance. Also, the deleterious effects of the treating
and loading fluids on the producing formation often result in a
reduction in the productivity or flow of desirable fluids from the
formation and a commensurate reduction in the value of the
well.
It is, therefore, one object of the invention to provide a new and
improved method of and system for installing surface controlled
subsurface safety valves in the conductor or conductors of
wells.
A particular object of the invention is to provide a method of and
system for installing surface controlled subsurface safety valves
in the flow conductor or conductors of wells which have been
previously completed with the flow conductor or conductors in place
therein.
An important object of the invention is to provide a method of and
apparatus for disconnecting the upper portion of one or more flow
conductors in a well from the remainder of such conductors
therebelow and installing a receptacle and replacement upper flow
conductor portion in flow communication with each of such flow
conductors therebelow with a surface controlled subsurface safety
valve in such replacement upper flow conductor portion for
controlling fluid flow through each such flow conductor.
A further object of the invention is to provide a method and
apparatus of the character set forth wherein the receptacle and
replacement upper flow conductor portion are provided with means
for detachably connecting the receptacle and replacement upper flow
conductor portion for each flow conductor of the well to permit
removal and replacement of the replacement upper flow conductor
portion and the safety valve when desired.
Still another object is to provide a method and apparatus as set
forth wherein the surface controlled subsurface safety valve is
insertable and removable independently of the replacement upper
flow conductor portion.
A further important object of the invention is to provide a method
and apparatus of the character set forth wherein a supplementary
surface controlled subsurface safety valve may be installed in the
replacement upper flow conductor portion in the event of the
original safety valve becoming inoperative or ineffective.
A further object of the invention is to provide in a method and
apparatus of the character set forth means for directing a hanger
into place over a flow conductor in place in the well and actuating
the hanger into anchoring supporting engagement with the casing and
the flow conductor either before or after the upper portion of the
flow conductor above the hanger has been removed from connection
with the flow conductor therebelow.
A further particular object of the invention is to provide a method
and apparatus for servicing wells to provide a subsurface hanger in
the well engaging between the flow conductor and the well casing
and supporting the flow conductor therebelow against longitudinal
downward movement in the casing, then installing a receptacle and
replacement upper flow conductor portion above the hanger in flow
communication with the upper end of the flow conductor remaining in
place in the well casing for receiving a surface controlled
subsurface safety valve in the receptacle for controlling fluid
flow through the conductor and replacement upper flow conductor
portion to the surface in the event of either an imminent or
impeding disaster or under any other desired circumstances, and
wherein the method and apparatus in installable in wells already
previously completed without removing from the well flow
conductors, or packer, or other well tools connected therewith
already in place in the well below the point of connection of the
hanger with the flow conductor.
A further object of the invention is to provide a method and
apparatus of the character desribed which may be used with either
single flow conductor well installations or in multiple flow
conductor well installations for controlling fluid flow through the
conductors to the surface.
Still another object of the invention is to provide a method and
apparatus of the character described which is adapted for use in
wells in which the well is serviced or treated by means of through
the flow line pump-down operations, and in which the pump-down
tools may be moved through the surface controlled subsurface safety
valve and receptacle and hanger without affecting the customary
operation of such pump-down tools.
It is still another object of the invention to provide a method and
apparatus of the character described wherein the installation may
be made without rotary manipulation of the flow conductor in place
in the well, particularly that portion thereof left in place in the
well; and wherein the surface controlled subsurface safety valve
and replacement upper flow conductor portion may be removed and
replaced without rotation thereof.
Still another object of the invention is to provide an apparatus
and method of the character described wherein the replacement upper
flow conductor portion or extension and the well equipment at the
surface may be readily replaced with a minimum of cost, time, and
labor by merely replacing the well head, if damaged, the
replacement upper flow conductor portion and the surface controlled
subsurface safety valve and its appurtenances.
Still another object of the invention is to provide a method and
apparatus for servicing a well, which has been previously
completed, to install a subsurface hanger below the surface in the
casing for supporting the upper end of the flow conductor in the
well casing, and wherein guide means is connected with the upper
end of the flow conductor to be left in place in the well for
guiding the hanger, receptacle and replacement flow conductor
portion and safety valve into position to engage, anchor and seal
with the upper end of the flow conductor or conductors to be left
in place in the well casing below the point at which the upper
portion of the conductor thereabove is to be removed; and wherein
the upper portion of the flow conductor above the hanger may be
disconnected from the portion to be left in the well by unscrewing
or severing the same in any desired manner; and wherein the guide
means is removable after the receptacle, replacement upper flow
conductor portion, and safety valve have been positioned in flow
communication with the upper end of each desired flow conductor in
place in the well.
A further object of the invention is to provide a method and
apparatus of the character set forth wherein the guide means
connected to each flow conductor left in place in the well provides
for positively directing the receptacle, safety valve, and
replacement upper flow conductor portion into separate flow
communication with a predetermined one of the flow conductors left
in place in the well, after which the guide means is removable for
normal operation of the well.
Still another object is to provide a method and apparatus of the
character set forth wherein the replacement upper flow conductor
portion includes a landing nipple having a control fluid pressure
conductor communicating its bore with a source of control fluid
pressure at the surface and the surface controlled subsurface
safety valve insertable and removable through the replacement upper
flow conductor into and out of said landing nipple and includes a
normally closed valve means operable to open position by the
control fluid pressure in the bore of the landing nipple acting
thereon.
A further object is to provide a method and apparatus of the
character set forth wherein the surface controlled subsurface
safety valve comprises a section of the replacement upper flow
conductor portion and a landing nipple is connected to such
replacement upper flow conductor portion adjacent the safety valve
for receiving a supplementary surface controlled subsurface safety
valve insertable into and removable from said landing nipple
through said replacement upper flow conductor portion for
controlling flow therethrough in the event of the original safety
valve becoming inoperative or ineffective, and wherein said
supplementary safety valve is normally closed and operated to open
position by control fluid pressure directed thereto from said
original safety valve.
Additional objects and advantages of the invention will be readily
apparent from the reading of the following description of a device
constructed in accordance with the invention, and reference to the
accompanying drawings thereof, wherein:
FIG. 1 is a schematic vertical sectional view of a completed cased
well having a pair of flow conductors therein suspended from the
surface and having their lower inlet ends separated by packers
which also separate the producing zones in the well bore;
FIG. 2 is a view similar to FIG. 1 showing removable flow conductor
plugs installed in receptacles in the lower portions of the flow
conductors for closing off communication of the well producing
formations with the surface of the well to permit carrying out the
method of the invention;
FIG. 3 is a view similar to FIG. 2 showing the Christmas tree and
fittings connected therewith removed from above the hanger at the
upper end of the well casing and a blowout preventer connected with
the hanger for sealing between the casing and the upper ends of the
flow conductors extending upwardly through the casing to the
surface;
FIG. 4 is a view similar to FIG. 3 showing an overshot hanger and
handling string therefor moved into place in the well casing to a
point below the point at which the flow conductors are to be
separated for later installation of the surface controlled
subsurface safety valve;
FIG. 5 is a fragmentary view of the flow conductors and tubing
hanger showing means for loosening the upper portion of the flow
conductors above the hanger for removal from the well;
FIG. 6 is a view similar to FIG. 3 showing guide strings lowered
through the flow conductors into anchored engagement with the
conductors below the point at which the flow conductors are to be
parted;
FIG. 7 is a fragmentary view similar to FIG. 6 showing the upper
ends of the flow conductors supported by the overshot hanger after
the upper portions of the flow conductors have been disconnected
and removed from the well leaving the guide strings anchored in
place;
FIG. 8 is a view similar to FIG. 6 showing handling strings, each
having a receptacle for a subsurface safety valve connected at its
lower end, inserted into the well over the guide strings and
threaded into the upper end of the corresponding flow conductors
supported by the overshot hanger;
FIG. 9 is a view similar to FIG. 8 showing the handling strings for
the receptacle released from connection with the upper ends thereof
and being removed from the well;
FIG. 10 is a view similar to FIG. 9 showing the handling strings
removed and replacement upper flow conductor portions, each having
a surface controlled subsurface safety valve and control fluid line
connected thereto, anchored in the receptacles connected to the
upper ends of the flow conductors in place in the well;
FIG. 11 is a view similar to FIG. 10 showing the upper ends of the
replacement upper flow conductor portions connected to the tubing
hanger and Christmas tree in flow controlling condition, with the
guide strings removed and the well in condition to produce;
FIG. 12 is a view similar to FIG. 11 showing a surface controlled
subsurface safety valve installation in a single zone well having a
single flow conductor to the surface which has been completed in
substantially the same manner as the multiple string installation
of FIG. 11;
FIGS. 13A, 13B, 13C and 13D are longitudinal vertical views, partly
in elevation and partly in section, showing the details of
construction of the surface controlled subsurface safety valve and
latching mechanism located in the receptacle in position for
anchoring the safety valve in place in the well;
FIG. 14 is a fragmentary view, similar to FIG. 13, showing the
guide string moved upwardly to shift the latching mechanism for the
safety valve to anchored position in the receptacle prior to
releasing the shifting tool from the latching mechanism;
FIGS. 15A and 15B are fragmentary views, partly in elevation and
partly in section, of the latching mechanism and lower portion of
the safety valve showing the same anchored in sealing operating
condition in the receptacle, ready for flow of well fluids
therethrough;
FIGS. 16A and 16B are longitudinal vertical views, partly in
elevation and partly in section, showing the details of
construction of the overshot hanger of FIGS. 4 through 11,
inclusive;
FIG. 17 is a horizontal cross-sectional view taken on the line 17
--17 of FIG. 16A;
FIGS. 18A, 18B, and 18C comprise a vertical sectional view of the
hanger taken on the line 18 --18 of FIG. 17;
FIG. 19 is a fragmentary view, partly in elevation and partly in
section, of the valve mechanism of FIG. 13B taken at right angles
to that of FIG. 13B showing the valve closure moved to closed
position;
FIGS. 20A and 20B are longitudinal vertical views, partly in
elevation and partly in section, showing the downshift tool engaged
with the sliding locking sleeve of FIG. 15B to shift the same
downwardly for releasing the latching mechanism for removal of the
safety valve and latching mechanism with the replacement upper flow
conductor portion thereabove;
FIG. 21 is a view similar to FIG. 1, in which the flow conductors
are made up of coupled sections of tubing rather than integral
joint pipe as in FIG. 1, and wherein the diameter of the couplings
in the tubing strings is so large as to prevent the use of an
overshot tubing hanger in the same manner as in FIGS. 1 through 11,
showing the well before the installation of surface controlled
subsurface safety valve equipment therein;
FIG. 22 is a fragmentary view similar to FIG. 21, with the
Christmas tree and tubing hanger removed, showing a guide string
having an anchoring spear and cutter device connected to the lower
end thereof inserted into each of the flow conductors and engaged
therewith for cutting off the conductors at a desired location in
the well;
FIG. 23 is a fragmentary view similar to FIG. 22 showing the upper
portions of the flow conductors parted from the remainder thereof
above the spears which hold the guide strings connected in the
respective flow conductors therebelow;
FIG. 24 is a fragmentary view similar to FIG. 23 showing the
separated upper portions of the flow conductors removed from the
well by having been stripped off over the guide strings;
FIG. 25 is a fragmentary view similar to FIG. 24 showing a milling
tool and actuating string telescoped over one of the guide strings
for milling the upper end of the flow conductor to which the guide
string is connected;
FIG. 26 is a fragmentary view similar to FIG. 25 showing an
overshot hanger being lowered into place over the upper ends of the
flow conductors left in place in the well and being guided into the
proper position by the guide strings;
FIG. 27 is a fragmentary view similar to FIG. 26 showing the
overshot hanger anchored in place in supporting engagement with the
casing and the upper ends of the flow conductors left in place in
the well;
FIG. 28 is a schematic view similar to FIG. 21 showing the
replacement upper flow conductor portion, surface controlled
subsurface safety valve, and packoff overshot for each of the flow
conductors being lowered into the well over the guide strings
connected the flow conductors left in place therein;
FIG. 29 is a view similar to FIG. 28 showing the replacement upper
flow conductor portions latched in flow conducting communication to
the upper ends of the flow conductors left in place in the well and
connected at their upper ends to the tubing hanger and Christmas
tree with the guide strings removed and the well in condition to
produce;
FIG. 30 is a view similar to FIG. 22 showing a modified method of
cutting the flow conductor by means of a chemical type tubing
cutter for carrying out the method of this invention;
FIG. 31 is a view similar to FIG. 30 showing the guide strings
inserted through each of the flow conductors and anchored in
supporting engagement below the level of the cut made by the
chemical type cutter, and the upper portions of the flow conductors
lifted to part the same from the lower portions of the conductors
to be left in the well, with the guide strings supporting the
same;
FIG. 32 is a view similar to FIG. 29 showing a modified replacement
upper flow conductor portion, safety valve, and packoff overshot in
position for the upper ends of the flow conductors left in place in
the well to be lifted by the guide strings into latched and sealed
flow communication with their respective packoff overshots;
FIG. 33 is a view similar to FIG. 32 showing the upper ends of the
flow conductors left in place in the well lifted into latched
sealed flow communication with their respective packoff overshot,
the guide strings removed, and the well in condition to
produce;
FIG. 34 is fragmentary view, similar to FIG. 5, showing a further
modified method of the invention;
FIG. 35 is a longitudinal vertical, partly in elevation and partly
in section of a modified form of safety valve installation showing
an original surface controlled safety valve such as is shown in
FIGS. 13A through 13D, inclusive, having a supplementary safety
valve disposed therein for controlling fluid flow from the well in
the event of failure of the original safety valve to so function;
and,
FIG. 36 is a longitudinal vertical view, partly in elevation and
partly in section, of a modified form of replacement upper flow
conductor portion having a safety valve insertable into and
removable from a landing nipple forming a part of said replacement
upper flow conductor portion.
In FIG. 1 of the drawings is shown a multiple zone well
installation having the usual casing C extending downwardly through
two producing formations F1 and F2, respectively, and having
perforations I1 and I2, respectively, communicating the bore of the
casing with the producing formations. A long string of tubing T1
extends downwardly in the casing to a lower packer P1 which seals
between said tubing and the casing between the upper and lower
formations F1 and F2 to separate the formations and to direct the
well fluids from the lower formation into the lower end of the
tubing string T1. A short string of tubing T2 extends downwardly in
the well to a position near the upper formation F1 and a multiple
string packer P2 seals between the tubing strings T1 and T2 and the
casing C above the upper formation F1 in the usual manner to
isolate the upper formation from the casing annulus above the
packer and direct flow from the upper formation into the lower end
of the short tubing string T2. The upper end of the short tubing
string T2 is connected in the usual manner to a tubing hanger H
which is supported and seated in sealing relationship in the bore
of a tubing head B in the usual manner above a casing head X which
has a lateral flowing wing X1 and valve X2 connected therewith in
the usual manner. The long tubing string T1 has a slip joint J at
its upper end between the tubing hanger H and the tubing string and
a short sleeve is supported by the tubing hanger H and connected to
the upper end of the tubing string T1 in sealing relationship
therewith in the usual manner. This slip joint which permits the
upper end of the tubing string T1 to be connected with the
supported by the tubing hanger H after the short tubing string T2
has been connected thereto, as is well known, could as well be
connected in the short tubing string rather than the long tubing
string, or both such strings, if desired.
The tubing strings shown are of the integral joint type such as the
well known "Hydril" Integral Joint Tubing.
Above the tubing head B, the usual Christmas tree fittings V are
connected, including gate valves V1 and V2 communicating and
controlling flow through the tubing strings T1 and T2,
respectively. The usual flow lines, flow wings and pressure gauges
are connected above the gate valves for receiving, controlling and
directing flow from the valves in the conventional manner and form
the Christmas tree which is designated generally as A, and may be a
dual type tree for the usual construction and assemblage, for
controlling flow from the two formations through the two tubing
strings separately.
It is also usual to have receptacles L1 and L2 connected in the
tubing strings T1 and T2, respectively, for seating removable
closing plugs therein when desired to service the well. These may
take the form of the usual landing nipples for wire line or through
the flow line pump-down system operated plugs having anchoring
devices for latching and sealing the same in the landing nipples to
close off flow through the tubing strings.
As shown in FIG. 2, the well installation in prepared for carrying
out the method and installing the system of this invention by
inserting wire line or through the flow line pump-down operated
plugs D1 and D2 which have anchoring or locking means 10 and seal
means 11 thereon engageable in anchoring sealing position in the
landing nipples or receptacles L1 and L2, respectively, and which
are provided with normally closed plug valves 12 which are biased
to the closed position by springs 13. These removable plugs are
inserted in the landing nipples or receptacles L1 and L2 to close
off the producing formations from entry of well fluids into the
tubing strings. Thus, when the plugs are installed as shown in FIG.
2, and the pressure thereabove is bled off, all well fluid pressure
is excluded from the tubing strings above the packers and from the
annulus and tubing head B thereabove. Therefore, no well fluid
pressure is present above the upper packer P2 and the Christmas
tree A and the master valves V1 and V2 may be removed from the
upper end of the tubing head B as shown in FIG. 3 and replaced by a
blowout preventer BOP, which will seal between the tubing head B
and the two strings of pipe extending therethrough, in the usual
manner. When this step has been completed the well is in the
condition shown in FIG. 3 and is ready for the next step of the
method.
As shown in FIG. 4, the tubing hanger H is thereafter removed from
the tubing head B, the slip joint J disconnected from the upper end
of the tubing string T1, and a joint of the usual tubing connected
therein. After the tubing hanger has been removed and the slip
joint detached and the new joint of tubing has been connected to
the upper end of the tubing string T1, an overshot type hanger OH
supported by an operating string OS is inserted in the casing,
telescoping over the two strings of tubing T1 and T2 as it is moved
downwardly in the casing to a position below the location at which
it is desired to install a surface controlled subsurface safety
valve in each of the two strings of tubing.
As shown in FIG. 4, the overshot hanger OH is lowered to a position
below the threaded joints U1 and U2 of the tubing strings T1 and
T2, respectively, so that the hanger will engage the exterior of
the tubing strings below the slight upsets in the pipe at the
joints and to assure that the upper ends of the pipe from which the
tubing thereabove is to be disconnected are positioned above the
hanger and accessible for later operations. Thus, the overshot
hanger will engage the body of the tubing string rather than the
upsets U1 and U2 at the joint. The external gripping members 15 and
the internal gripping members 16 of the hanger are expanded into
gripping engagement with the casing and the tubing strings,
respectively, by hydraulic fluid pressure conducted down the
operating string OS and applied to suitable operating pistons (not
shown) in the overshot hanger, as will be hereinafter more fully
explained. When the gripping members 15 and 16 are so engaged, the
tubing strings T1 and T2 below the hanger are supported by the
hanger against downward movement then the sections of the tubing
strings above the joints U1 and U2 are removed, as will now be
explained.
The strings of tubing T1 and T2 are supported at the surface to
maintain the same in the proper tension while the tubing hanger H
is being removed and during running and setting of the overshot
hanger OH. When the overshot hanger is set, the tubing is supported
in the proper tension therebelow and the upper sections of the
strings above the hanger may be removed without affecting the
setting of the hanger, the packers, or condition of the tubing
string below the hanger. THis is important where it is necessary or
desirable to avoid setting the weight of the tubing strings on the
packers in the well and so to avoid damaging the casing or packer
seals, and the like, in place in the well.
After the overshot hanger has been anchored in supporting
engagement in the casing and is gripping the tubing strings T1 and
T2, as has just been described, any suitable method of
disconnecting the tubing string above the joints U1 and U2 is
employed to release the one or more joints of pipe above the joints
U1 and U2 for removal from the well for carrying out the method and
installing the protective system of the invention. The means
illustrated in FIG. 5 in an explosive charge or string shot which
is lowered by a wire line mechanism into each of the tubing strings
and exploded at the location of the joints while a left hand or
unscrewing torque is applied to the sections of pipe thereabove to
loosen the joints U1 and U2.
As shown in FIG. 5, an explosive charge E1 such as Primacord is
lowered into the well by a suitable electrical conductor cable 19
to a position immediately adjacent the coupling or joint U1 in the
tubing string T1. The upper joints of the tubing string above the
coupling U1 then have a left hand or unscrewing torque applied
thereto, while the joint engaged by the overshot hanger OH is held
thereby against rotation. With the torque applied to the joints
above the joint U1 the charge E1 is exploded, and the shock or jar
impressed on the tubing string at the joint will loosen the thread
for unscrewing the joints of pipe above the joint U1 out of the box
of the joint therebelow. This explosive effect, plus the torque
applied to the tubing string thereabove, permits the loosening of
the threaded joint. However, the joint is not disconnected at this
time, for reasons to be explained hereinafter.
Subsequent to releasing or loosening the joint U1, an explosive
charge E2 is lowered into the tubing string T2 adjacent the joint
U2 and exploded in the same manner while a left hand or unscrewing
torque is applied to the string of tubing above the joint U2. The
loosened string above the joint is not disconnected from the tubing
string T2 until later, as will be hereinafter explained. After the
two joints have been loosened and are ready to be disconnected, the
electrical conductor cable 19 is removed from the well with any
remainder of the explosive device, in the usual manner.
After the joints have been loosened, a guide string GS1, having a
spear or gripping device SP1 and an upshifting tool US1 connected
to the lower end thereof, is lowered through the tubing string T1
to a point below the joint U1. As shown in FIG. 6, the spear and
upshifting tool are engaged with the bore wall of the tubing string
T1 below the overshot hanger OH, but may be engaged at any suitable
point below the joint U1 of the tubing string T1 supported by the
overshot hanger.
Similarly, a guide string GS2 is lowered into the tubing string T2
in the same manner as the guide string GS1, and this guide string
also has a spear or gripping device SP2 and upshifting tool US2
connected to its lower end, and the spear is engaged with the wall
of the tubing string T2 below the joint U2, also shown in FIG. 6 to
be below the overshot hanger OH, though it may be engaged at any
point below the joint U2.
With the guide strings in place, a slight upward force is applied
to the guide strings to place the guide strings under tension. The
tubing strings T1 and T2 above the joints U1 and U2 are then
rotated in a direction to back the lower ends of such tubing
strings out of the loosened joints U1 and U2, and such tubing
strings above the joints U1 and U2 are then stripped off over the
guide strings and removed from the well leaving the guide strings
GS1 and GS2 anchored to the tubing strings T1 and T2, respectively,
as shown in FIG. 7, and the overshot hanger OH engaged with the
casing and the tubing strings T1 and T2 as shown in FIG. 7.
When the well has been serviced to remove the upper sections of the
tubing strings, as shown in FIG. 7, a receptacle R1 is connected to
the lower end of a handling string HS1 and lowered over the guide
string GS1 into the well until the threaded lower end 21 of the
receptacle is engaged in the threaded box member of the joint U1 of
the tubing string T1. The handling string is then rotated to thread
the pin at the lower end of the receptacle R1 into fluid tight
engagement with the threads of the box member of the joint U1 at
the upper end of the tubing string T1.
Similarly, a handling string HS2, having a receptacle R2 connected
to its lower end, is telescoped over the guide string GS2 and
lowered into the well until the threads 22 at the lower end of the
receptacle are engaged with and made up in fluid tight sealing
engagement with the box member of the joint U2 at the upper end of
the tubing string T2 by rotating the handling string HS2.
After the receptacles R1 and R2 have been securely connected to the
tubing strings T1 and T2, respectively, the handling strings HS1 is
further rotated in the same right hand direction to shear the pins
23 release the left hand threaded back-off connection 24 at the
lower end of the handling string HS1 from engagement with the
threaded upper end of the receptacle R1 to disconnect the handling
string HS1 from the receptacle R1, after which the handling string
may be stripped upwardly out of the well over the guide strings
GS1, as shown in FIG. 9.
Similarly, after the receptacle R2 has been suitably engaged with
the box member of the joint U2 of the tubing string T2, the
handling string HS2 is further rotated in the same right hand
direction to shear the pin 25 and release the left hand threaded
back-off connection 26 on the lower end of the handling string HS2
from the threads in the upper end of the bore of the receptacle R2.
The shear pins 23 and 25 are sheared before the left hand threaded
back-off connections 24 and 26 are operable to disconnect the
handling strings from the receptacles R1 and R2, respectively.
Obviously, the receptacles R1 and R2 may be lowered into the well
and connected to the upper ends of the tubing strings T1 and T2,
respectively, utilizing a common handling string for inserting and
connecting each of the receptacles to its respective tubing
string.
Once the handling strings have been disconnected from the
receptacles and lifted out of the well over the guide strings, the
receptacles are in position to receive the surface controlled
subsurface safety valve latching mechanism as will now be
explained.
After the handling strings HS1 and HS2 have been removed from the
well, leaving the guide strings GS1 and GS2 engaged with the tubing
strings T1 and T2, respectively, a replacement tubing string RT1,
having a surface controlled subsurface safety valve SV1 and
latching mechanism LM1 connected to its lower end, is telescoped
over the guide string GS1 and lowered until the latching mechanism
LM1 is engaged in the receptacle R1 as shown in FIG. 10. A control
fluid line CF1 is connected to the safety valve SV1 and extends
upwardly exteriorly of the replacement tubing string RT1 to the
surface, where it will be connected as will be hereinafter more
fully explained to an exit fitting. Th latching mechanism LM1 has
locking dogs 31 and seal elements 32 thereon which engage in
locking recesses 33 and seal against the bore wall of the
receptacle R1 to secure the safety valve SV1 in flow communication
with the tubing string therebelow. As will be explained, the
closure member 35 of the safety valve SV1 is held in open position
by fluid pressure exerted through the control fluid line CF1 while
the replacement tubing string RT1 and the safety valve SV1 and
latching mechanism LM1 are lowered over the guide string GS1 into
the receptacle R1, though the latching mechanism LM1 has not been
moved to latching position.
A suitable type telescoping or slip joint connection or member SJ1
is connected in the replacement tubing string RT1 above the safety
valve SV1 for facilitating connection of the replacement tubing
string with the tubing hanger H and the flow connections and
Christmas tree thereabove, when the well is recompleted in the
usual manner.
In the same manner, a replacement tubing string RT2, having the
telescoping or slip joint SJ2 and safety valve SV2 with a latching
mechanism LM2 connected therewith at its lower end, is telescoped
over the guide string GS2 and the latching mechanism lowered into
position to be latched in the receptacle R2 as shown in FIG. 10.
The latching mechanism LM2 has locking dogs 36 expandable into a
locking recess 37 in the receptacle R2 and seal members 38 for
sealing between the latching member and the bore of the receptacle
R2 to connect the safety valve SV2 in flow communication with the
receptacle R2 and the tubing string T2 therebelow. The valve
closure member 39 of the safety valve SV2 is held in the open
position by control fluid pressure applied through the control
fluid line CF2 while the device is being lowered over the guide
string to position the latching member LM2 in the receptacle
R2.
The telescoping or slip joints SJ1 and SJ2 connected in the
replacement tubing strings RT1 and RT2 above the safety valves SV1
and SV2 permit the replacement tubing strings to be connected to
the tubing hanger H without affecting the position of the safety
valves and the latches in the receptacles, or the tubing strings T1
and T2 therebelow.
Before connecting the replacement tubing strings RT1 and RT2 to the
tubing hanger H, th string, the safety valve and latching mechanism
are lowered into position to be latched in the receptacles and the
upper ends of the replacement tubing strings and control fluid
lines are marked for cutting off and fitting them preparatory to
connecting them to the tubing hanger H and the exit flange or
bushing XF, as will be hereinafter more fully explained.
After the replacement tubing tubing strings RT1 and RT2 have been
connected to the hanger H, and the control fluid lines CF1 and CF2
have been connected to the exit flange XF, the hanger is secured in
sealed position in the tubing head B. The exit flange XF is
similarly secured in sealing position on the tubing head and is
connected with the sources of supply of control fluid CFP1 and CFP2
by means of the control fluid lines CF1 and CF2. Test fluid
pressure may then be applied to the bore of the replacement tubing
strings through the Christmas tree which has been secured to the
upper end of the exit flange and tubing head between the guide
strings GS1 and GS2 and the replacement tubing strings to determine
that the installation is connected in proper sealing condition in
communication with the tubing strings T1 and T2 therebelow, and
that the tubing hanger H and exit flange XF are in sealing with the
replacement tubing strings and the control fluid lines. Test fluid
pressure may also be introduced through the casing valve X2 into
the annulus between the casing and the tubing strings for applying
fluid pressure exteriorly of the tubing strings to test the hanger
and the connections of the safety valve and latching mechanism with
the receptacle and tubing strings connected therewith.
After the connections have been tested by applying the test fluid
pressure in the annulus between the replacement tubing strings and
the guide strings GS1 and GS2, the spears SP1 and SP2,
respectively, at the lower ends of such guide strings are released
from latching position by shearing or otherwise releasing the same
to permit the guide strings to be moved upwardly with respect to
the latching mechanisms. Such upward movement lifts the upshifting
tools US1 and US2 on such guide strings upwardly through the tubing
strings T1 and T2 to engage the shifting keys 41 and 42,
respectively, of such shifting tools with the shiftable locking
sleeves 43 and 44 of the latching mechanisms LM1 and LM2,
respectively, to move the locking sleeves upwardly to positively
hold the locking dogs 31 and 36 in the recesses 33 and 37 of the
receptacles R1 and R2, respectively, and so positively anchor the
latching mechanisms and the safety valves in connected flow
communication with the receptacles and the tubing strings
therebelow. Thus, well fluids may flow upwardly through the tubing
strings, the latching mechanism and the safety valves to the
replacement tubing strings and through such replacement tubing
strings to the Christmas tree connections at the upper end of the
well.
After the locking sleeves of the latching mechanisms have been
shifted to locking positing, the shifting keys 41 and 42 are moved
to retracted position by a further upward pull on the guide strings
GS1 and GS2, as will be hereinafter more fully explained, and the
guide strings, the shifting tools and the spears may be removed
from the well.
After the guide strings have been removed, the Christmas tree
connections, including the gate valves V1 and V2 and the other
appurtenances, are connected to the well above the exit flange SF,
and the well is then in condition illustrated in FIG. 11 and ready
for production in the usual manner.
So long as control fluid is supplied to the safety valves SV1 and
SV2 from the control fluid pressure sources CFP1 and CFP2 through
the control fluid lines CF1 and CF2, respectively, the closure
members 35 and 39 of the safety valves are held in the open
position. The plugs D1 and D2 have been removed in the usual manner
from the landing nipples L1 and L2 by conventional wire line or
pump-down tools in the usual manner leaving the tubing strings open
for communication with the formations F1 and F2, respectively. Well
fluids may then flow upwardly through the tubing strings, safety
valves, and replacement tubing strings so long as the safety valve
closure members are held in the open position.
Should any condition occur which would act to reduce or release
control fluid pressure present in either of the control fluid lines
CF1 or CF2, the safety valve SV1 or SV2 to which that control fluid
line is connected, would close automatically as a result of such
reduction or release of such control fluid pressure. Either of the
valves may close independently or both may close simultaneously,
and when closed, will shut off further flow of well fluids through
the tubing string in which such closed valve is connected.
Obviously, the control fluid pressure sources CFP1 and CFP2 may be
separate individual sources or control fluid may be supplied from a
common source. If desired, a manifold may be provided for supplying
a common sensing and control valve connected to both the control
fluid lines for releasing or reducing control fluid pressure in the
lines upon the occurrence of any undesirable condition such as a
fire or other catastrophe at the surface of the well. When the
pressure in either or both of the control fluid lines is released
or reduced sufficiently either or both of the valves will close
automatically, as has been explained.
From the foregoing, it will be seen that a well having multiple
strings of flow conducting tubing connected therein can be reworked
to install surface controlled subsurface safety valves in the
tubing strings below the surface of the well for controlling flow
from the producing formations through the well.
When desired, the latching mechanisms LM1 and LM2 may be released
by a down shifting tool DS lowered through the replacement tubing
strings to engage and move the shiftable locking sleeves 43 and 44
downwardly to release the locking dogs 31 and 36 from locking
engagement in the recesses 33 and 37 in the receptacles R1 and R2,
respectively, to permit the safety valves and latching mechanisms
to be pulled upwardly out of the receptacles to the surface for
repair or replacement, as needed.
The method of carrying out this operation involves the reinsertion
of the plug tools D1 and D2 in the landing nipples L1 and L2,
respectively, in the tubing strings T1 and T2, bleeding off the
pressure from within the tubing strings above the plug tools, then
inserting the guide strings GS1 and GS2 with the spears and
upshifting tools connected to the lower end thereof into anchored
gripping engagement with the tubing strings T1 and T2,
respectively, while the safety valves are open. Since the slidable
locking sleeves have already been moved to the inoperative position
to release the dogs, the replacement tubing strings RT1 and RT2 may
be lifted to lift the safety valves and the latching mechanisms
connected therewith upwardly out of the well over the guide strings
GS1 and GS2 in the reverse manner to that in which they were
installed.
After the valves and latching mechanisms have been repaired or
replaced as desired, or as necessary, the same may be reinstalled
and locked to their respective receptacles in the manner already
described, and the well again placed on production.
While the foregoing description of the method and apparatus for
carrying out the method and controlling flow from the well has been
directed to a multiple zone well installation, it is perfectly
obvious that a single zone well may be similarly treated. Such an
installation is shown in FIG. 12, wherein the tubing string T3
having a joint U3 therein is supported in a single string overshot
hanger OH2. The overshot hanger has a single bore telescoped over
the tubing string T3, with a single set of internal slips 16a
gripping the tubing string and external slips 15a engaged with the
casing, in the same manner as the multiple string overshot hanger
OH of the form previously described was utilized for supporting the
upper ends of the tubing strings T1 and T2 in the casing C.
The receptacle R3 is connected to the box member of the joint U3 of
the tubing string T3 in the same manner as the receptacles R1 and
R2 were connected to the tubing strings T1 and T2 of the form
previously described. The replacement tubing string RT3 having the
safety valve SV3 and latching mechanism LM3 connected to its lower
end is lowered into the well and the latching mechanism is anchored
in sealing flow communication with the receptacle R3. Th slip joint
SJ3 above the safety valve SV3 is connected in the replacement
tubing string RT3 for facilitating connection of the upper end of
the replacement tubing string to the tubing hanger H2. The control
fluid line CF3 from the safety valve SV3 is connected to the hanger
H and extends upwardly therethrough to a sealed opening in the exit
flange XF2 to which the control fluid line supply CFP3 is connected
in the same manner as the first form.
With the various elements of the safety valve, the latching
mechanism, the control fluid line and the slip joints connected in
the manner illustrated, the plug in the lower end of the tubing
string T3 is removed and the well placed on production. Should any
condition occur at the surface which would result in reducing or
releasing the control fluid pressure in the control fluid line CF3,
the valve closure 35a will move to the closed position, as will be
hereinafter explained in connection with the details of the
construction and operation of the valve.
Thus, a single string well may be equipped with a surface
controlled subsurface safety valve in the same manner as the
multiple string well already described, and placed in controlled
production in the same manner without the necessity of killing the
well, removing the tubing string and the packer, and recompleting
the well. Instead, only the receptacle, the safety valve, the latch
member and the replacement tubing string are installed above the
overshot hanger and the well is then ready for production. In this
form of the apparatus, as in the other, the latching mechanism and
the safety valve SV3 may be removed for service or repair as
desired and may then be replaced in the well in the same manner as
the multiple string equipment was removed and installed. Thus all
the advantages of the multiple string production well are provided
in the single string production well of the form first
described.
The safety valves SV1, SV2 and SV3 may be any desired type valve in
which the clousre member is moved between open and closed positions
by a longitudinally movable actuator member in the valve. One
satisfactory form of the device is illustrated and described in
detail in U.S. Pat. application, Ser. No. 99,543, filed Dec. 12,
1970, by Donald F. Taylor, now U.S. Pat. No. 3,696,868 and is shown
in FIGS. 13A through 13D, inclusive, wherein the valve V includes
an elongate tubular housing 110 having internal threats 110a at its
upper end into which the lower end of a landing nipple N is
threaded. The landing nipple comprises a body 111 having a locking
recess 112 consisting of a plurality of annular stop and locking
grooves providing an upwardly facing stop shoulder therein in the
same manner as that shown in the U.S. Pat. No. to Tamplen,
3,208,531, issued Sept. 28, 1965. Below the locking recess is a
reduced bore providing a sealing surface 113 which is polished and
adapted to receive and be engaged by seals on well tools anchored
in the landing nipple as explained in that patent.
The lower end of the housing 110 of the valve is provided with a
seat bushing or sub 115 which is welded or otherwise suitably
secured to the housing and provides an upwardly facing internal
concave seating surface 116 surrounding the bore 117 through the
sub. A ball valve closure member 120 is movable in the enlarged
bore of the valve section 124 of the housing 110 above the seat 116
and is adapted, when in its lower position, to engage said seat to
position the closure member in an open position with its
diametrical flow bore 121 in axial alignment with and communicating
with the bore 117 of the sub. Since the valve may be identical to
that shown in the U.S. Pat. to W. W. Dollison, No. 3,583,442,
issued June 8, 1971, it will not be described in great detail.
Other types of valves such as that shown in the U.S. Pat. to Fredd,
No. 3,007,669, may also be used, if desired.
Above the ball valve closure 120 is an elongate tubular actuating
sleeve 125 which is movable longitudinally in the housing or body
110 and is connected with an moves the ball valve closure member
120 longitudinally therewith. The valve closure member is
operatively connected with the lower end of the actuating sleeve by
means of a pair of connector links 127 each having a support pin
128 welded or otherwise suitably secured thereto and engaged in one
of a pair of diametrically opposed recesses 129 formed in the ball
and each receiving one of the pins 128. The upper end of each
connector link 127 has an inwardly projecting flange or arm 130
which is engaged in an annular slot or groove 131 formed in the
enlarged lower portion 132 of the actuator sleeve 125. The extreme
lower portion 132a of the sleeve is still further enlarged below
the annular groove, and this further enlarged portion is provided
with a pair of diametrically opposed vertical cut-away guide slots
133, in each of which the longitudinal upper portions of one of the
connector members 127 is disposed. The opposite sides of the ball
closure member 120 surrounding the recesses 129 are flattened as at
135, and the lower portions of the connector members 127 are
slidable on these flattened surfaces with the pins 128 engaged in
the recesses 129 in the ball. A slidable operator or rotator sleeve
140 is disposed in the lower portion of the bore of the valve
section 124 of the housing or body 110 and is slidable between a
shoulder 143 on the lower end of a guide bushing 122 which is
threaded into the upper end of the valve housing section 124 of the
valve body and is welded or otherwise suitably secured at its upper
end to the lower end of the spring housing section 123 of the valve
body 110, for a purpose which will be hereinafter more fully
explained.
A beveled seat shoulder or surface 150 is formed at the upper end
of the enlarged portion 132 at the lower end of the actuating
sleeve 125, and this seat shoulder engages a downwardly facing
beveled seat 151 formed in the bore of the guide bushing 122, above
the enlarged portion of the bore of said bushing therebelow and
intermediate the ends of the bushing. When the actuating sleeve is
in the upper powition, the seat shoulder 150 engages the seat 151
to close off flow exteriorly of the actuating sleeve. When the
sleeve is in the lower position shown in FIG. 13 B, the seat
shoulder 150 is spaced below the seat 151 and fluids may flow past
the enlarged lower portion 132 of the actuating sleeve, and the
fluids so entering will flow upwardly then inwardly through a
plurality of lateral equalizing ports 138 formed in the wall of the
tubular actuating sleeve 125 above the seat shoulder 150 and into
the bore 126 of the tubular sleeve.
When the sleeve is in the upper position, the equalizing ports are
closed off from communication with the bore of the valve housing
section 124 therebelow, and flow from below the seat 151 inwardly
through such ports to the bore 126 of the sleeve is prevented.
The ball valve closure member 120 seats upon a hardened wear
material seat surface 160 formed at the lower end of the bore 126
of the sleeve 125, and when the valve is in the upper closed
position (FIG. 19), the valve closure member 120 is rotated to turn
the diametrical bore 121 thereof out of communication with the bore
126 of the sleeve to close the seat 160 and no flow can take place
in either direction through the housing and sleeve.
Guide pins 165 are each welded or otherwise suitably
secured in an aperture formed in the rotator sleeve 140 on each
side of the ball valve closure member 120 and engage one side of
the adjacent connecting links 127. A similar pair of turning pins
170 are also secured by welding or the like to the rotator sleeve
on the opposite side of the connector links 127 on each side of the
closure member and, with the pins 165, maintain the positional
relationship of the valve closure member and the connecting links
during longitudinal movement of the valve closure member and the
rotator sleeve. The guide pins 165 are sufficiently short that
their inner ends will ride along the flattened surfaces 135 of the
ball valve closure member as the ball valve and actuating sleeve
move rotatably with respect to each other. The turning pins 170
engage in angularly disposed grooves or slots 175 formed in the
exterior of the ball valve closure member on opposite sides of such
closure member, and these turning pins engage the inclined surfaces
of the angularly disposed slots to rotate the ball between open and
closed positions when the ball is moved longitudinally with respect
to the rotator sleeve 140 by the connector links 127 moved by the
actuating sleeve 125.
As the rotator sleeve 140 is moved upwardly when the actuating
sleeve 125 is moved upwardly, the upper end of the rotator sleeve
engages the downwardly facing shoulder 143 in the bore of the
housing 110 and further upward movement of the rotator sleeve is
stopped. However, the elongate tubular actuating sleeve 125 may
continue to move upwardly until the seat shoulder 150 engages the
downwardly facing seat 151 in the bushing 122 forming a part of the
housing or valve body 110. Such upward movement of the actuator
sleeve lifts the connecting links 127 and also lifts the ball valve
closure member 120 upwardly with respect to the rotor sleeve 140.
Due to the engagement of the actuating or turning pins 170 and the
slots 175 in the ball, the ball will be turned from the open
position shown in FIG. 13B to its closed position (FIG. 19) during
such upward movement.
As is explained in the patent to Dollison, the valve closure member
is moved between open and closed positions under conditions of
equalized pressure across the closure member, and the closure
member is rotated or moved between such open and closed positions
by longitudinal movement of the actuating sleeve 125 in the
housing.
For moving the actuating sleeve 125 to cause rotation of the valve
closure member, a piston 176 is formed on the exterior of the
actuating sleeve 125 by means of an external annular flange formed
integral with the actuating sleeve and provided with an external
annular groove 177 in its mid-portion for receiving a seal ring 178
for sealing between the piston and the bore wall of the spring
housing 123. A helical coiled spring 179 is confined between the
lower end of the piston 176 and the upper end of the bushing 122
and this spring acts to bias the piston and the actuating sleeve
upwardly in the housing to move the seat 150 into and out of
engagement with the seat 151 and to rotate the valve closure member
120.
The upper end of the actuator sleeve 125 is slidable in the lower
portion of the bore 182 of a latch section 183 forming the upper
portion of the valve body 110. An internal annular seal ring 184 is
disposed in an internal annular groove 185 formed in the lower
portion of the bore 182 of the latch housing and seals around the
upper end of the actuator sleeve above the piston 176. Thus, the
bore 186 of the spring housing 123 between the lower end of the
latch housing 183 and the piston forms an operating cylinder 186
into which control fluid may be conducted through an annular flow
passage 187 in a boss 188 welded or otherwise suitably secured to
the exterior of the spring housing 123 and having the control line
L connected thereto for conducting control fluid pressure through
the angular passage 187 into the chamber 186 for biasing the piston
176 downwardly against the spring 179 to move the actuating sleeve
125 downwardly to open the valve.
Thus, the valve is normally biased to a position in which the
closure member closes off flow therethrough, but is placed into
operation to permit flow by introducing control fluid through the
control line L into the chamber 186 to act downwardly on the piston
176 to move the actuator sleeve 125 downwardly and cause the valve
to be rotated to the open position shown in FIGS. 13A and 13B to
permit flow therethrough until the actuating fluid or control fluid
pressure is reduced for any reason, which may be controlled by
various sensing apparatuses or devices at the surface, or which may
be caused by the occurrence of some condition in the well system
which has been sensed by various types of sensing devices connected
in the system, such as pressure reducing systems, fire detecting
systems, remote control systems, liquid level control systems, and
sensing systems and the like.
Secured to the lower end of the safety valve V is the locking and
sealing mechanism LM connected thereto by means of a coupling
member 225 which is threaded onto the lower end of the valve
housing 110 and the upper end of th latching mechanism. This
latching mechanism is designed to be inserted into and lock and
seal in the receptacle R which is threaded into the upwardly facing
box member of the joint U of the tubing string T left in place in
the well. The receptacle includes a housing 227 having an enlarged
bore 228 above its reduced lower end 229. The enlarged bore has an
internal annular downwardly facing stop shoulder 230 formed therein
which is engaged by a locking flange for retaining the latching
member L in place in the receptacle R, as will hereinafter be
explained. The upper end of the bore of the housing 227 has coarse
buttress type lefthand threads 231 formed therein which receive
corresponding mating threads at the lower end of the handling
string HS by means of which the receptacle is lowered into the well
bore and threaded into the open box member of the connection or
joint U of the tubing string in the manner already described. At
least one suitable radial aperture 232 is provided for receiving a
shear pin similar to the shear pin 23 to lock the handling string
to the receptacle until it is desired to release and remove the
handling string, as has already been described. This shear pin, as
has already been explained, assures that the threaded lower reduced
end of the receptacle R is made up in tight flow sealing
communication with the box member of the joint U at the upper end
of the tubing string T.
The latching mechanism LM includes an elongate upper seal mandrel
section 235 having an external annular flange 236 at its upper end
below the threaded pin 237 by means of which it is connected to the
coupling 225 and the valve V thereabove. Spaced substantially below
the external flange is a reduced lower exterior cylindrical sealing
surface section 238 having a downwardly facing stop shoulder 239 at
its upper end and threads 240 at its lower end. Between the threads
and the shoulder are mounted a plurality of sealing ring assemblies
241, each of which may comprise an annular beveled central seal
member ring 242 and a pair of retainer rings 243 which are molded,
bonded or otherwise secured to the seal rings 242 for sealing
between the mandrel 235 and the bore wall of the receptacle R above
the locking shoulder 230 therein. It is believed readily apparent
that the external annular flange 236 on the latching mechanism will
engage the upper end of the receptacle R to stop downward movement
of the latching member into the receptacle before the seal members
reach the lower end of the internal sealing surface 228a in the
base 228 above the locking shoulder 230, to prevent damage to the
seal assembly.
Below the sealing mandrel section 235 is a latching mandrel section
245 which has an internal annular enlarged bore 246 at its upper
end provided with internal threads which engage the threads 247 on
the lower end of the sealing mandrel section, and an internal
annular stop shoulder 248 which abuts the lower end of the sealing
mandrel section 235 to form a seal therewith and limit movement of
the upper end of the locking mandrel section 245 toward the seal
assemblies 241. The upper end of the locking mandrel and the
downwardly facing shoulder 239 on the seal mandrel section provide
means for limiting movement of seal assemblies on the external seal
surface portion 238 of the latching mandrel section and confine the
seal assemblies thereon.
Below the upwardly facing shoulder 248 in the bore of the latching
mandrel, the bore of the mandrel is enlarged by a downwardly and
outwardly inclined bevel undercut 249, and a plurality of resilient
collet latching members 250 are formed by a plurality of
circumferentially spaced longitudinally extending slots 251 which
define the lateral edges of the collet latching members. Exteriorly
of each of the collet latching members is an external boss or lock
member 252 having an upper beveled surface 253 which is adapted to
engage the downwardly facing lock shoulder 230 in the bore of the
receptacle R to hold the latching mechanism in place in the
receptacle. The slots 251 extend downwardly a substantial distance
below the locking bosses 252 and terminate above the lower end of
the latching mandrel section which extends downwardly a substantial
distance below the slots and is provided with internal threads 256
which receive the externally threaded upper end of a guide and
retaining bushing 257 threaded into the lower end of the latching
mandrel section.
Slidable within the lower enlarged bore of the latching mandrel
section 245 is the locking sleeve 260, previously described as
locking sleeves 43 and 44 in the description of the method of the
invention. The locking sleeve 260 has at its upper end a
cylindrical tubular locking section 261 having a bore 262
therethrough and a downwardly and outwardly inclined external
shoulder 263 at its upper end adapted to engage the downwardly
facing shoulder 249 in the bore of the latching mandrel section 245
when in its upward position. The locking section 261 is adapted to
engage the inner surfaces of the resilient collet members 250 to
hold the same in expanded position, so that the stop shoulders 253
on their bosses 252 will positively engage the downwardly facing
lock shoulder 230 to prevent disengagement and withdrawal of the
latching mechanism LM from the bore of the receptacle R, as has
already been explained.
The lower portion of the bore of the locking sleeve 260 is enlarged
to provide a downwardly facing shifting shoulder 264 by means of
which the sleeve is shifted upwardly, as will be hereinafter
further explained. Below the shoulder 264, the enlarged bore of the
sleeve is slotted longitudinally, as at 265, at spaced points about
its circumference to provide a plurality of resilient detent
members 266 having detent bosses 267 on their external faces, which
engage in a lower internal annular detent groove 270 to hold the
locking sleeve in its lower inoperative position shown in FIG. 13C.
The slots 265 permit the springing of the detent members 266
inwardly to permit the bosses 267 on the exterior thereof to move
out to such lower internal annular detent groove 270 so that the
locking sleeve 260 is movable upwardly from such lower inoperative
position. The locking sleeve is then movable in the enlarged bore
of the latching mandrel section to its upper operative position
therein, and the bosses 267 engage in the upper internal annular
detent groove 271 in such enlarged bore below the stop shoulder
249. In this position, the beveled shoulder 263 at the upper end of
the locking section 261 is in substantial engagement with the stop
shoulder 249 and the exterior surface of said locking section is
disposed between the several spring collet members 250 to hold them
in their expanded position shown in FIG. 13, so that the bosses are
positively held in position to engage the downwardly facing lock
shoulder 230 in the receptacle R.
Thus, when the locking sleeve 260 is in the lower position, the
spring collet members 250 may spring inwardly to pass below the
internal annular flange in the bore of the receptacle having the
locking shoulder 230 at its lower end. However, when it is desired
to lock the latching mechanism in place in the receptacle, the
locking sleeve 260 is shifted upwardly, as will hereinafter be
explained, to the position shown in FIG. 15B, in which the locking
section is disposed between the collet members to positively hold
the bosses 252 thereon in locking position to prevent removal of
the latching mechanism LM from the receptacle R.
For shifting the locking sleeve 260 from its lower position, shown
in FIG. 13C, upwardly to the locking position, shown in FIG. 15B,
the upshifting tool US is connected to the lower end of the guide
string GS, as shown in FIG. 13B, and the spear SP is connected to
the lower end of the upshifting tool. Any suitable upshifting tool
may be utilized to engage the locking sleeve 260, but a shifting
tool such as that illustrated in the U.S. Pat. to Grimmer et al.,
No. 3,051,243, dated Aug. 28, 1962, may be utilized. As clearly
shown in the patent and in FIG. 13B, the shifting tool includes a
mandrel 280 having a box 281 on its upper end threaded onto the
lower end of the guide string GS. A pair of shifting keys 282,
which have been described as keys 41 and 42 in the description of
the method, are positioned on the reduced lower portion of the
mandrel 280. These keys are biased outwardly toward engaging or
shifting position by a spring 283 in the same manner as in the
Grimmer et al patent, and the upwardly facing abrupt shoulder 284
on the exterior of the shifting keys is adapted to engage the
downwardly facing shoulder 264 in the bore of the locking sleeve
260 to lift the same when the guide string is lifted. The keys will
lift the locking sleeve until the beveled shoulder 263 at the upper
end thereof engages the downwardly facing shoulder 249 in the bore
of the latching mandrel section 245. This assures that the
retaining detent bosses 267 on the sleeve engage in the upper
internal detent groove 271 in the bore of the latching mandrel
section to retain the locking sleeve in such upper position,
holding the locking bosses 252 on the collet members 250 in their
expanded locking position, as shown in FIG. 14.
A further upward pull applied to the guide string GS will cause the
shear pin 285, supporting the slidable sleeve 286 on which the
shifting keys are mounted, to be sheared to permit the supporting
sleeve to move downwardly on the mandrel in the bore of the
upwardly facing receptacle or cup 287 threaded onto the lower end
of the mandrel, in the same manner as in the patent. The downwardly
and inwardly inclined surfaces 288 on the lower exterior ends of
each of the keys engage the beveled shoulder 289 on the upper end
of the bore of the cup or receptacle and positively wedge or cam
the keys inwardly against the force of the spring 283, to hold the
same retracted and permit the keys to pass the downwardly facing
shoulder 264 in the bore of the locking sleeve 260, so that the
guide string may be lifted out of the bore of the tubing string and
the shifting tool and spear SP lifted upwardly therewith through
the bore of the latching mechanism LM, and through the bore of the
safety valve V and the replacement upper flow conductor section RT
above the safety valve to the surface, as has been already
described.
The spear SP may be any suitable commercial releasing type spear
which will engage in the bore of the lower portions of the tubing
strings T1 and T2 left in place in the well to support the same and
provide a positive connection between the guide string GS and such
tubing strings. The spears may be released in the usual manner to
permit the upward movement therewith of the upshifting tools US,
which lift the locking sleeves 260 upwardly to locking position.
Thereafter, continued upward movement cams the shifting keys from
shifting position to releasing position to permit complete
withdrawal of the guide string GS and the upshifting tool and spear
connected thereto from the well.
One type of overshot hanger OH useful for supporting the upper ends
of the tubing strings T1 and T2 left in place in the well, is
illustrated in FIGS. 16A through 18C, inclusive. As shown in FIGS.
16A and 16B the overshot hanger comprises a plurality of body
members 301, 302, 303, 304, 305, 306, and 307, all connected
together in longitudinally spaced relationship by means of an
elongate tubular conductor pipe or member 310 which is threaded
into the underside of the upper body member 301 and extends
downwardly through aligned bores 303d, 304d and 305d in the body
members 303, 304 and 305, respectively, to the next lowest member
306, and is threaded into the upper end of an aligned threaded bore
306d therein. The lowermost body member 307 is connected to the
next to lowest member by an elongate rod or shaft 311 having
retaining nuts 312 threaded on its lower end, and which extends
upwardly through aligned bores 307c, 306c, 305c, 304c and 303c in
the body members, 307, 306, 305, 304 and 303, respectively, and has
its upper end threaded into a threaded blind bore 302c in the lower
end surface of the body member 302.
As will be seen in FIGS. 16A and 16B, each of the body members 301
through 307 is provided with a pair of laterally offset
longitudinal bores through which the tubing strings T1 and T2 are
insertable. The bores in each of the body members are identified by
the corresponding numbers applied to the body members with suffixes
a and b, so that the bore in each of the body members through which
one of the tubing strings extends is defined as 301a through 307a,
inclusive, while the bores in the body members through which the
other tubing string extends are defined as 301b through 307b,
inclusive.
As is shown in FIG. 18A, the upper end of the tubular connector
member 310 is secured to the body member 302 by a shear pin 312
which prevents rotation of the upper section 301 with respect to
the several body sections therebelow while the shear pin is
integral and also prevents the other body members connected to the
second body member 302 from sliding downwardly with respect to such
upper body member until desired.
As is clearly shown in FIG. 18B, a connector rod 311 has a reduced
lower rod 311a threaded into the lower end thereof below the body
member 305, and the lower portion of the rod 311a has a piston 313
formed thereon which is disposed in a cylinder 314 formed in the
body member 306 for a purpose which will be hereinafter more fully
explained.
The lower body member 307 also has a piston 315 secured thereto and
extending upwardly therefrom into a cylinder 316 formed in the body
member 306, preferably in longitudinal alignment with the tubular
connector member 310. Seal rings 315a are positioned in external
annular recesses formed in the upper portion of the piston 315 for
sealing between the piston and the wall of the cylinder 316.
Similarly, seal rings 313a are positioned in external annular
recesses formed in the piston 313 for sealing between that piston
and the cylinder 314. The upper ends of the cylinders 314 and 316
are connected by a lateral conductor passage 318 whereby fluid may
be conducted between the cylinders for a purpose which will be
hereinafter explained.
Each of the body members 302, 303, and 304 is secured by shear pins
312, 319 and 320, respectively, to the tubular connector member
310. Similarly, the body member 305 is connected to said tubular
connector member by one or more shear pins 320 extending into one
or more suitable radial apertures or recesses formed in the
exterior of the connector member and through a connector sleeve 321
threaded into the underside of the body member 305. These shear
pins prevent disconnection of the body member 305 from the tubular
connector member 310 until after the shear pins 312, 319 and 320
are sheared to permit movement of those body members in which they
are disposed with respect to the connector member.
The body member 302 has a tubular collet type gripping slip member
324, secured to the lower side thereof in axial alignment with the
aperture 302a, comprising a cylindrical body 325 having a plurality
of depending integral spring fingers 326 with internally serrated
gripping slip members 326a on their lower ends having downwardly
and inwardly tapered outer surfaces 326b disposed to engage in a
tapered wedge bowl 327 formed in the bore 303a of the next lower
body member 303. The slip members are adapted to engage the tubing
string extending through the bores 302a and 303a of the body
members 302 and 303 when the slip members are moved downwardly with
respect to the tapered bowl 327.
The body member 303 similarly has a gripping slip member 330
comprising a tubular body 331 threaded into the bore 303b and
extending downwardly therefrom in axial alignment with said bore. A
plurality of integral resilient spring fingers 332 are formed on
the lower portion of the gripping member and inwardly facing
serrated gripping slip members 332are formed on the lower ends of
the fingers and have downwardly and inwardly inclined wedge
surfaces 332b on their outer sides which engage a correspondingly
tapered locking bowl 333 in the bore 304b of the body member 304.
This gripping member is adapted to grip the other of the tubing
strings which is extending through the bores 303b and 304b of the
body members 303 and 304 in the same manner as the gripping member
324 just described grips the tubing string extending
therethrough.
The body member 305 has a plurality of conventional casing gripping
slips 335 supported on the upper end surface thereof and retained
thereon by T-shaped handles 336 engaging in corresponding T-shaped
slots in the body member. The slips have external serrated gripping
teeth 335a on their outer surfaces and downwardly and inwardly
inclined wedge surfaces 337 on their inner surfaces disposed to
engage similarly inclined complementary wedge surfaces 338 on the
lower exterior of the body member 304, whereby the casing slips may
be expanded outwardly into gripping engagement with the well casing
in the well known conventional manner.
The lower end of the operating rod 311a below the piston 313
extends downwardly through the bore 340a of the locking sleeve 340
and through the opening 307a in the body member 307, and has
retaining and locking nuts 312 screwed on the lower end thereof.
The locking sleeve 340 has a plurality of locking wedge members 341
resiliently biased upwardly on an inwardly and upwardly tapered
locking wedge surface 342 in the bore 340a of the sleeve by a
helical coil spring 343 confined between the lower end of the
locking wedge members 341 and a retaining ring 344 held in the bore
of the locking sleeve by a snap ring 345. The exterior surface of
the lower portion 311b of the connecting rod 311a is provided with
a plurality of serrations or angular teeth for engagement by the
serrated gripping teeth on the wedge members 341 to provide a more
positive lock between the wedge members in the locking sleeve and
the lower portion 311b of the connecting rod 311a for a purpose
which will be hereinafter more fully explained. The rod 311a slides
in the upper reduced bore 306c of the body member 306 and a
plurality of seal rings 350 are disposed in internal annular
recesses in such bore and seal between the body member 306 and the
connecting rod 311a to confine fluid pressure in the cylinder bore
314 therebelow above the piston 313. Similarly, if desired, an
internal annular seal ring 351 may be provided in the bore 306d for
sealing between the tubular connector member 310 and the body
member 306. Likewise, a seal ring 352 is provided in the bore 301d
for sealing between the body member 301 and the upper end of the
tubular connector member 310.
An operating string OS is connected to the body member 301 in axial
alignment and flow communication with the bore 301d and a seal ring
353 is disposed in an internal annular groove in said bore for
sealing between the body member and the operating string. The
connection between the operating string and the body member 301 is
preferably a coarse left hand thread to permit ready disconnection
of the operating string from the body member when desired.
In operation, the overshot hanger is lowered into the well by means
of the operating string OS telescoping over the upper ends of the
tubing strings T1 and T2 in the manner already described. For sake
of convenience, the bores 301a through 307a will be assumed to
telescope over the tubing string T1 while the bores 301b through
307b will be assumed to telescope over the tubing string T2. The
bores 301a through 307a and 301b through 307b are sufficiently
large to slide over the integral joint members of the tubing
strings T1 and T2, as has already been described. When the overshot
hanger has been lowered to a desired point below the upper ends of
the tubing strings T1 and T2, the hanger is locked in place in the
casing for supporting the tubing strings, as will now be
described.
With the overshot hanger at the desired point in the well bore,
hydraulic fluid pressure is supplied through the operating string
OS to the upper end of the tubular connector member 310, through
which it flows downwardly into the cylinder 316 in the body member
306 to act on the piston 315 and through the passage 318 into the
cylinder 314 to act on the piston 313. Such pressure acting on the
pistons 315 and 313 moves the body member 307 downwardly and forces
the connector rod 311a downwardly to move the externally serrated
portion 311b of said rod downwardly through the locking wedge slips
341 in the locking sleeve 340. Such downward movement of the
connector member 311a moves the connector member 311 to which it is
connected downwardly to pull the body member 302 downwardly,
shearing the pin 312 forcing the body member 302 downwardly on the
tubular connector member 310. This action moves the upper tubing
gripping slip member 326 downwardly in the slip bowl 327 of the
body member 303 and wedges the gripping teeth 326a on the lower
ends of the resilient fingers into gripping engagement with the
tubing string T1 extending therethrough. Continued application of
fluid pressure to the pistons 315 and 313 will cause the body
member 306 to move upwardly relative to the body member 307 and so
lift the body member 305 and the body member 304 upwardly relative
to the body member 303, which is now held stationary by the
engagement of the slip members 326a in the bowl 327 in the bore
303a thereof with the tubing string T1. Further application of
fluid pressure to the hanger will shear the shear pin 314
connecting the body member 303 to the tubular connecting member
310, after which the body member 304 moves upwardly with respect to
the body member 303 to engage the tapered bowl 333 with the
gripping slip members 332a at the lower end of the resilient
fingers 332 to force the same inwardly into gripping engagement
with the tubing string T2 extending through the bore 303b of the
body member 303 and the bore 304b of the body member 304. Further
continued upward movement of the body member 306 lifts the tubular
connector member 310 upwardly to shear the pin 320 in the body
member 304 and move the casing gripping slips 335 carried by the
body member 305 upwardly along the wedging surfaces 338 on the
exterior of the body member 304 to expand the casing gripping slips
into gripping engagement with the inner wall of the well casing and
so lock the overshot hanger in gripping supporting engagement with
the casing and with the two tubing strings extending
therethrough.
When the hanger is so locked in place, the hydraulic fluid pressure
applied through the operating string OS to the cylinders 314 and
316 is discontinued and the operating string may then be
disconnected from the upper body member 301 by right hand rotation
of the pipe to disengage the left hand threads at the lower end of
the operating string from the threads 354 in the bore 301d of the
body member 301 and leave the overshot hanger firmly anchored in
place in the well casing. The wedge gripping members 341 engage the
serrated surface 311b on the connecting rod 311a to positively hold
the connecting rod in the lower position in which the members are
telescoped together in gripping position.
Ordinarily, the overshot hanger is not removed until it is desired
to rework the well, in which event the hanger may be removed in the
usual manner by lifting the tubing string at the surface connected
to the tubing string T1 or T2 to lift the hanger out of the casing
and out of the well bore.
It is believed perfectly obvious that, if desired, a separate
overshot hanger may be provided for each of the tubing strings T1
and T2, each hanger having two bores therethrough to receive the
two tubing strings but only one of which has gripping members
povided therein for engaging and supporting one of the tubing
strings. Thus, one hanger for the tubing string T1 will have a bore
sufficiently large to slide freely over the tubing string T2 and be
provided with gripping members in the other bore to engage the
tubing string T1 to support the same, while the other hanger will
have its bore without slips telescoped over the tubing string T1
and the slips in its other bore in gripping engagement with the
tubing string T2 for supporting the same, and the casing slips on
each of the hangers engaged with the casing wall. In such an
installation, the overshot hangers will be spaced vertically in the
bore of the well sufficiently to permit their insertion and
operation. The same hydraulic actuation of the gripping members may
be employed, if desired.
Such a hanger may be also provided by merely omitting the gripping
slip members 325 or 332, respectively, as the case may be, from the
overshot hanger of FIGS. 16A through 18C so that the overshot
hanger merely grips one of the strings of tubing extending
therethrough.
Should it be desired to release the replacement upper tubing flow
conductor portion and safety valve and latch mechanism from locking
sealing engagement in the receptacle R, a suitable downshifting
tool may be connected to the lower end of the guide string GS and
inserted through the desired tubing string T1 or T2 into the
latching mechanism for shifting the locking sleeve 260 therein
downwardly to free the collet locking dogs 252 for inward and
upward movement past the downwardly facing locking shoulder 230 in
the bore of the receptacle. Such a downward shifting tool is
illustrated in FIGS. 20A and 20B.
The downshifting tool DS is preferably connected to the lower end
of a guide string GS and lowered through the replacement upper
tubing portion until the downshifting tool engages the locking
mechanism of the assembly as will be described. Obviously, the
downshifting tool may be operated by through-the-flow-line pumpdown
tools, if desired, by connecting a suitable locomotive member (not
shown) to the upper end of the downshifting tool, or it may be
operated by conventional wire line equipment, if desired. It is
preferable that the guide strings be set in place and connected to
the upper ends of the lower portion of the tubing string left in
place in the well before the replacement upper flow conductor is
removed from the well to facilitate the later reinstallation of the
replacement upper flow conductor portion after the safety valve has
been serviced, and this is accomplished by first removing the
downshifting tool and then reinserting the guide string with an
anchor and upshifting tool thereon prior to disconnecting the
latching mechanism and removing the replacement upper flow
conductor in the manner already described.
The downshifting tool DS comprises an elongate mandrel 401 which is
connected at its upper end to the guide string GS, or to any other
suitable operating mechanism by threads or the like. The mandrel
has a shifting key sleeve 402 slidably mounted thereon and confined
between a retaining sleeve 403 which is secured by a shear pin 404
to the mandrel against longitudinal movement thereon and is adapted
to be engaged by the upper end of the shifting key sleeve to limit
upward movement of the keys on the mandrel. Downward movement of
the shifting key sleeve on the mandrel is limited by the upper end
of an expander mandrel section 405 connected by screw threads to
the lower end of the upper mandrel section 401. The expander member
has an external annular enlargement having a downwardly and
inwardly inclined wedge surface 406 thereon intermediate its ends
for expanding a plurality of gripping slips 407 having tilted
hardened disc inserts 408 brazed in suitable recesses in the
exterior thereof providing downwardly facing gripping teeth for
engaging the locking sleeve 260 to shift the same, as will be
hereinafter more fully explained. The gripping slips are mounted on
elongate spring arms 409 extending upwardly from a cylindrical body
portion 410 which is threaded onto a supporting sleeve 411 slidable
on the lower portion 412 of the mandrel expander section 405 which
has its lower end reduced in diameter and provided with screw
threads for receiving a retaining cup 413 in which a helical coiled
spring 414 is confined between the lower end of the sleeve 411 and
an upwardly facing shoulder 413a in the lower portion of the bore
of the cup. The upper end of the cup telescopes over the lower
portion of the sleeve 411 and confines the spring in the space
therebetween. The spring acts to bias the gripping slips upwardly
on the mandrel 405 along the inclined wedge surface 406 thereon for
gripping the bore wall of the locking sleeve 260 in the latching
mechanism for shifting the same downwardly from the upper position
shown in FIG. 20A to the lower position shown in FIG. 13C.
For holding the gripping slips 407 in a position below the expander
section 406 on the mandrel 405, a plurality of detent members or
balls 415 are mounted in radial openings 416 in the mandrel above
the lower end portion 412 thereof, and these balls are adapted to
engage in an internal annular recess 417 formed between the
cylindrical portion 410 of the slip assembly and the sleeve 411
connected to the lower end thereof. When the balls engage the
upwardly facing beveled surface 417a on the upper end of the sleeve
411, the slips are held downwardly against movement upwardly
relative to the expander wedge surface 406 of the mandrel. To hold
the balls outwardly in the annular recess 415, an elongate control
rod 420 is slidable in the bore 421 of the mandrel sections 401 and
405. The upper end of the control rod has an enlargement 422
thereon which s slidable in the bore of the upper section 401 of
the mandrel and a shear pin 425 extends transversely through an
aperture in the sleeve 403 and through a diametrical opening 427 in
the enlarged head of the control rod. The shear pin slides in an
elongate slot 430 formed in the wall of the mandrel section 401,
until the mandrel section is moved downwardly a sufficient distance
to cause the upper end of the slot to engage the shear pin and
shear the same. The lower portion of the control rod 420 has an
external annular locking flange 431 thereon which is disposed to
engage between the detent balls 415 to hold the same outwardly in
the annular locking recess 417 in the sleeve at the lower end of
the gripping slips assembly. Thus, when the control rod is in the
lower position with its lower end engaging the closure at the lower
end of the bore 421 of the mandrel sections, the flange will engage
the balls and hold the same outwardly in the groove 417 for
engagement by the shoulders 417a, to hold the gripping slips in the
lower position out of engagement with the expander wedge 406 on the
expander section of the mandrel.
In operation, the tool is lowered into the well until the
downwardly facing shoulders 435 of the shifting keys 436 engage in
an internal annular stop groove 437 formed in the bore of the
receptacle R below the upper end thereof, while the guide boss 438
at the lower end of the shifting keys engages in an internal
annular recess 439 having inwardly divergent inclined shoulders at
its upper and lower ends to permit the abrupt downwardly facing
shoulders 435 on the keys to move outwardly in the recess 437 and
engage the upwardly facing abrupt shoulder 440 in the recess to
stop downward movement of the locator keys. When the locator keys
are engaged in the annular grooves 437 and 439 in the manner just
described, downward movement of the keys and the sleeve which
supports them is arrested. Similarly, the engagement of the
retainer sleeve 403 with the upper end of the locator key sleeve
402 prevents downward movement of the retainer sleeve, until
further downward movement of the mandrel section 401 shears the pin
404 to permit the mandrel section to move further downwardly. Such
downward movement of the mandrel section is permitted by movement
of the pin 425 in the slot 430, and the lower portion of the
expander section 405 of the mandrel is moved downwardly to move the
balls 415 downwardly with respect to the external flange 431 on the
control member 420 until the balls move below the lower end of the
external flange and may move readily inwardly in the apertures 416
out of the internal annular groove 417 in the slip carrier sleeve
to free the slip carrier sleeve and the actuating sleeve 411 to be
moved upwardly by the spring 414 to force the slip gripping members
407 upwardly on the inclined wedge surface 406 to expand the
gripping members into gripping engagement with the bore wall of the
locking sleeve 260, as shown in FIG. 20A.
When the slips are engaged with the bore of the locking sleeve 260,
further downward force applied to the upper mandrel section 401
will move the same downwardly to shear the pin 425 and permit the
mandrel section to move downwardly with respect to the locator keys
to shift the locking sleeve 260 to the lower position shown in FIG.
13C, where the outer locking surface on the section 261 thereof is
out of engagement with the collet members 250, to permit the
external bosses 252 on the mid-portions of said collet members to
be moved inwardly by engagement of the upper beveled locking
shoulders 253 thereon with the downwardly facing locking shoulders
230 in the bore of the receptacle, so that the replacement upper
flow conductor portion, the safety valve, and the latching
mechanism may all be removed from connection and sealing flow
communication with the receptacle R.
Obviously, this procedure may be performed on any one of the
latching mechanisms in place in the well.
After the locking sleeve 260 has been moved to its lower position,
the guide string and down shifting tool DS are lifted out of the
well through the replacement upper flow conductor portion above the
receptacle and a guide string hving the releasing spear SP and
upshifting tool US thereon is lowered into the well through the
replacement flow conductor portion and anchored in engagement with
that portion of the tubing string T1 or T2 left in place in the
well below the receptacle, whereupon the replacement flow conductor
portion may be stripped off over the guide string and out of the
well, carrying the safety valve and latching mechanism with it for
repair, replacement, or the like.
When the downshifting tool is lifted out of the well after the
locking sleeve 260 has been moved to the lower position, engagement
of the detent bosses 267 in the lower detent recess or groove 270
prevents upward movement of the locking sleeve 260 thereby as the
downshifting tool is withdrawn.
It is also believed to be obvious that, if desired, the bore of the
locking sleeve 260 may be enlarged in its upper portion, as shown
in dotted lines in FIGS. 14 and 15, to provide a recess 260a and an
upwardly facing shifting shoulder 264a which may be engaged by an
upshifting tool US connected to the guide string GS in an inverted
position so that the abrupt shoulder 284 on the upshifting tool
faces downwardly to engage the upwardly facing shoulder 264a in the
locking sleeve. This would permit ready shifting of the locking
sleeve by the upshifting tool and guide string in wells in which
there is no need for use of other types of shiftable equipment in
the well, and would eliminate use of the downshifting tools of
FIGS. 20A and 20B.
In FIGS. 21 through 29, inclusive, is illustrated the method of the
invention carried out in a well in which tubing strings T4 and T5
are suspended in the well in the same manner as the tubing trings
T1 and T2 of the method first described, but in which the tubing
strings are the conventional type having couplings or collars 501
connecting adjacent sections 502 of the tubing strings, rather than
the integral joint type tubing strings such as the Hydril Integral
Joint Tubing String of the installation shown in FIS. 1 through 11.
In carrying out the method in this modification, it is usually
necessary to part or cut the tubing string between adjacent
couplings to permit installation of a pack-off overshot connection
between the portion of the flow conductor left in place in the well
and the replacement upper portion of the flow conductor inserted in
the well having the safety valve connected therein.
In this form of the method, a well installation such as is shown in
FIG. 21, which is identical to that of FIG. 1 other than that each
tubing string is composed of the usual separate joints connected by
couplings or collars, the tubing strings may be parted between
adjacent couplings at a desired elevation in the well by mechanical
cutters MC4 and MC5, such as are illustrated schematically in FIG.
22. The mechanical cutters are lowered on the guide strings GS4 and
GS5 having spears SP4 and SP5 at their lower ends and having the
cutters MC4 and MC5 connected therein at the desired location above
the spears. The cutters are operated in the usual manner to part
the tubing strings at the elevation U4 and U5 to separate the upper
portions from the portions to be left in place in the well in the
same manner as in the method set forth in FIGS. 1 through 11.
As shown in FIG. 23, the tubing strings have been parted and the
upper portions are being stipped off over the guide strings GS4 and
GS5 for removing the same from the well. After the upper portions
have been so removed, a suitable mill M, which may be an overshot
mill, or other suitable milling tool, is lowered over the guide
string to cut off or smooth the rough upper ends of the tubing
strings T4 and T5 left in place in the well, as shown in FIG.
25.
After the upper ends of the tubing strings left in place in the
well have been milled in the usual manner to smooth the same, the
overshot hanger OH4 is lowered along the guide strings GS4 and GS5,
to telescope over the upper ends of the tubing strings T4 and T5 in
the same manner as in the method of FIGS. 1 through 11, and
anchored in place in the well casing C in gripping engagement with
said casing and with the tubing strings T4 and T5, as shown in FIG.
27. The operating string OS4 is then disconnected from the overshot
hanger OH4 and removed from the well, leaving the upper ends of the
tubing strings T4 and T5 supported by the overshot hanger.
Now, as shown in FIGS. 28 and 29, the replacement upper flow
conductor portions RT4 and RT5 are lowered into the well casing in
the same manner as in the method first described. However, the
lower ends of the replacement flow conductor portions have pack-off
overshots POO4 and POO5 on the lower ends thereof, which may be any
desired commercial form of pack-off overshots which will engage
over the free upper ends of the tubing strings T4 and T5,
respectively, in place in the well to grip and seal therewith and
provide a path of flow communication from the tubing strings
through the replacement upper flow conductor sections or portions
RT4 and RT5 to the surface.
Safety valves V4 and V5 are connected in the replacement upper flow
conductor portions RT4 and RT5, respectively, in the same manner as
in the method first described, and the upper ends of the
replacement flow conductor portions are connected to the tubing
hanger and well head and anchored in place therein in the manner
already described.
The flow control lines CF4 and CF5 for controlling actuation of the
safety valves V4 and V5, respectively, are also connected in the
same manner as has already been described, and the well is then in
condition for operation as shown in FIG. 29.
From the foregoing, it will be seen that this method is carried out
in substantially identical manner to the method first described,
but that rather than utilizing the receptacle R, we have utilized
the pack-off overshots POO4 and POO5 for connecting the replacement
upper flow conductor portions to the upper ends of the tubing
strings T4 and T5 in flow conducting array.
FIGS. 30 through 33 illustrate still another method of parting the
tubing, wherein the parting is effected by means of chemical
cutters CC6 and CC7 lowered into the tubing strings T6 and T7,
respectively, from the surface by wire line or other operating
means in the usual manner for chemically cutting the tubing strings
T6 and T7 in the conventional manner by chemical process to part
the upper portion of the tubing strings T6 and T7 from the lower
portions thereof which are to be left in place in the well. In this
method, the lower portions of the tubing strings are not provided
with an overshot hanger for supporting the same, but are left in
the well supported by the packer P2 therebelow. It is usual,
following use of chemical cutters CC6 and CC7, that the upper ends
of the pipe are left relatively smooth and milling may not be
required. It is further to be recognized that the chemical cutters
CC6 and CC7 may preferably not completely part the tubing strings,
but will cut an internal annular groove therein or in a plurality
of recesses in the bore wall of the tubing closely adjacent each
other in sufficient number to permit the upper end of the tubing to
be parted by an upward pull thereon. This is a customary operation
and is a well known method of parting tubing strings in wells. If
the cutter does not cut a smooth surface, obviously the milling
tool M may be lowered to dress or smooth the upper end of the
tubing strings T6 and T7 left in place in the well, and the
pack-off overshots installed over such upper ends in the manner
already described in connection with FIGS. 21 through 29,
inclusive.
Guide strings GS6 and GS7 having spears on the lower ends thereof
are run or lowered through the tubing strings into the portions to
be left in place in the well until the spears are located below the
point at which the chemical cutter has been actuated, to support
the upper ends of the tubing strings while the strings are being
parted by an upward pull applied thereto at the surface. The
overshot mill M may then be lowered over the guide strings to
smooth the upper end of the tubing strings left in place in the
well. The replacement upper flow conductor portions RT6 and RT7 are
then inserted over the guide strings until the pack-off overshots
POO6 and POO7, respectively, are engaged over the upper ends of the
tubing strings T6 and T7 left in place in the well to establish a
path of flow communication through said tubing strings and the
respective replacement upper flow conductor portions RT6 and RT7
connected thereto by the pack-off overshots POO6 and POO7,
respectively. Other parts of the installation are identical to
those of FIGS. 21 through 29 and the well is operated in the same
manner after it has been placed in condition for operation as shown
in FIG. 33.
As is customary in the oil fields, the installation shown in FIGS.
32 and 33 may be accomplished by "spacing out" the replacement
upper flow conductor portions above the pack-off overshots POO6 and
POO7 to assure the proper length of pipe between the pack-off
overshots and the well head, the proper tension on the tubing
strings and the proper weight on the packers therebelow, as is well
known.
This is easily accomplished in this method because the portion of
the flow conductors T6 and T7 removed from the well after being cut
off from the portions left in place therein may be utilized to
provide measurements assuring the proper spacing of the elements of
the flow conductors reinstalled in the well when the same is
completed for production.
If desired, it is also believed readily apparent that a receptacle
R6 and R7 may be connected in the replacement upper flow conductor
portions RT6 and RT7 above the packoff overshots POO4 and POO5, as
illustrated at R4 and R5 in FIG. 29. Further, such receptacles R6
and R7 may be connected in the replacement upper flow conductor
portions RT6 and RT7 above the pack-off overshots POO6 and POO7 as
shown in FIGS. 32 and 33. This structure would permit the use of
the latch mechanisms in the receptacles and removal of the safety
valves V4, V5, V6, and V7 from the wells, when desired, in the same
manner as in the method of FIGS. 1 through 11, to permit servicing,
repair or replacement of the valves, or any of the other equipment
in the replacement upper flow conductor portions.
It is believed apparent that in well having tubing strings with the
usual couplings therein as illustrated in FIGS. 21 through 29,
inclusive, in some instances in some wells the tubing may be parted
at one of the couplings in the same manner as the tubing strings T1
and T2 of the integral joint tubing were parted in the method
illustrated and described in connection with FIGS. 1 through 11. In
such event, as shown in FIG. 34 an explosive charge PC is lowered
in the tubing to a position adjacent a selected one of the
couplings CP, by means of a guide string GS lowered into the tubing
string with a spear SP connected to the lower end thereof and an
upshifting tool US thereabove. A conventional collar finder KF,
such as that illustrated and described in the U.S. Pat. to Otis et
al., No. 2,571,934, is also connected in the guide string at a
point sufficiently above the spear and upshifting tool to engage in
a coupling recess above the coupling CP and permit the spear and
upshifting tool to be positioned a suitable distance below said
coupling. The explosive charge, such as a short length of
Primacord, is fixed to the guide string GS between the collar
finder and the upshifting at a point below the collar finder at
which the charge is adjacent or within the coupling CP when the
collar finder is engaged in the couplings recess at the upper end
of the pipe joint PJ connected to the upper end of the coupling CP.
The spear SP is then engaged with the tubing string below the
coupling CP. A right hand torque is applied to the guide string and
tubing below the coupling CP, while a left hand torque is applied
to the tubing string above the coupling CP, and the explosive
charge PC is then detonated to loosen the coupling CP. The tubing
string above the coupling is then rotated in a left hand direction
about its longitudinal axis to disconnect the tubing section or
joint PJ and the joints thereabove from the tubing below the
loosened coupling. If the coupling unscrewed at its lower thread
end and came out of the well with the joint PJ and the upper
portion of the tubing string removed, it is obvious that a coupling
may be connected to the lower end of a receptacle R and threaded
onto the pin end of the tubing string T11 left in place in the well
in the manner set forth in connection with the method of FIGS. 1
through 11. If on the other hand, the coupling unscrews at its
upper thread end and was left in place in the well, only the pin
end of the receptacle R needs to be inserted and connected into the
coupling or collar CP at the upper end of the tubing string T11 in
the same manner as the method of FIGS. 1 through 11. Obviously,
therefore, where no overshot hanger is to be used, the same method
as is practiced in the description of the method set forth in FIGS.
1 through 11 may be carried out in a well having the customary
usual joints of pipe and couplings or collars connecting the same.
In this case, the weight of the tubing string below the receptacle
would be supported on a packer P2 therebelow.
Obviously, the collar finder may be used to locate the coupling
recess above pipe joint PJ, the guide string marked at the surface,
the collar finder released, and the guide string then manipulated
to position the spear SP and upshifting tool US below the coupling
CP and the explosive charge PC within or immediately adjacent said
coupling before applying the opposing torques and detonating the
explosive charge in the manner already explained. The remaining
steps of the method may then be performed.
Utilizing these methods of parting the pipe and installation of the
replacement upper flow conductor portions in the well eliminates
the necessity for the overshot hanger.
It is believed obvious that, if desired, the safety valve V
installed in the replacement upper flow conductor portion RT in any
of the methods heretofore described may be a valve of the
construction illustrated in the application of Donald F. Taylor,
Ser. No. 99,534, filed Dec. 18, 1970, now U.S. Pat. No. 3,696,868,
which s designed to accommodate a replacement safety valve V9
installed in the valve V8 anchored in place therein in sealing
engagement with the housing of the valve V8 for controlling flow
through the housing of the valve V8.
The valve structure illustrated in FIGS. 13A and 13B includes a
retainer mechanism 190 operable for holding the valve closure
member in the open position. As is shown, the retainer mechanism is
contained within the latch housing 183 below the lower end of the
landing nipple N and above the upper end of the actuating sleeve
125.
The retainer mechanism includes an elongate sleeve 191 which fits
slidably within the bore 182 of the latch housing 183 immediately
below the lower end of the landing nipple N connected thereto, and
is retained in such position by a shear pin 192 disposed in a
lateral opening 193 in the latch housing and confined therein by a
retaining set screw 194 which may be secured in place by means of a
suitable compound preventing leakage past the threads and
disengagement of the plug from the bore of the opening. The inner
end of the pin 192 engages in a recess 195 formed in the exterior
wall of the sleeve 191 and so positively holds the sleeve in the
upper position until the pin is sheared. Any desired number of such
pins may be provided to obtain a required desired force to be
applied to the sleeve to move it downwardly from such position.
The bore of the latching or retainer sleeve 191 is formed with a
plurality of internal recesses or grooves 196 having a total
configuration which does not conform to any other series of grooves
in the bore of the flow conductor, packer or landing nipples
thereabove or therebelow. The recesses or grooves 196 are adapted
to be engaged by a suitable shifting tool as is explained in the
aforementioned U.S. Pat. No. 3,696,868, to Donald F. Taylor for
moving the retainer sleeve downwardly to lock the actuator sleeve
in its lower position and hold the valve open.
A detent or retainer member 210 formed by a split ring 215 engaged
in an annular groove or recess 220 is disposed to engage an
upwardly facing external annular shoulder 218 on the retainer
sleeve 191 to hold the same in its lower position.
FIG. 35 shows schematically a valve V8 of the type heretofore
described installed in a replacement upper flow conductor RT, as
has been suggested hereinabove, with a replacement safety valve V9
anchored in place therein after the valve closure of the valve V8
has been locked in the open position.
The valve housing 610 has the usual control fluid line CF8
connected thereto for controlling actuation of the valve. The ball
closure member 620 is operated in the same manner as the ball B of
the Taylor application, by means of a slidable actuating sleeve 625
and the spring 679.
Should the valve V8 fail or become unsatisfactory for any reason,
the same may be locked in the lower open position by the shiftable
locking sleeve 690, as shown in FIG. 35, and the replacement valve
V9 be lowered through the replacement upper flow conductor portion
RT, through the bore of the actuating sleeve 625, and the open ball
closure member 620, until the seal member 650 on the lower end of
the valve V9 engages and seals against the bore wall of the housing
610 below the valve closure 620. An upper seal 651 carried by the
valve V9 seals in the bore of the landing nipple 611 at the upper
end of the valve housing 610, and anchoring dogs 670 engage in the
stop and locking recesses 612 in the bore of the landing nipple to
position said upper seal in sealing engagement with the sealing
surface 613 in said landing nipple.
With the valve anchored in the position shown in FIG. 35, the
control fluid pressure from the control fluid line CF8 will pass
upwardly exteriorly of the locking sleeve 690 through an L-shaped
flow passage 691 into the bore of the housing above the locking
sleeve where it will be confined in the housing 610 between the
seal members 650 and 651 on the replacement valve V9. The control
fluid from the control fluid line CF8 may therefore be used to
control the operation of the valve V9.
If desired, and if the L-shaped flow passage 691 is not provided,
as is the case in the valve V of FIGS. 13A through 13E, the
actuating sleeve 625 may be perforated by a cutter or punch of the
usual well-known type to provide an aperture 625a (shown in dotted
lines in FIG. 35) in the wall thereof above the piston 676 to
permit the control fluid pressure to pass from the control fluid
line CF8 to the bore of the actuating sleeve 625 between the
packing or seal members 650 and 651 for actuation of the valve
V9.
This structure permits insertion of a supplemental surface
controlled subsurface safety valve in the well without the
necessity of removing the replacement upper flow conductor portion
RT until such is absolutely necessary.
It is readily apparent that the valve V9 may be inserted into the
position shown in FIG. 35 by means of the usual flexible line
operating mechanism, through-the-flow-line pump-down tools, or any
other suitable means.
FIG. 36 shows a further modification of the valve used in the
system and in practicing the method, wherein a valve V10 is
installed in a landing nipple LN10 forming a part of the
replacement upper flow conductor portion RT10 having the pack-off
overshot POO10 connected to the lower end thereof and engaged over
the upper end of the flow conductor or tubing string T10 left in
place in the well, as has been described in connection with FIGS.
21 through 29, and 30 through 33.
The landing nipple LN10 is the usual type having the control fluid
line CF10 connected to a lateral inlet 788 communicating with the
bore of the landing nipple, and the valve V10 may be identical to
the valve V9 shown in FIG. 35. The landing nipple LN10 has internal
annular locking recesses or grooves 712 therein for receiving the
locking dogs 770 of the locking mechanism of the safety valve V10,
and the seal members 750 and 751 on the exterior of the valve
assembly seal against the internal bore wall 713 of the landing
nipple LN10 above and below the lateral inlet port 789 in the inlet
fitting 788 to which the control fluid line CF10 is connected.
Control fluid introduced into the bore of the landing nipple will
pass through the port 715 of the valve V10 to control actuation of
the closure member therein in the same manner as in the form of
FIGS. 13A through 13E.
It is believed manifest that the safety valve V10 is readily
insertable into and removable from the landing nipple LN10 by
flexible line operating mechanism, through-the-flow-line pump-down
equipment, or any other suitable equipment for lowering the valve
into place in the landing nipple and locking it in position
therein.
It is believed readily apparent that all the objects of the
invention have been readily accomplished, and that a new and
improved method of servicing a well having a flow conductor already
in place therein to provide surface controlled subsurface safety
valve in the well without removing the entire well flow conductor
and equipment and completely reworking the well. Also, these
methods permit the installation of a safety valve below the surface
for controlling flow from offshore wells or other wells which would
be subject to damage of the surface connections, and the like, to
prevent undesired flow from the wells upon the occurrence of any
such undesired conditions.
It is also believed readily apparent that, if desired, any
well-known commercial type safety joint may be provided in the
replacement upper flow conductor portion above the safety valve and
below the well head to facilitate reworking the well in the event
of a disaster which destroyed or damaged the surface connection and
the upper ends of the tubing strings above the safety valve. Such a
safety joint would permit ready parting of the tubing strings at
such safety joint for replacement of the upper portion thereabove
and recompletion of the well in the usual manner, to quickly and
economically place the well back in operation and production.
This form of the valve facilitates servicing the valve and the flow
controlling parts thereof, and eliminates the necessity for
movement of the replacement upper flow conductor portion RT10
thereabove to do so.
If desired, the valve and landing nipple of FIG. 36 may be
connected in any one of the replacement upper flow conductor
portions hereinbefore illustrated and described, or the valve and
landing nipple may be connected in tandem with any of the valves
previously described.
In such latter tandem type installations, a tubular sleeve having
an anchoring mechanism and upper and lower seals similar or
identical to those of the valve V10, but provided with an
uninterrupted open flow path therethrough may be lowered into and
locked in place in the landing nipple LN10 until it is desired to
install the safety valve V10 in place therein. In this case, the
tubular sleeve would be removed in the usual manner and the valve
inserted in its place for control of flow by actuation of the valve
in the manner already described.
The foregoing description of the invention is explanatory only, and
changes in the details of the constructions illustrated may be made
by those skilled in the art, within the scope of the appended
claims, without departing from the spirit of the invention.
* * * * *