U.S. patent number 3,874,446 [Application Number 05/475,427] was granted by the patent office on 1975-04-01 for tubing hanger releasing and retrieving tool.
This patent grant is currently assigned to Baker Oil Tools, Inc.. Invention is credited to Talmadge L. Crowe.
United States Patent |
3,874,446 |
Crowe |
April 1, 1975 |
TUBING HANGER RELEASING AND RETRIEVING TOOL
Abstract
A tool for releasing and retrieving a tubing hanger, and the
like, anchored in a well casing disposed in a well bore, the tool
being connectible to a running string for lowering into the well
casing toward the tubing hanger and being oriented upon engaging
the tubing hanger to a predetermined rotational position, latch
means of the tool being coupled to the tubing hanger, enabling an
upward pull to be taken on the running string and tool for
application to the tubing hanger to effect its release from the
well casing and its retrieval from the well casing.
Inventors: |
Crowe; Talmadge L. (Houston,
TX) |
Assignee: |
Baker Oil Tools, Inc. (Los
Angeles, CA)
|
Family
ID: |
26957667 |
Appl.
No.: |
05/475,427 |
Filed: |
June 3, 1974 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
|
275911 |
Jul 28, 1972 |
3830295 |
|
|
|
243806 |
Apr 13, 1972 |
3771603 |
|
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Current U.S.
Class: |
166/129; 166/182;
166/189; 166/237 |
Current CPC
Class: |
E21B
23/06 (20130101); E21B 43/10 (20130101); E21B
33/1295 (20130101); E21B 33/122 (20130101); E21B
2200/04 (20200501) |
Current International
Class: |
E21B
33/12 (20060101); E21B 23/06 (20060101); E21B
23/00 (20060101); E21B 43/02 (20060101); E21B
43/10 (20060101); E21B 33/1295 (20060101); E21B
33/122 (20060101); E21B 34/00 (20060101); E21b
023/00 () |
Field of
Search: |
;166/123,124,125,181,182,212,237,189 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Leppink; James A.
Attorney, Agent or Firm: Kriegel; Bernard
Parent Case Text
This application is a division of application Ser. No. 275,911,
filed July 28, 1972, now U.S. Pat. No. 3,830,295 which is a
division of application Ser. No. 243,806, filed Apr. 13, 1972., now
U.S. Pat. No. 3,771,603.
Claims
I claim:
1. In a retrieving tool for releasing a tubing hanger from anchored
engagement in well casing and removing said tubing hanger from the
well casing, said tubing hanger having a key slot for orienting the
retrieving tool, a receptacle for the retrieving tool, a shoulder,
and a flow passage leading into the tubing hanger at an off-center
location, said retrieving tool comprising: an elongated tubular
body having means at its upper end for connecting to a pipe string,
a flow passage extending longitudinally in said body from said
upper end, passage forming means carried by said body in off-center
relation and having a passage communicating with said passage in
said body, key means projecting laterally from said body and
engageable in the key-slot in said tubing hanger for orienting said
passage forming means with the flow passage in the tubing hanger,
and latch means carried by said body and engageable with said
shoulder of said tubing hanger to connect said body to said tubing
hanger.
2. In a retrieving tool as defined in claim 1, said body having a
radial port leading between said passage in said body and the
exterior of said body at longitudinally spaced locations, valve
means normally closing said ports and shiftable to establish
communication between said ports, and means on said body between
said ports for forming a seal with the casing.
3. In a retrieving tool as defined in claim 1, said body having a
radial port leading between said passage in said body and the
exterior of said body at longitudinally spaced locations, valve
means normally closing said ports and shiftable to establish
communication between said ports, and means on said body between
said ports for forming a seal with the casing, said valve means
including a sleeve longitudinally shiftable in said passage in said
body, and means for shifting said sleeve.
4. In a retrieving tool as defined in claim 1, said body having a
radial port leading between said passage in said body and the
exterior of said body at longitudinally spaced locations, valve
means normally closing said ports and shiftable to establish
communication between said ports, and means on said body between
said ports forming a seal with casing, said valve means including a
sleeve longitudinally shiftable in said passage in said body, and
means for shifting said sleeve including a seat on said sleeve for
engagement by a seating element carried in fluid flowing through
said passage in said body for closing the same to move said sleeve
responsive to the pressure of said fluid.
5. In a retrieving tool as defined in claim 1, said body having a
radial port leading between said passage in said body and the
exterior of said body at longitudinally spaced locations, valve
means normally closing said ports and shiftable to establish
communication between said ports, and means on said body between
said ports for forming a seal with the casing, said valve means
including a sleeve longitudinally shiftable in said passage in said
body, and means for shifting said sleeve including a seat on said
sleeve for engagement by a seating element carried in fluid flowing
through said passage in said body for closing the same to move said
sleeve responsive to the pressure of said fluid, said sleeve and
said body having means defining a normally closed by-pass passage
for interconnecting said ports.
6. In a retrieving tool as defined in claim 1, said body having a
radial port leading between said passage in said body and the
exterior of said body at longitudinally spaced locations, valve
means normally closing said ports and shiftable to establish
communication between said ports, and means on said body between
said ports for forming a seal with the casing, said valve means
including a sleeve longitudinally shiftable in said passage in said
body, and means for shifting said sleeve including a seat on said
sleeve for engagement by a seating element carried in fluid flowing
through said passage in said body for closing the same to move said
sleeve responsive to the pressure of said fluid, said sleeve and
said body having means defining a normally closed by-pass passage
for interconnecting said ports, said sleeve and said body also
having passage means to allow flow of fluid through said passage in
said body following movement of said sleeve.
7. In a retrieving tool as defined in claim 1, said body having
means for forming a seal with the casing, normally closed by-pass
passage means leading from above to below said means for forming a
seal, valve means normally closing said by-pass passage, and means
for opening said valve means.
8. In a retrieving tool as defined in claim 1, said latch means
comprising resilient latch fingers engageable with said shoulder,
and holding means shiftable on said body into engagement with said
fingers to hold the latter in engagement with said shoulder.
9. In a retrieving tool as defined in claim 1, said latch means
comprising resilient latch fingers engageable with said shoulder,
and holding means shiftable on said body into engagement with said
fingers to hold the latter in engagement with said shoulder
including a threaded member on said body, said key means engaging
said threaded member to hold the latter against rotation when said
body is rotated by said pipe string.
10. In a retrieving tool as defined in claim 1, said latch means
comprising resilient latch fingers engageable with said shoulder,
and holding means shiftable on said body into engagement with said
fingers to hold the latter in engagement with said shoulder
including a threaded member on said body, said key means engaging
said threaded member to hold the latter against rotation when said
body is rotated by said pipe string, said latch finger having lugs
projecting therefrom beneath said shoulder, spring means normally
biasing said latch fingers downwardly and shifting said lugs away
from said shoulder, said holding means engaging said lugs to shift
said fingers upwardly to effect engagement of said lugs with said
shoulder.
11. In a retrieving tool as defined in claim 1, said latch means
comprising resilient latch fingers engageable with said shoulder,
and holding means shiftable on said body into engagement with said
fingers to hold the latter in engagement with said shoulder, said
body having means for forming a seal with the casing, normally
closed by-pass passage means leading from above to below said means
for forming a seal, valve means normally closing said by-pass
passage, and means for opening said valve means.
Description
The present invention relates to tools for releasing and retrieving
tubing hangers, and the like, anchored in well casing disposed in
well bores, and more particularly to releasing and retrieving tools
used in connection with tubing hangers having a plurality of
longitudinal passages through which well production from a
plurality of formation zones may be conducted to the top of the
well bore, or to a location above the well bore.
As set forth in applicant's copending U.S. application Ser. No.
275,911, filed July 28, 1972, a tubing hanger is provided which
supports a plurality of production tubing strings depending
therefrom, such strings appropriately communicating with a
plurality of production zones in the well bore. The tubing hanger
has seats for removable safety valves that control fluid flow
through the production tubing strings.
The present invention involves an improved tubing hanger releasing
and retrieving tool attachable to a running string, and lowered to
a tubing hanger secured in a subsurface casing, the tool being
oriented by the tubing hanger to a predetermined position and
latched to the tubing hanger to effect its release. Manipulation of
the tool by the running string prevents its unlatching from the
tubing hanger, insuring that an upward pull on the running string
and tool with appropriate force will effect release of the tubing
hanger from the well casing, permitting the running string and tool
to retrieve the hanger from the well casing.
More specifically, the releasing and retrieving tool is used with a
tubing hanger having a plurality of longitudinal fluid passages,
the tool being capable of orientation relation to the fluid
passages to permit fluid flow between the tool and hanger passages,
the tool becoming latched to the tubing hanger, its subsequent
manipulation preventing its release from the hanger, enabling a
longitudinal pull to be taken on the tool and hanger to thereby
release the hanger from the casing. More specifically, the tool is
rotated by a running string secured thereto to prevent release of
its latching mechanism from the hanger.
A further objective of the invention is to provide a releasing and
retrieving tool for a tubing hanger secured in a well casing, in
which the tool is coupled to the hanger, which is then released
from the casing by taking an upward pull on the hanger transmitted
from the running string through the tool attached thereto to the
hanger, a cushioning device being provided to absorb the energy
stored in the running string by restricting upward acceleration of
the tool and hanger following its sudden release from the casing.
In a more limited sense, the cushioning device takes advantage of
the liquid column in the casing above the tool when it has been
coupled to the tubing hanger. The tool can be conditioned, after
release of the hanger from the casing, to permit fluid in the
casing to by-pass or equalize around the tool, in order to permit
ready upward movement of the tool and released hanger through the
casing.
This invention possesses many other advantages, and has other
purposes which may be made more clearly apparent from a
consideration of a form in which it may be embodied. This form is
shown in the drawings accompanying and forming part of the present
specification. It will now be described in detail for the purpose
of illustrating the general principles of the invention; but it is
to be understood that such detailed description is not to be taken
in a limiting sense.
Referring to the drawings:
FIG. 1 is a diagrammatic illustration showing dual safety valve
apparatus installed in a tubing hanger anchored in a well casing
extending through vertically spaced productive well zones which are
isolated from one another by packers, and fromwhich well fluids are
produced through a pair of production tubing strings;
FIG. 2 is a fragmentary detailed view illustrating the tubing
hanger set in the well casing by a setting tool;
FIG. 3 is an enlarged horizontal section as taken on the line 3--3
of FIG. 2;
FIGS. 4a, 4b, 4c and 4d together constitute a longitudinal section
through the tubing hanger and setting tool, as taken on the line
4--4 of FIG. 3, with certain of the parts shown in elevation, FIGS.
4b through 4d, respectively, constituting successive downward
continuations of FIGS. 4a, and shown prior to setting of the tubing
hanger in the well casing;
FIGS. 5a, 5b and 5c together constitute a longitudinal section
generally corresponding to FIGS. 4a through 4d, FIGS. 5b and 5c,
respectively, constituting successive downward continuations of
FIG. 5a and showing the tubing hanger set in the well casing and
also showing the setting tool released from the tubing hanger;
FIG. 6 is a horizontal section as taken on the line 6--6 of FIG.
4b;
FIG. 7 is a horizontal section as taken on the line 7--7 of FIG.
4c;
FIG. 8 is a horizontal section as taken on the line 8--8 of FIG.
4c;
FIG. 9 is a horizontal section as taken on the line 9--9 of FIG.
4d;
FIG. 10 is a fragmentary vertical section as taken on the line
10--10 of FIG. 9;
FIGS. 11a, 11b, 11c and 11d together constitute a view generally in
elevation, but with certain parts broken away, showing the
subsurface valve assembly landed in the tubing hanger, FIGS. 11b
through 11d, respectively, constituting successive downward
continuations of FIG. 11a;
FIG. 12 is a view partly in elevation and partly in section as
taken on the line 12--12 of FIG. 11d;
FIG. 13 is a horizontal section as taken on the line 13--of FIG.
11b;
FIG. 14 is a horizontal section as taken on the line 14--of FIG.
11d;
FIG. 15 is a horizontal section as taken on the line 15--15 of FIG.
11d;
FIG. 16 is a horizontal section as taken on the line 16--16 of FIG.
11a;
FIG. 17 is a horizontal section as taken on the line 17--17 of FIG.
11b;
FIGS. 18a and 18b together constitute a vertical section through
one of the subsurface valve assemblies, as taken on the line 18--18
of FIG. 16, FIG. 18b constituting a downward continuation of FIG.
18a, and the valve being shown in the normally closed
condition;
FIGS. 19a and 19b together constitute a view generally
corresponding to FIGS. 18a and 18b, showing the valve assembly in
the open condition;
FIG. 20 is a vertical section as taken on the line 20--20 of FIG.
18a;
FIG. 21 is a horizontal section as taken on the line 21--21 of FIG.
18a;
FIG. 22 is a fragmentary horizontal section as taken on the line
22--22 of FIG. 18b;
FIG. 23 is a fragmentary vertical section as taken on the line
23--23 of FIG. 16;
FIG. 24 is an exploded detail view in perspective, showing a
typical ball valve and a removable side closure and valve
supporting member;
FIG. 25 is a fragmentary detailed view partly in elevation and
partly in section showing the ball valve in a closed position;
FIG. 26 is a view generally corresponding to FIG. 25, but showing
the ball valve shifted longitudinally downwardly from engagement
with the resilient seal but prior to rotation towards the open
position;
FIG. 27 is a view corresponding to FIGS. 25 and 26, showing the
ball valve rotated towards an open position;
FIG. 28 is a view corresponding to FIGS. 25 through 27, but showing
the ball valve in the full open position;
FIGS. 29a, 29b, 29c and 29d together constitute a view, partly in
vertical section and partly in elevation, showing a tubing hanger
retrieving tool landed in the set tubing hanger, FIGS. 29b through
29d, respectively, constituting downward continuations of FIG.
29a;
FIG. 30 is a horizontal section as taken on the line 30--30 of FIG.
29a; and
FIGS. 31a, 31b, 31c and 31d together constitute a view, partly in
vertical section and partly in elevation, showing the retrieving
tool locked in engagement with the tubing hanger and showing the
tubing hanger released from the well casing, FIGS. 31b through 31d,
respectively, constituting successive downward continuations of
FIG. 31a.
As seen in the drawings, referring first to FIG. 1, a well bore W
extends downwardly into the earth below the ocean floor F through
vertically spaced well fluid producing zones Z1 and Z2. A casing C
is set in the well bore and perforations P in the casing establish
communication between the productive zones Z1 and Z2 and the casing
C. Set in the casing C is an upper packer P1 located above the
productive zone Z1 and a lower packer P2 located in the casing
between the productive zones Z1 and Z2. A first production tubing
string T1 extends through the packer P1 and opens into the casing
therebelow to communicate with the productive zone Z1, and a second
production tubing string T2 extends downwardly through the upper
packer P1 and downwardly through the lower packer P2 into the
casing therebelow for communication with the productive zone Z2.
The tubing strings T1 and T2 may extend a number of thousands of
feet downwardly in the casing to the packers P1 and P2 and the
tubing strings T1 and T2 are supported by tubing hanger means TH
which is set or anchored in the well casing and forms a seat for a
shutoff valve assembly V which comprises dual shutoff valves V1 and
V2 for the respective tubing strings T1 and T2. The tubing hanger
TH and the valve assembly V are located below the ocean floor or
the mud line of a body of water, at a desired or required depth of
say 500 to 1,000 feet, more or less. The casing C extends upwardly
through the water to a production platform or barge PP, as shown in
the diagrammatic illustration. However, as is well known, the well
may be completed at the ocean floor and one or a number of
additional casings (not shown) may be set in larger diameter well
bores, and the casing C may be suspended or hung from a casing
hanger located at the ocean floor, in which case, a conductor pipe
or other casing (not shown) may extend to the production platform
PP. In any event, upper production fluid tubings T3 and T4 extend
upwardly from the respective valves V1 and V2 of the valve assembly
V and are connected with the usual Christmas Trees CT on the
platform PP whereby the flow of well fluids from the well zones Z1
and Z2 may be controlled or manually shut off. Flow lines FL are
provided to conduct well fluids from the Christmas Trees to
suitable reservoirs or tanks (not shown).
The respective subsurface valves V1 and V2, which are normally
closed, are adapted to be held open, to enable the flow of
production fluids therethrough, by means of control fluid pressure
supplied through a control fluid conduit CF, or through a pair of
such conduits, from a source of control fluid pressure CP. So long
as the control fluid pressure is adequate to maintain the
subsurface valves V1 and V2 open, well fluids may flow from the
zones Z1 and Z2 to the respective flow lines FL, but, if it is
desired for any reason to close either of the shutoff valves V1 or
V2, or in the event of damage of the control fluid tubing, the
control fluid pressure may be reduced so that the subsurface valves
V1 and V2 are automatically closed, thereby shutting the well in at
a location below the ocean floor, to prevent continued production
fluid flow.
As will be later described, the tubing hanger assembly TH and the
tubing strings T1 and T2 are adapted to be lowered from the
platform PP downwardly through the casing C on a setting tool ST,
as seen in FIG. 2, and the valve assembly V is thereafter adapted
to be lowered through the casing C into the tubing hanger TH on the
upper tubing strings T3 and T4. Likewise, the valve assembly V can
be retrieved from the tubing hanger TH, so that under normal
circumstances requiring repair or service of the subsurface valve
assembly V, it is not necessary to pull the entire dual tubing
strings T1 and T2, as has heretofore been the practice. Since only
the comparatively short upper tubing strings T3 and T4 need be
pulled from the well to remove the valve assembly V, and the
substantially longer tubing strings T1 and T2 remain in the well,
the platform PP need not be equipped with or supplied with
high-powered hoisting apparatus. Instead, the platform PP may
simply be provided with a small low-powered hoist mechanism or a
gin pole hoist. In addition, the tubing strings T1 and T2 can be
plugged off at or below the tubing hanger TH to enable the service
or repair of the valves V1 and V2 without requiring that the well
be killed.
As seen in FIGS. 2 through 5c, the tubing hanger TH comprises a
body section 10 having an upwardly extended tubular guide secton
11, the upper end edge 12 of which is arched downwardly from a peak
13, in opposite directions, to a vertically extended slot 14 at the
side of the guide section 11 diametrically opposite the peak 13.
Internally of the guide section 11, between the lower end of the
slot 14 and the body section 10, is a thread 15 to which the
setting tool ST is connected, as will be later described. Below the
internal thread 15, is an internal flange 16 which provides a
downwardly facing shoulder 17, for purposes also to be later
described.
Extending downwardly into the body section 10 from the guide
section 11, are a pair of diametrically spaced fluid passages 18,
18 at the upper end of each of which is a cylindrical receptacle or
socket 19. At the lower end of the body section 10, a pair of
tubular members 20 are threadedly engaged in a bore 21 in
communication with the respective body passages 18, 18. Also, at
diametrically spaced locations, the body section 10 has a pair of
bores 22 in which the upper ends 23 of tie rods 24 are disposed.
Each of these tie rods 24 has a socket 25 in its upper end 23
adapted to receive the reduced lower end 26 of a setting tool
connector rod 27, the reduced end 26 being connected to the tie
rods 24 by shear pins 28. At the lower end of each bore 22 is a
resilient split lock ring 29 having external, upwardly facing
buttress threads 30 loosely fitting within complemental buttress
threads 31 in an enlarged bore in the body section 10. The lock
ring 29 has internal upwardly facing smaller threads 32 engageable
by external threads 33 on the tie rods 24, as seen in FIG. 5b,
when, as will later be described, the tie rods 24 are pulled
upwardly. The tie rods 24 extend downwardly through normally
retracted but outwardly expansible anchor means 34, and, at their
lower ends, the rods 24 are releasably connected by a frangible
connector screw 35 to a lower end or body member 36 of the tubing
hanger assembly. The frangible connector screw 35 has a reduced
frangible section 37 and a threaded end 38 engageble in the lower
end member 36, as well as an upper threaded end 39 connected to the
threaded lower end 40 of the rod 24 by an internally threaded
connector sleeve 41. The pair of tubular members 20, previously
referred to, also extend slidably downwardly through a split collar
36a (FIG. 29d) carried by the lower body 36 and have threaded lower
ends 42 adapted for connection with the respective tubing strings
T1 and T2.
The anchor means 34, as seen in FIGS. 4c, 5c and 8, comprises an
upper expander member 43 having longitudinally extended openings 44
at opposite sides thereof to accommodate the tubular conduit
members 20, as well as elongated openings 45 to accommodate the tie
rods 24. The expander member 43 is connected to the tubing hanger
body 10 for limited relative axial movement by a sleeve 43a which
is threaded on the expander member 43, at 43b, and slidably extends
onto the lower end of the tubing hanger body 10. Screws 43c at
circumferentially spaced locations, as seen in FIG. 7, extend
through elongated slots 43d in the sleeve 43a and are threaded into
the body 10. Connected to the upper expander member 43 are opposed
pairs of expansible, casing engaging slip elements 46, 46 and 47,
47, respectively, disposed at opposite sides of the expander memer
43. The slip elements 46 and 47 are so constructed as to engage the
casing over a substantial portion of the surrounding casing and
have vertically spaced sets of teeth or wickers 48 adapted to
anchor in the casing responsive to outward expansion of the slip
elements 46 and 47.
As best seen in FIGS. 4c and 8, the upper expander member 43, at
opposite sides thereof, has upwardly and outwardly inclined wedge
surfaces 46a and 46b, in vertically spaced relation thereon, and at
opposite sides of the expander surfaces are suitable elongated
slots 51 adapted to receive marginal inturned flanges 52 on the
slip elements 46, as best seen in FIG. 8, whereby the slip elements
46 are retained in assembly with the expander member 43. The bores
44 for the tubular members 20 interrupt the expander surfaces 46a,
46b and the inner face of the slip elements 46 are recessed at 50
to accommodate peripheral portions of the tubular members 20, so
that the latter may be of a larger diameter. The expander member 43
also has opposed upwardly and outwardly inclined expander surfaces
47a and 47b, and opposed T-slots 54 which receive correspondingly
T-shaped portions 55 of the slip elements 47 whereby these slip
elements are also connected to the upper expander member 43. The
expander surfaces 47a, 47b are interrupted by the bores 45 which
accommodate the connector rods 34, and the T-shaped portions 55 of
the slip elements 47 are longitudinally recessed to receive
peripheral portions of the connector rods 24.
At their lower ends, the slip elements 46 and 47 are connected to a
lower expander member 56 having upwardly and inwardly inclined
expander surfaces, such as the expander surfaces designated 46c and
47c in FIGS. 4c and 5c, for forcing the lower portions of the slips
46 and 47 toward the casing. The lower expander member 56 also has
openings 58 for the tubular conduits 20 and openings 59 for the
rods 24. It will be apparent without need of further illustration
or description that when the expander members 43 and 56 are moved
axially toward one another, the expander surfaces described above
will effect outward expansion of the slip elements 46 and 47 from
their normally retracted positions into anchoring engagement with
the casing, i.e., from the position of FIG. 4c to the position of
FIG. 5c, in which, for clarity, one of the respective slip elements
46 and 47 is illustrated in elevation. Casing engaging anchor means
of this general type are well known.
However, in the present case, the slip elements 46 and 47 are units
having the teeth or wickers formed in axially spaced locations
which are directly engaged by the respective wedge surfaces 46a,
46b and 46c and by the respective wedge surfaces 47a, 47b and 47c.
The wedge surfaces 46a and 46b and the wedge surfaces 47a and 47b
are forced downwardly by the weight of the tubing strings T1 and T2
to force the upper two sets of wickers or teeth 48 on the slip
elements or units 46 and 47 into gripping engagement with the
casing to support the tubing stringss strings and T2. In the event
that well pressure should tend to force the tubing hanger upwardly
in the well casing, say when the valves V1 and V2 are closed, the
lower set of teeth or wickers 48 on the slips 46 and 47 will be
forced outwardly by wedge or expander surfaces 46c and 47c to hold
the hanger down.
As best seen in FIG. 8, moreover, the slip elements 46 and 47 are
essentially chordal in section and the expander body 43 is
essentially square in section. The slip elements 47, at their
vertical side portions, overlap the vertical side edges of the slip
elements 46, so that, in combination, the slip elements define a
substantially circumferentially continuous anchor means, which when
set in engagement with the casing will be interruptd at the
overlapping slip portions to an extent determined by the relative
longitudinal movement between the expander body 43 and the slip
elements 46 and 47, and the angle of the wedge surfaces, to effect
anchoring engagement of the slip elements with the casing.
The setting tool means for setting the tubing hanger TH in the
casing, with the tubing strings T1 and T2 suspended thereby, is
illustrated in FIGS. 4a and 4b in the running in condition and in
FIGS. 5a and 5b in a condition for setting the tubing hanger. The
setting tool ST is adapted to be made up in an assembly with the
tubing hanger TH, before the tubing hanger is run into the well
casing, and includes an elongated tubular outer body 60 having an
external thread 61 engageable in the internal thread 15 of the
upper section 11 of the tubing hanger TH. At its upper end, the
setting tool body 60 is threadedly connected at 62 to a connector
sub 63 which in turn is threadedly connected at 64 to the lower end
of a running-in string of pipe R, whereby the setting tool ST with
the tubing hanger TH connected thereto may be lowered into the well
casing. Reciprocably disposed within the setting tool body 60 is an
inner tubular body 65. Connected to the outer body 60 is an annular
piston 66 which seats on an upwardly facing shoulder 67 and has an
inner skirt 68 extending downwardly about the inner body 65 to a
position below a suitable number of radial ports 69 in the body 65.
Seal ring means 70 are disposed between the skirt 68 and the body
65, and the annular piston 66 has inner sealing ring means 71 and
outer sealing ring means 72, respectively, engaged with the inner
body 65 and with the outer body 60. Above the annular piston 66,
the inner body 65 has a collar 73 provided with a suitable number
of radial ports 74, and an upper annular piston 75 has an internal
flange 76 which seats on the collar 73 and is retained in place by
an upper, inner body section 65a which is threadedly connected at
77 to the inner body 65, and which extends upwardly through the
outer body 60 and into the connector sub 63. The upper piston 75
has inner sealing ring means 78 and outer sealing ring means 79
sealingly engaged with the collar 73 and with the outer body 60.
Accordingly, there is defined between the inner and outer bodies 65
and 60 and the lower and upper pistons 66 and 75, an annular
pressure chamber 80 with which the ports 74 communicate.
The upper inner body section 65a is provided with resilient collett
fingers 81 spaced circumferentially therein and having lower latch
lugs 82 initially held in latching engagement beneath an inner
shoulder 82a on an outer body member 83 which is threadedly
connected at 83a within the outer body 60. The collett fingers 81
cooperate with body locking means 84 at the lower end of the inner
setting tool body 65 to hold the setting tool bodies 60 and 65 in
an initial telescopically contracted condition. The body lock means
84, as seen in FIG. 4b, comprises a resilient lock ring 85 having
external buttress teeth 86 engageable with complemental teeth 87
within a bore 88 in a lower body member 89 which is threaded at 90
to the lower end of the inner body 65. The lock ring 85 has inner
and smaller buttress teeth 91 adapted to engage complemental teeth
92 on the upper end of the connector rod 27 when the latter is
forced axially into the lock ring 85 upon assembly of the setting
tool with the tubing hanger. The inner body member 89 also has a
pair of flow tubes 93 threadedly engaged, as at 94, in
diametrically spaced bores 95 in the body member 89 and
communicating with a central bore 96, which in turn communicates
with the tubular body 65. The flow tubes 93 have lower end sealing
portions 97 having sealing rings 98 engageable in the diametrically
opposed receptacles or bores 19 in the tubing hanger body 10,
previously described, whereby fluid may be circulated downwardly
through the running-in string of pipe R. The outer setting tool
body 60 has an elongated vertical slot 100 which receives the head
of a key in the form of a screw 101 which is threaded into the
inner body member 89, whereby rotation of the running-in string R
is transmitted to the body 60.
The ports 74 leading to the pressure chamber 80 are initially
closed by an inner sleeve 105 which has vertically spaced seals 106
and 107 straddling the ports 74 to initially close the same. Above
the seal 107, the sleeve 105 has a number of radial ports 108
adapted to communicate with the pressure chamber ports 74, upon
downward movement of the sleeve 105, to the position shown in FIG.
5a, when a ball 109 is introduced into the fluid stream and engages
the seat 110 in the sleeve 105 so that fluid pressure shifts the
sleeve 105 downwardly. The sleeve 105 extends upwardly, initially,
past the lower ends of the collett fingers 81 and normally holds
the latter in latching engagement with the flange 83, as shown in
FIG. 4a, until the sleeve 105 is shifted downwardly to release the
collett latch fingers 81.
From the foregoing, it will be understood that the tubing hanger
assembly TH is run into the well casing on the setting tool ST.
When it is desired to set the tubing hanger in the casing, the ball
109 is dropped onto the sleeve seat 110, and the application of
fluid pressure will force the sleeve 105 downwardly to the position
of FIG. 5a, at which the sleeve ports 108 and the pressure chamber
ports 74 are in registry. Fluid pressure is then applied in the
pressure chamber 80 between the annular pistons 66 and 75 to
telescopically extend the setting tool bodies 60 and 65, which have
beeen released for extension when the upper end of the sleeve 105
clears the collett fingers 81 so that they may flex inwardly.
Accordingly, a downward force is applied through the piston 66 to
the outer setting tool body 60 which is transmitted to the tubing
hanger body section 11. An upward force is applied to the inner
setting tool body 65 by the piston 75 and this upward force is
transmitted through the connecting rods 27 to the tie rods 24.
Since the tie rods 24, as previously described, are connected to
the lower end member 36 of the tubing hanger assembly, the latter
is pulled upwardly while the tubing hanger body 10 is pushed
downwardly, and the expander members 43 and 56 of the tubing hanger
are corespondingly moved towards one another to force the slip
elements 46 and 47 outwardly into anchoring engagement with the
casing. When the slip elements are fully set and anchored so that
no further telescopic contraction of the setting tool is permitted,
the shear pins 28, which connect the connector rods 27 to the tie
rods 24, will be broken, as seen in FIG. 5b, and the inner setting
tool body 65 and its connected member 89 are then free to move
upwardly, clearing the flow tubes 93 from the tubing hanger, so
that the setting tool assembly is then free for rotation. The
running-in string R is then rotated to release the thread 61 on the
outer setting tool body 60 from the inner tubing hanger thread 15,
as will be apparent.
Means are incorporated in the tubing hanger assembly to maintain a
force which tends to urge the expanders 43 and 56 towards one
another, such a means is best seen in FIGS. 9 and 10, as comprising
a suitable number of angularly spaced spring means 115. More
particularly, at each location a bolt 116 is threaded at 117 into
the lower end of the lower expander member 56 and extends
downwardly, slidably, through holes 118 in the lower end member 36,
the bolt heads 119 shouldering at 120 to retain the member 36 in
assembly. Interposed between the lower end member 36 and the
expander 56 is a stack of Belville washers 121 adapted to exert
substantial force tending to spread the members 36 and 56 apart. As
previously indicated and as seen in FIG. 4d, for example, the tie
rods 24 are also connected to the lower member 36, and when the tie
rods 24 move upwardly, the teeth 33 thereon (FIG. 4c) will move
into engagement with the lock ring 29 (FIG. 5b) so that the force
of the Belville washers 121 is applied downwardly to the upper
expander 43 and upwardly to the lower expander 56. The Belville
washers 121 are compressed during setting of the tubing hanger to
the extent determined by the movement of an outer sleeve 122
carried on the lower body member 36 and movable upwardly relative
to the expander member 56 into engagement with a downward facing
shoulder 123, as the anchor means 34 are being set.
When the setting tool has been removed from the well casing, the
tubing hanger assembly is then in condition to receive the dual
valve assembly V, as seen in FIGS. 11a through 11d.
The dual valve assembly V, as previously indicated, comprises, in
the illustrated embodiment, a pair of valves V1 and V2, since the
apparatus is shown as applied to producing from a pair of well
zones Z1 and Z2, but it will be understood that the invention is
applicable, also, to the production from more than two well
zones.
At its lower end, as seen in FIGS. 11d and 12, the valve assembly V
is adapted to be received in the upper tubing hanger body section
11 and to be latched in place by releasable latch means 125 beneath
the internal flange 16 in the hanger body section 10. At
diametrically spaced locations in a cross-head 126 of the latch
means 125, the latch means 125 has elongated laterally opening
spaces 127, 127 accommodating flow tubes 128 and 129 which are
respectively adapted to establish communication between the tubing
strings T1 and T2 and the valve assemblies V1 and V2,
respectively.
At their lower ends, the flow tubes 128 and 129 have sealing end
portions 130 and 131, respectively, each having sealing ring menas
132 engageable within the bores or receptacles 19 in the tubing
hanger body 10. The flow tube 128 extends upwardly from the
cross-head 126 and is connected at 133 to a length of tubing 134
which extends further upwardly a suitable distance, and is
connected at 135 to the housing 136 of the upper valve assembly V1,
which will be hereinafter described. The flow tube 129 also extends
upwardly from the cross-head 126 and is connected at 137 to the
valve assembly V2, which is spaced vertically downwardly from the
valve assembly V1 to enable utilization of valve assemblies V1 and
V2 having full bore flow passages, as will also be later described.
Extending upwardly from the valve housing 138 through swivel means
139 is a rotatable tubular member 140 which is connected at its
upper end by a coupling 141 to the tubing string T4 above the
connection of the tubing string T3 to the valve assembly V1, as
seen in FIG. 11a. Rotation of the tubing string T4 and, thus, the
tubular member 140 is utilized to engage and release the latch
means 125 when the valve assembly V is run into the tubing hanger
TH.
The flow tubes are retained in parallel, assembled relation by a
vertically split body 142 comprising opposed half sections 143 and
144, as seen in FIG. 15, clamped together by fasteners 145. The
body sections 143, 144 have internal grooves 146 which receive
annular ribs 147 on the flow tubes 128, 129 to hold the latter
against relative axial movement.
When the valve assembly V is being lowered into the tubing hanger
TH, a key 148 on one side of the assembly, shown on the flow tube
129, and engageable with peak 13 of the hanger body section 11 will
cause rotation of the valve assembly V, as the key 148 rides
downwardly on the inclined surface 12 and is guided into the
vertical slot 14, whereby the lower ends 130, 131 of the flow tubes
128, 129 will be properly positioned or oriented so as to be
stabbed into the bores or receptacles 19 in the hanger body 11.
The latch means 125 referred to above, comprises a plurality of
resilient, normally retracted collett fingers 150 depending from
the cross-head 126 and having outwardly projecting latch lugs 151
at their lower ends. The lower ends of the latch fingers 150 are
expansible outwardly by a wedge surface 152 on the split body 142
when the cross-head 126 is moved downwardly relative to the body
142, from the position of FIG. 11d to the position of FIG. 12.
Means 155 are provided for normally holding the latch fingers 150
in the retrated positions, and spring means 156 are provided for
actuating the cross-head 126 downwardly to cam the fingers 150
outwardly.
More particularly, a pair of bolts 157 extend through the
cross-head 126 and have their heads 158 engageable beneath the
cross-head 126 to hold the latter in an upper position, as seen in
FIG. 11d. These bolts 157 are threaded into a plate 159 which is
connected to a pull rod 160, the pull rod extending upwardly
alongside the length of tubing 134 and being connected, as seen in
FIG. 11b, to a non-rotatable nut 161, having a notch 162 for
straddling the tubing 134 to prevent rotation of the nut. The nut
161 has a threaded bore 163, in which a complemental thread 164 on
the rotatable tubing section 140 is engaged. Accordingly, when the
tubing string T4, which, as previously indicated, is connected to
the tubing section 140, is rotated the nut 161 is moved axially on
the tubing section 140, downwardly, from the position of FIG. 11b,
to allow downward movement of the plate 159 and the bolts 157.
The spring means 156 are operable to force the crosshead 126
downwardly and comprises a pair of coiled compression springs 165
disposed about the bolts 157 and seating at their lower ends in
bores 166 in the cross-head 126 and at their upper ends against a
spring seating plate 167 which abuts beneath the lower valve
housing 138. When the cross-head 126 is moved downwardly by the
springs 166, the lugs 151 on the latch fingers 150 are cammed by
the cam surface 152, outwardly for engagement beneath the latch
shoulder 17 of the tubing hanger body section 11.
As seen in FIGS. 11a through 11d, the control fluid conduit CF is
connected by a fitting 170 to the upper valve housing 136 of the
valve V1 and passage means 171 in the housing 136 conduct control
fluid to an outlet fitting 172 which is connected to a conduit 173
leading to an inlet fitting 174 for the lower valve V2. However, if
preferred, plural control fluid tubings CF may be employed to
supply control fluid pressure to the valves V1 and V2.
The fluid pressure responsive shutoff valve V1 is representative of
the two valves V1 and V2 and will now be described. The valve
structure is the subject matter of the companion application for
U.S. Pat., Ser. No. 275,910, filed July 28, 1972. a, T3. threadedly
threadedly
In this form, as seen in FIGS. 11a, 11b, 18a, 18b and 19a, 19b, the
valve assembly comprises the outer body 136 and an upper tubular
sub 136a which is connected with the lower end of the tubing string
73. The upper body 136a is theadedly connected at 175 at its lower
end to the body 136, which, in turn, as previously described, is
theadedly connected at 135 to the flow tube 134 which seats in one
of the bores or receptacles 19 in the tubing hanger body 10.
A ball valve 176 is disposed within the body 136 and has a passage
177 for the flow of well fluid when the ball valve is in the open
position, with the passage 177 aligned with the body 136, the ball
valve being rotatable 90.degree., as will be later described, to a
closed position, in which flow of well fluid through the body 136
is prevented.
Normally, the ball valve 176 is biased to a closed position by a
lower sealing and actuating sleeve 178 which is reciprocable in the
valve body 136 between an upper position, as seen in FIG. 18a, and
a lower position, as seen in FIG. 19a. The sleeve 178 is piloted in
a reduced bore 179 in the body 136, and the lower end of the sleeve
extends into a bore 180 in the upper end of the tube 134. A coiled
compression 181 is disposed between the upper end of the tube 134
and a seating shoulder or ring 182 on the sleeve 178, and biases
the sleeve 178 and the ball valve 176 upwardly. Externally, the
ball valve 176 has a spherical sealing surface 183 sealingly
engageable by a companion sealing end surface 184 at the upper end
of the sleeve 178.
Above the ball valve 176 is an upper valve actuating and sealing
sleeve 185 having a lower end sealing surface 186 which is
complemental to the spherical valve surface 183 of the ball valve
176. At its upper end, the sleeve 185 has an enlarged piston
section 187 which is slidably disposed within a cylinder portion
188 of the valve body 136. Below the piston section 187 is a
cylindrical section 189 smaller than the outside diameter of the
piston section 187. Between the cylindrical section 189 and the
cylindrical wall 188 is a sleeve 190 engaged by an external seal
ring 191 on the cylindrical section 189 and having an external seal
192 engaging with the cylinder wall 188. At its lower end, the
sleeve 190 abuts with an upwardly facing shoulder 193. The
difference between the annular cross-sectional area of the sleeve
190 and the annular cross-sectional end area of the upper end 194
of the piston section 187 constitutes the net piston area of the
piston section 187 exposed, as will be later described, to control
flud pressure to hold the ball valve 176 open. The piston section
187 extends into an annular space 195 defined between the
cylindrical wall 188 and a sleeve 196 which is connected by
suitable shear screws 197 to a skirt 198 on the lower end of the
upper body section 136a, the sleeve 196 carrying a seal ring 199
engageable within the skirt 198, and the skirt 198 having a seal
ring 200 engageable in the cylindrical wall 188. The control fluid
passage 171, previously referred to, communicates through a port
201 with the annular space 195 which constitutes a control fluid
pressure chamber in which control fluid pressure is operable on the
net piston area of the piston section 187 of the sleeve 185 to
provide a downward force adapted to overcome the upward force
applied to the ball valve 176 by the lower valve actuating sleeve
178, when the ball valve 176 is to be opened by moving the ball
valve from the position of FIG. 18b, to the position of FIG. 19b,
as the upper sleeve 185 is forced downwardly.
Preferably, the valve assembly includes resilient sealing means 202
engageable with the ball valve 176 when it is in the closed
position. In the embodiment now being described, the resilient
sealing means 202 comprises a seal carrier ring 203 having an
annular elastomeric seal ring 204 engageable with the ball valve
176 externally of the seating surface 186 at the lower end of the
sleeve 185. The seal carrier ring 203 is normally biased downwardly
by a coiled compression spring 205 which seats against a seating
ring 206 carried within the valve body 136.
The respective valve assemblies V1 and V2 are full opening valve
assemblies through which remedial operations can be performed when
the ball valve is opened. In order to provide a ball valve 176 of
maximum diameter, the ball valve 176 is installed in the body 136
through a side opening 207 which is closed by a valve supporting
closure member 208 which fits within the opening 207, and is sealed
therein by a suitable seal ring 209. Referring again to FIG. 11b,
it will be noted that the closure and valve support member 208 is
adapted to be secured to the valve body 136 by a suitable number of
fasteners 210, and as best seen in FIG. 17, the closure member 208
includes a guide section 211 having a bore 212 through which the
tubular member 140 rotatably extends.
In order to support the ball valve 176 and cause rotation thereof
in response to movement of the ball longitudinally between the
sleeves 185 and 178, the valve supporting member 208 has a pin or
lug 213 projectng therefrom in aligned opposition to a
corresponding pin or lug 214 carried within the valve body 136, and
the ball valve 176 has at its opposite sides corresponding slots
215 in which the respective pins or lugs 213 and 214 are engageable
for rotating the ball valve 176 between the opened and closed
positions, as best illustrated in FIGS. 25 through 28. In these
views, the side of the ball valve 176 supported by the closure 208
is illustrated, but similar structure will be understood to be
located at the other side of the ball valve also. In FIG. 25, the
valve is shown fully closed and sealed by the sleeves 178 and 185
as well as by the resilient sealing means 202. In FIG. 26, the
valve 176 has been shifted downwardly away from the resilient seal
means 202 through an initial increment of non-rotatable
longitudinal movement. In FIG. 27, the ball valve 176 is in the
partially opened position. In FIG. 28, the ball valve 176 is in the
fully opened position.
More particularly, the ball valve member 176 on each of its
opposite sides has a chordal flat surface 216 adjacent to the
diametrically opposite portions of the body 136 and the support
208. The slot 215 extends radially with respect to the axis of
rotation to the ball valve member 176, and at right-angularly
spaced locations, the ball face 216 is recessed to form a stop
surface 217 and a stop surface 218 cooperable with fixed stop lug
surfaces 217a and 218a on the closure 208 to limit rotation of the
ball 176 between the extremes of FIG. 25 and FIG. 28. When the ball
valve member 176 is in the position of FIG. 25, the stop surface
217 engages the vertical stop surface 217a, thereby limiting
rotation of the valve member 176 to the position at which the valve
is open. The stop surface 218 engages the stop surface 218a, as
shown in FIG. 28 to limit rotation of the valve member 176 to the
position at which the valve is closed. Such rotation between the
open and closed positions is caused by longitudinal or vertical
movement of the valve member 176 relative to the body 136. As
previously indicated, the ball member 176 is actuated or shifted
longitudinally by longitudinal movement of the upper actuator
sleeve 185 and the lower actuator sleeve 178, as indicated by the
arrows in FIGS. 26 and 27. The slot 215 is formed in such a manner
as to cause such rotation of the valve member 176 as the latter
moves vertically or longitudinally within the body 136. Thus, as
seen in FIG. 25, the slot 215 is formed in the valve member 176 by
opposed walls which are disposed at a right angle to one another
and designated 215a and 215b and which respectively are parallel to
the stop surfaces 217a and 217b. At the apex of the angle defined
between the walls 215a and 215b, the slot opens radially inwardly
at 215c. Thus, the relationship between the pin 213 and the wall
215b is such that the ball valve 176 will be rotated from the
position of FIG. 25 to the position of FIG. 28 when the valve
member 176 moves downwardly relative to the pin 213, and
conversely, the flat wall 215a will engage the pin 213 and rotate
the ball valve member from the position of FIG. 28 to the position
of FIG. 25 upon upward movement of the valve member 176. However,
it will be noted that when the valve member 176 is in the position
of FIG. 28, the pin 213 clears the flat wall 215a so as to allow
freedom of longitudinally movement of the ball valve 176 after the
stop surface 218 engages the stop 218a, and correspondingly limited
free downward movement of the ball valve 176 is permitted when the
ball valve is open, as seen in FIG. 25, where the pin 213 clears
the slot wall 215a, and the stop surface 217 engages the stop 217a.
Such free or lost motion connection of the ball valve 176 and the
rotating pin 213 relieves the connection of damaging forces when
the ball valve is in either of its closed or opened positions, and
in addition saves the resilient seal 202 from relative rotative
movement of the ball valve 176.
When the ball valve 176 is closed and is to be opened by applying
control fluid pressure to the piston chamber 195, there may be
substantial differential pressure across the valve tending to hold
it closed, and in order to equalize the pressure across the valve,
equalizing valve means 220 are provided, as seen in FIG. 23, for
establishing communication between a port 221 below the ball valve
176 (FIG. 18b) and a port 228 above the valve 176 (FIG. 18a), via
the elongated passage 223 in the valve body 136. The port 221
communicates with the annular space 224 between the body 136 and
the lower valve actuating sleeve 178 which communicates with the
passage through the tubular member 134 through radial ports 225 in
the upper end of the member 134, when the valve 176 is closed, as
seen in FIG. 18b. Above the ball valve 176, the skirt 198 of the
upper valve body section 136a has a number of radial ports 226
communicating between the flow passage through the valve assembly
and an annulus 227 which in turn commicates through a port 228 with
a chamber 229 of the equalizing valve means 220. The equalizing
valve chamber 229 is provided by a tubular insert 230 retained in a
bore 231 in the body 136 by a sealing plug 232. Seals 233 and 234
on the insert 230 engage in the bore 231 and a reduced bore 235. A
valve member 236 is reciprocable in the insert 230 and has its
lower end 237 provided with a seal 238 slidably engaging within the
insert 230 below inlet ports 239 in the insert which establish
communication between the port 228 and the valve chamber 229, so
that above the seal 238, the chamber 229 is exposed to the flow
passage through the upper valve body 136a. At the upper end of the
equalizing valve member 236 is a head 240 engageable with a seat
241 under the influence of pressure below the ball valve 176
supplied to an inlet chamber 242, above the head 240, via the
passage 223 and via a radial port 243 in the body 136 and ports 244
in the insert 230. A rod 245 slidably extends downwardly through
the lower end of the insert 230 and into the bore 235, and a coiled
spring 246 engages the insert 230 and an adjustable spring seat 247
on the rod to provide a downward bias closing the head 240 against
the seat 241. Leading into the bore 235 of the equalizing valve 220
is a port 248 which communicates with the control fluid chamber 195
of the shutoff valve means.
It will now be apparent that so long as the pressure differential
across the closed ball valve 176 is such that well pressure in the
equalizing valve chamber 242 and the force of spring 246 cause a
downward force holding the valve head 240 seated, in excess of the
force upwardly caused by control fluid pressure in the bore 235,
there will be no communication between the ports 221 and 228,
respectively, below and above the ball valve 176. However, as
control fluid pressure is increased to open the shutoff valve 176,
the increased pressure acts upwardly on the effective piston area
at the lower end of the equalizing valve member 236 and will open
the equalizing valve head 240, whereby pressure will equalize
between the lower ports 221, through passage 223, ports 243 and
244, valve chambers 242 and 229, ports 239, and the upper
equalizing port 228.
The effective areas in the equalizing valve means 220 and the force
of the spring 246 are selected, as compared with the effective area
of the shutoff valve actuating piston section 187 of the sleeve
185, so that the equalizing valve means 220 will open first, and
thereby relieve the main shutoff valve 176 from the effect of
differential pressure thereacross.
In order to assure that no back flow can occur when the shutoff
valve 176 is open and the well is flowing therethrough, a back flow
preventing valve 223a is provided between the equalizing valve
chamber 242 and the passage 223.
In order to enable control fluid pressure to be supplied to both of
the valve assemblies V1 and V2 in the valve means V, as previously
indicated, the control fluid pressure chamber or bore 235 of the
equalizing valve means 220 of the upper valve V1 has a passage 235a
leading to the fitting 172, which in turn communicates with the
lower valve assembly V2.
In the use of shutoff valves, such as the valve assembly V1 or V2,
to control flow from a plurality of well zones, it may occur, under
various circumstances, such as seal failure, that one or more of
the shutoff valves will not open under applied control fluid
pressure. In such event, it may be necessary to pull the shutoff
valve means from the well in order to repair and replace the
shutoff valve means. In the present apparatus, however, means are
provided whereby the valve V1 or the valve V2 may be opened
mechanically and locked open to allow continued production from one
or both of the well zones Z1 and Z2. In addition, the present
apparatus enables the use of an auxiliary or secondary shutoff
valve, adapted to be run into and anchored in the locked open valve
assembly V1 or V2.
As seen in FIGS. 18a and 18b, the sleeve 196 is held by the shear
screws 197 in an initial upper position, and the sleeve 196
cooperates with the body 136 to form the control fluid pressure
chamber or annular space 195. Initially released lock means 250 are
provided, whereby, when the sleeve 196 is shifted downwardly, it
will be locked in the lower position. When the sleeve 196 is
shifted downwardly, it engages a shoulder 251 on the sleeve 185 and
shifts the latter downwardly to open the ball valve 176. More
particularly, the lock means 250 includes a resiliently
contractable, split lock ring 252 having external upwardly facing
buttress teeth 253. Beneath the lock ring 252 is an expander 254
which is secured to the sleeve 196 by fasteners 255 and has an
expander surface 256 engageable within the lock ring 250 to expand
the latter when it is lockingly engaged with internal teeth 257
within the body 136. A sleeve shifting tool is disclosed and
claimed in the companion application for U.S. Pat. Ser. No.
275,910, filed July 28, 1972.
As previously described, the valve assembly V may be removed from
the tubing hanger assembly TH and thereafter, the tubing hanger and
the tubing strings T1 and T2 may be removed from the well by the
use of the retrieving tool RT, shown in FIGS. 29a to 29d, as being
landed and latched into the upper end section 11 of the tubing
hanger assembly TH, the retrieving tool RT being operable, as shown
in FIGS. 31a through 31d, to release the tubing hanger TH so that
it may be removed from the well.
More particularly, the retrieving tool RT comprises an elongated
body 400 threadedly connected at 401, at its upper end, to a
running-in string of pipe R2. At its lower end, the body 400 has an
annular carrier 402 rotatably mounted thereon by ball bearing means
403, the carrier supporting a pair of inserts 404 providing flow
passages 405 and adapted to be sealingly engaged within the
respective receptacles or bores 19 in the tubing hanger body 10,
whereby fluid may be circulated downwardly through the running-in
string R2 and the retrieving tool body 400, into the tubing strings
T1 and T2. The carrier 402 has an upwardly extending neck 406
rotatably receiving the lower end of the body 400. Suitably keyed
to the neck 406, as by a screw 407 extending into a longitudinal
slot 408 in the neck 406, is a retainer sleeve 409 which is
threaded at 410 onto the body 400. The retainer sleeve 409, above
the threaded connection 410, is provided with a vertically extended
slot 411 into which projects a key 412 which is carried by the
solid ring portion 413 of a latch sleeve 414 connected at 415 to a
support ring 416 suspended from a flange 417 of a ring supporting
member 418 threaded onto the body 400 at 419. The latch sleeve 414
comprises a plurality of downwardly extended and circumferentially
spaced resilient latch fingers 420 having outstanding lugs 421 at
their lower ends adapted to be engaged beneath the flange 16 within
the body section 11 of the tubing hanger TH. The inner side of each
lug 421 has a vertically extended face 422 engageable, upon
actuation of the retrieving tool RT, by a companion vertical face
423 on the latch retainer 409. Above the carrier ring 416 is a
spring seating ring 424 engaged by a coiled compression spring 425
which at its upper end engages a collar 426 secured by fasteners
427 to a support ring 428. The collar 426 has a plurality of radial
ports 429 communicating with an annulus 430 between the collar 426
and the body 400, the annulus 430 communicating with ports 431 in
the body 400. The ports 431 lead into the body 400, but are
normally closed by a sealing sleeve 432 having an upper seal 433
and a lower seal 434 engaged within the body 400 and straddling the
ports 431. This sealing sleeve 432 is initially held in the
position shown in FIG. 29a by one or more shear screws 435, and the
sleeve 432 extends upwardly within the body 400 to a location above
an upper set of radial ports 436 located below a seal ring 437
carried by the sealing sleeve 432 and engaged within the body 400.
Between the seals 433 and 437 on the sealing sleeve 432, the
extension of the sealing sleeve is longitudinally grooved, as at
438, so that when the sleeve is shifted downwardly to the position
of FIGS. 31a communication is established between the lower ports
431 and the upper ports 436.
The sleeve 432 is shifted downwardly, as mentioned above, by means
of fluid pressure, when a ball 439 introduced into the running
string R2 engages an upper seat 440 on the sleeve 432 to close the
central passage through the sleeve. when the sleeve 432 is shifted
When the upper end thereof which carries an outer ring seal 441 is
disposed within an enlarged bore portion 442, which establishes
communication between the running pipe string R2 and the interior
of the sealing sleeve 432 via ports 443 adjacent the upper end of
the sleeve 432.
Seating on the support ring 428 is a packer cup supporting ring 444
which supports an upwardly facing packing cup 445 having a sealing
lip 446 engageable with the well casing C. When the retrieving tool
RT is in the condition shown in FIGS. 29a and 29b, the annular
space between the running string R2 and the tool body 400, above
the packing cup 445, may be filled with fluid to apply a downward
force opposing the release of the tubing hanger, but after the
tubing hanger has been released, the ball 439 may be inserted into
the running string R2 to shift the sealing sleeve 432 downwardly to
the position shown in FIGS. 31a through 31d to equalize the fluid
across the packing cup 445.
To release the tubing hanger assembly TH, the retrieving tool RT is
run into the well casing, and the key 412 will engage the
downwardly inclined upper face 12 of the tubing hanger body section
11 and be cammed into the vertical slot 14, thereby orienting the
sealing inserts 404 with the receptacles or sockets 19 in the
tubing body 10. Thereafter, rotation of the running string R2 will
effect corresponding rotation of the retrieving tool body 400
relative to the carrier ring 402 which is held stationary by the
sealing inserts engaged in the receptacles 19. The body 400 also
rotates relative to the key 412 which is held non-rotatable in the
tubing hanger slot 14 and thus holds the retainer sleeve 409
against rotation with the body 400, so that the retainer sleeve 409
will be threaded upwardly along the threaded connection 410 until
the retaining surface 423 thereon engages within the vertical
surface 422 on the latch lugs 421, as shown in FIG. 31b, thereby
retaining the resilient latch fingers 420 against inward
deflection, so that the latch lugs 421 are positively held
outwardly for engagement beneath the tubing hanger body flange
16.
Thereupon the running string R2 is pulled upwardly to apply an
upward pull to the tubing hanger body 10 tending to pull the upper
expander member 43 upwardly to release the slip elements 46 and 47,
but release of the slip elements is initially precluded, inasmuch
as the tie rods 24 engaged in the lock ring 29, as shown in FIG.
31c, are positively interconnected with the lower tubing hanger
member 36, so that, as previously described, the anchor means 34
are retained in anchoring engagement with the casing C. However,
sufficient upward strain on the running string R2 will cause the
reduced section 37 of the frangible screw 35 to be broken, as shown
in FIG. 31d, allowing the upper expander member 43 to move upwardly
with respect to the lower expander 56, and the slip elements 46 and
47 will be retracted. Since fracturing of the screw 35 results in
the instantaneous release of the anchor means while the running
string R2 is under substantial tension, the fluid column supported
in the annulus above the packing cup 445 constitues a cushion which
will absorb the energy stored in the running string R2. When the
ball 439 is dropped through the running string R2 and the sealing
sleeve 430 is shifted downwardly, as described above, to equalize
the fluid across the packing cup 435, the tubing hanger assembly
can then be elevated through the well casing by the retrieving tool
RT, and the tubing strings T1 and T2 pulled from the well.
* * * * *