Note: Descriptions are shown in the official language in which they were submitted.
CA 02229198 1998-02-10
TU1BING HANGER TO PERMIT AXIAL TUBING DISPLACEMENT
IN A WELL BORE AND METHOD OF USING SAME
TECHNICAL FIELD
This invention relates generally to wellhead
equipment and, in particular, to an apparatus and method
for axially displacing tubing string in a cased well
having a wellhead.
:LO BACKGROUND OF THE INVENTION
In a cased well equipped with a wellhead,
tubing strings are supported by a tubing hanger which is
in turn supported by a tubing head in a manner well known
in the art. Tubing heads are generally mounted to a
L5 surface flange of the cased well.. The tubing hanger is
received in the tubing head and locked in position by
lock-dawn screws to ensure that the tubing hanger is not
ejected from the tubing head if the well is subjected to
significant fluid pressure. The tubing string is
20 genera.Lly suspended by threaded attachment to the tubing
hanger. The position of a bottom end of the tubing
string is therefore fixed and determined by the length of
the string. In order to change a position of the bottom
end of the tubing string, a complicated process must be
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CA 02229198 2001-04-18
tubing hanger. Before the wellhead can be removed, it is
usually necessary to "kill" the well by overburdening any
natural pressure to ensure that hydrocarbons do not
escape from the well when the wellhead is removed.
Operations such as killing a well and removing a wellhead
require considerable time and generally involve the use
of a derrick or a rig in order to handle components and
ensure safety. Such operations therefore require the
engagement of complex equipment and skilled labour which
involves considerable expense.
It is therefore desirable to provide a method
and apparatus to permit the axial displacement of a
tubing string in a cased well bore without removal of the
wellhead or necessity for killing the well. One such
apparatus is described in applicant's Canadian Patent
No. 2,216,668 entitled TELESCOPING JOINT FOR USE IN A
CONDUIT CONNECTED TO A WELLHEAD AND ZONE ISOLATING TOOL
FOR USE THEREWITH which was filed on 7 October 1997 and
issued on December 26, 2000. An apparatus for use in
moving tubing connected to the telescoping joint was
described in applicant's copending application
No. 2,223,214 entitled APPARATUS FOR AXIALLY DISPLACING A
DOWNHOLE TOOL OR A TUBING STRING IN A WELL BORE which was
filed on 17 December 1997, and laid open to public
inspection on May 27, 1999.
- 2 -
CA 02229198 2001-04-18
Although the telescoping joint described above
greatly facilitates certain downhole operations, the
axial displacement of a tubing string which may be
achieved using the telescoping joint is limited by a
length of the telescoping joints) in the tubing string.
While that limited range of axial displacement is
adequate for most downhole operations that require
displacement of a bottom end of the tubing string, it is
sometimes desirable to be able to displace the bottom end
of the tubing string over a greater distance than is
economically afforded by a telescoping joint(s).
There therefore exists a need for an apparatus
and method which permits axial displacement of a tubing
string in a cased well bore over a range which is
practically limited only by the length of the tubing
string itself.
SZJI~1ARY OF THE INVENTION
It is therefore an object of the invention to
provide a tubing hanger for enabling the axial
displacement of a tubing string in a well bore without
removing the wellhead from the well.
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CA 02229198 1998-02-10
It is a further object of the invention to
provide a tubing hanger to permit axial displacement of
the tubing string through the wellhead.
It is yet a further obj ect of the invention to
provide a method of axially displacing a tubing string in
a cased well bore without removing a wellhead from the
well.
It is yet a further obj ect of the invention to
provide a method and a tubing hanger for facilitating
7.0 downhol.e operations which involve axial displacement of a
tubing string in a well bore.
The objects of the invention are enabled by a
hanger for a tubing string in a cased well equipped with
a wellhead, to permit axial displacement of the tubing
=_5 string up through the wellhead, comprising:
a first hanger part engageable with the wellhead for
detachably supporting a second hanger part:
tree second hanger part being' adapted for hanging the
tubing string and sized to be stroked up through a
?0 central passage in the wellhead with the tubing string
attached; and
a fluid seal located between the first and second
hanger parts to inhibit a flow of fluids therebetween
when the first hanger part supports the second hanger
?5 part.
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CA 02229198 1998-02-10
The objects of the invention are further
enabled by a method of axially displacing a tubing string
in a cased well bore without removing a wellhead from the
well, comprising the steps of:
a) equipping the wellhead with a tubing hanger
which _Lncludes at least a first hanger part supported by
the wellhead and a second hanger part supported by the
first hanger part, the second hanger part supporting the
tubing string and sized to be stroked up through a
7_0 centra7_ passage of the wellhead;
b) inserting a latch for connecting to the second
hanger part or the tubing string through the well_head,
and connecting the latch to the tubing string or the
second hanger party and
.L5 c) stroking the second hanger part of the tubing
hanger and a portion of the tubing string through the
wellhead.
The invention therefore provides a novel
construction for a tubing hanger which permits axial
~?0 tubing displacement in a well bore and a method of using
the tubing hanger to perform downhole operations which
require or are facilitated by, axial displacement of the
tubing string. Such operations include the logging of a
well bore; the positioning of a zone isolating tool to
:?5 select_Lvely produce a fluid of interest from a well bore;
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CA 02229198 1998-02-10
the removal of debris such as sand from a bottom of the
well bore; selective stimulation of a production zone
using <~ zone isolating tool; the removal of paraffin or
hydrates from a portion of the bore; or any other
downhole operation in which a tubing string is
advantageously axially displaced to enable or facilitate
a downhole operation.
The tubing hanger in accordance with the
invention comprises at least a first hanger part
hereinafter referred to as the primary tubing hanger
component, and a second hanger part, hereinafter referred
to as i~he secondary tubing hanger component. The primary
tubing hanger component is supported by a tubing head in
a manner well known in the art. The secondary tubing
.L5 hanger component is preferably supported in a cavity
formed in the primary tubing hanger component. Lock
means are provided between the primary and secondary
tubing hanger components to ensure that the secondary
tubing hanger component cannot be ejected from wells
~?0 having high natural pressure or high induced pressure. A
fluid seal is provided between the first and second
tubing hanger components to inhibit the migration of
fluids between the components. The fluid seal is
preferably carried in grooves formed in an outer surface
:?5 of the secondary tubing hanger component.
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CA 02229198 1998-02-10
The secondary tubing hanger component supports
the tubing string, preferably by threaded connection.
The secondary tubing hanger component is sized to enable
it to be stroked up through a central passage in the
wellhead.
The tubing hanger in accordance with the
invention can be manufactured to fit most commercially
available tubing heads.
=_0 BRIEF DESCRIPTION OF THE DRAWINGS
The invention will now be further explained by
way of example only and with reference to the following
drawings wherein:
Fig. 1 is a cross-sectional view of a first
.L5 embodiment of a tubing hanger in accordance with the
invent~_on supported in a tubing head mounted to a surface
flange of a cased well;
Fig. 2 is a cross-sectional view of a second
embodirlent of a tubing hanger in accordance with the
20 invent__on supported by a tubing head mounted to a surface
flange of a cased well;
Fig. 3 is a perspective view of a J-latch
preferably used to lock the secondary tubing hanger
component within the primary tubing hanger component of a
25 tubing hanger in accordance with the invention; and
CA 02229198 1998-02-10
Fig. 4 is a cross-sectional view of a cased
well equipped with a tubing hanger in accordance with the
invention and a lifting apparatus preferably used for
axially displacing the tubing string within the cased
well bore.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
Fig. 1 is a cross-sectional view of a tubing
hanger in accordance with the invention, generally
7_0 indicated by the reference 10. The tubing hanger 10
includes a first hanger part which is referred to below
as the primary tubing hanger component 12 and a second
hanger part which is referred to below as the secondary
tubing hanger component 14. The primary tubing hanger
._5 component 12 is substantially frustoconical and has a top
end 16 and a bottom end 18. A cavity 20 is formed in the
top end 16 of the primary tubing hanger component 12. A
passage 22 is formed through the bottom end 18 of the
primary tubing hanger component 12. The passage 22 is
20 sized to permit a tubing string 24 to reciprocate
therethrough. The primary tubing hanger 12 is supported
by a tubing head generally indicated by the reference 26.
The tubing head 26 includes a bottom flange 28, a top
flange 30 and an internal passage 32. The internal
25 passage 32 may include seals or stops not shown in this
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CA 02229198 1998-02-10
drawing- but well known in the art. The top flange 30
generally includes a plurality of lock-down screws 34.
The lock-down screws 34 engage a bevelled shoulder 36 of
the pr_Lmary tubing hanger component 12. This locks the
primary tubing hanger component 12 within the tubing
head 2E~ to ensure that it is not ejected by fluid
pressure in the well bore. Lock-down screws 34 also
frequently serve the purpose of energizing fluid seals.
The tubing head 26 is usually mounted to a casing head 38
7_0 that =_s schematically illustrated in cross-sectional
view. The casing head 38 is connected to the casing 40
of the cased well bore. Components such as a bit guide,
etc. standard in wellhead constructions are not
illustrated.
7_5 As described above, the secondary tubing hanger
component 14 is received in the cavity 20 formed in the
top surface 16 of the primary tubing hanger 12. The
shape of the cavity 20 and the shape of the secondary
tubing hanger component 14 are matters of design choice.
20 It is only important that the secondary tubing hanger
component 14 be robust enough to support the tubing
string 24 while being sized to enable the secondary
tubing hanger component 14 to be stroked through a
centra=_ passage of the wellhead (not illustrated).
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CA 02229198 1998-02-10
Fluid seals are provided between the tubing
head 2Ei and the primary tubing hanger component 12, as
well as between the primary tubing hanger component 12
and the secondary tubing hanger component 14. The
position and composition of the fluid seals are partially
dependent on matters of design choice and partially
dependent on fluid pressure and fluid composition in the
well bore. The embodiments shown in Fig. 1 have fluid
seals ~!2 to inhibit the flow of fluids from the annulus
7_0 of cas~_ng 40 between the primary tubing hanger 12 and the
tubing head 26. The fluid seals 42 are typically an
elastomeric composition compatible with the composition
and the pressure in the well bore. For high-pressure
applications, metal-to-metal seals may also be used. As
._5 will be understood by those skilled in the art, the fluid
seals may be borne by the tubing head 26, the primary
tubing component 12, or both.
Fluid seals 43 inhibit a flow of fluids from
the annulus of the casing 40 between the primary tubing
~?0 hanger component 12 and the secondary tubing hanger
component 14. The composition, structure and position of
the fluid seals 43 are likewise dependent on a
combination of design choice and the pressure and
compos~_tion of the fluids in the well bore. The design
~?5 and se:Lection of such fluid seals are well understood in
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CA 02229198 1998-02-10
the art and will not be further explained for that
reason.
The secondary tubing hanger component 14 is
preferably locked in the cavity 20 of the primary tubing
hanger component 12 to ensure that it is not ejected by
fluid pressure in the well. The mechanism for locking
the secondary tubing hanger component 14 in the cavity 20
is a matter of design choice. In the preferred
embodiment of the invention, the lock is provided by an
7_0 opposed pair of locking pins 44 which are received in
complimentary J-shaped slots 46. The slots 46 in
combination with the locking pins 44 provide a J-latch,
well known in the art. As will be understood by persons
skilled in the art, the pins 44 may be mounted to either
7_5 of the secondary tubing hanger component 14 or the
primary tubing hanger component 12 and the J-shaped
slots 46 can be formed in the other of the two
components. Other lock-down arrangements can also be
used. For example, the secondary tubing hanger
20 component 14 and the primary tubing hanger component 12
may be complimentarily threaded so that they are locked
together by threaded engagement. As another example,
threaded lock-down screws which extend through the tubing
head 2Ei and the primary tubing hanger component 12 may be
25 used to lock the secondary tubing hanger component in the
- 11 -
CA 02229198 1998-02-10
cavity 20. As will be understood by those skilled in the
art, a collet, slip, or key-type connection may also be
used to lock together the primary tubing hanger
component 12 and the secondary tubing hanger
component 14. If the tubing hanger 10 in accordance with
the invention is to be used in wells with little or no
natural. pressure, the weight of the tubing string 24 may
be adequate to retain the secondary tubing hanger
component 14 within the cavity 20, but a positive lock
J_0 mechanism is preferred.
Fig. 2 shows a second configuration for the
tubing hanger 10 in accordance with the invention. In
this embodiment, the primary tubing hanger component 12
is substantially cylindrical rather than substantially
~_5 frustoc:onical. The primary tubing hanger component 12 is
retained in the tubing head 26 by an internal shoulder 48
which is typically inclined at 45°. This embodiment of
the tubing hanger 10 is designed for high-pressure
applications. The primary tubing hanger component 12 has
?0 an external sleeve 50 which compresses a fluid seal 52
against. a wall of the internal passage 32 of the tubing
head 26, in a manner well known in the art. The fluid
seal 52 may be an elastomer band or the like.
A further feature of the embodiment shown in
25 Fig. 2 is that fluid seals 54 seal the passage 22 to
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CA 02229198 1998-02-10
contain fluid pressure in the annulus of the casing 40
while the tubing string 24 is being stroked out of the
well, as will be explained below in more detail with
reference to Fig. 4. In other respects, the embodiment
shown in Fig. 2 is substantially the same as the
embodiment described above with reference to Fig. 1.
Fig. 3 shows a perspective view of the J-shaped
slot 4Ei of the J-latch preferably used to lock the
secondary tubing hanger component 14 within the cavity 20
7_0 of the primary tubing hanger component 12. As described
above, the J-shaped slots 46 may be machined in either
the primary tubing hanger component 12 (see Fig. 1) or
the secondary tubing hanger component 14 (see Fig. 2).
The shape of the J-shaped slot 46 is also a matter of
.L5 design choice, as will be well understood by those
skilled in the art. As described above, the secondary
tubing hanger component 14 may also be secured within the
cavity 20 of the primary tubing hanger component 12 using
other securing mechanisms, including a collet or slip-
20 type connector; a threaded connection; a key-type
connect=or or lock-down screws, which are not illustrated
but are respectively well known in the art.
As explained above, the axial displacement of a
tubing string in a well bore permits or facilitates
25 various downhole operations including: well completion;
- 13 -
CA 02229198 2001-04-18
well bore workovers; well abandonments; wirelining for
logging or the like; drilling for barefoot completions or
the like; production testing using zone isolation tools
or the like; and, any other downhole process in which
axial displacement of a tubing string is desirable or
necessary.
In order to axially displace the tubing string
within the well bore, a rig or a derrick may be used but
the operation is most economically and preferably
accomplished using the apparatus described in applicant's
copending application entitled APPARATUS FOR AXIALLY
DISPLACING A DOWNHOLE TOOL OR TUBING STRING IN A WELL
BORE which was filed on 17 December 1997, and laid oopen
to public inspection on May 27, 1999.
Fig. 4 is a schematic cross-sectional view of
that apparatus being used to axially displace tubing
string 24 in the casing 40. The tubing string 24
supports a zone isolating tool 54 described in
applicant's Canadian patent entitled TELESCOPING JOINT
FOR USE IN A CONDUIT CONNECTED TO A WELLHEAD AND ZONE
ISOLATING TOOL FOR USE THEREWITH issued December 26,
2000. Zone isolating tool 54 is used to selectively
produce oil, for example, from a production zone which
produces oil 56, gas 58 and water 60. The apparatus
generally indicated by reference 62 is used to stroke the
secondary tubing component 14 and the tubing string 24
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CA 02229198 2001-04-18
through a wellhead 64 without removal of the wellhead or
killing the well. As explained in applicant's copending
application, the motive force for stroking the secondary
tubing hanger component 14 and the tubing string 24
through the wellhead 64 is a hydraulic cylinder or
jack 66 which is mounted to an upper support plate 70.
The upper support plate 70 is supported by support
posts 72. The support posts 72 are connected to a lower
support plate 74. A travelling support plate 76 slides
over and is guided by the support posts 72. A hydraulic
motor 78 mounted to the travelling support plate 76
rotates a lift rod string 80. Attached to a free end of
the lift rod string 80 is a latch 82 which is used to
connect the lift rod string 80 to the secondary tubing
hanger component 14 or the tubing string 24. The lift
apparatus 62 further includes a pair of blowout
preventers 84 and a tool entry spool 86.
The tubing string 24 used with the tubing
hanger in accordance with the invention is preferably a
flush joint tubing manufactured by Atlas Bradford and
available from most oil well equipment suppliers. The
use of flush joint tubing is not required if the
passage 22 (Figs. 1,2) in the primary tubing hanger
component 12 is large enough to permit joints in the
tubing string 24 to reciprocate through the opening.
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CA 02229198 1998-02-10
In preparing to axially displace the tubing
string 24, a first step is to position a plug 86 in the
tubing string at a position below the last joint to be
removed from the tubing string 24. The plug 86 may be
inserted using the lift rod string 80. After the plug 86
is inserted, the latch 82 is connected to the lift rod
string 80 and the lift rod string 80 is stroked down
through the lift apparatus 62, the wellhead 64 and
connected to the secondary tubing hanger component 14 or
J_0 the ini~erior of the tubing string 24 below the secondary
tubing hanger component 14. After a connection is made,
the secondary tubing hanger component 14 is released from
the primary tubing hanger component 12 by operating the
hydraulic motor 78 to rotate the lift rod string 80. The
7_5 amount of rotation will depend on the type of latch
mechanism used to secure the secondary tubing hanger
component 14 in the cavity 20 of the primary tubing
hanger component 12 (Figs. 1,2). After the secondary
tubing hanger component 14 is released from the primary
20 tubing hanger component 12, the secondary tubing hanger
component 14 is stroked up through the wellhead and the
BOPS 8~1. As will be understood by those skilled in the
art, the BOPS 84 are opened in sequence to permit the
secondary tubing hanger component 14 to be stroked out
- 16 -
CA 02229198 1998-02-10
without: losing well pressure or permitting hydrocarbons
to escape to the atmosphere.
After the secondary tubing hanger component 14
is stroked up through the upper blowout preventer 84, the
tubing string is stroked up through the wellhead until a
first t=ubing string joint appears in a tool window 88 of
the lift apparatus 62. The tubing string 24 can then be
gripped through the tool window 88, which permits the
joint to be unscrewed and the joint removed. The
7.0 latch E~2 is then reconnected to the tubing string 24 and
a next joint is stroked out through the well. Depending
on the joint design, it may be necessary to operate the
blowout: preventers 84 to let the joints pass through.
This process is repeated until the tubing string 24 has
7_5 been shortened a desired amount. If the tubing string
need to be lengthened, a reverse of this procedure is
followed.
As will be understood by those skilled in the
art, the length of support posts 72 must be adequate to
20 permit a joint of tubing string 24 to be added or removed
from the tubing string when the lifting apparatus 62 is
used for tubing string displacement. Consequently, for
wells where tubing string displacement is anticipated a
plurality of "pup" joints having a length of 1-2 metres,
25 for example, can be placed in the tubing string at the
- 17 -
CA 02229198 1998-02-10
top of the well to facilitate displacement and minimize
the length required in the support posts 72.
As described above, the tubing hanger in
accordance with the invention can be used for any
downhol.e operation in which the position of the tubing
string is advantageously or necessarily changed. Those
downhol.e operations include, but are not limited to,
selective well stimulations using a zone isolating tool;
selective production using a zone isolating tool;
7_0 barefoot completions; production testing; wireline
logging; well abandonments; and the removal of sand or
debris from a bottom of the well bore.
For example, to perform a selective well
stimulation, the zone isolating tool 54 (Fig. 4) is
7_5 positioned by axially displacing the tubing string 24 so
that an area of a production zone to be stimulated is
isolated by the tool. A high-pressure base is then
connected to a top end of the tubing string and high-
pressure fluids are pumped through the tubing string and
20 into t=he isolated fluid zone provided by the zone
isolating tool 54. After stimulation of the area is
complete, the zone isolation tool 54 is relocated and the
process is repeated. Since the tubing isolates the
wellhead from the high-pressure fluids, the wellhead need
25 not be removed or otherwise protected during the
- 18 -
CA 02229198 1998-02-10
isolation procedure assuming there is an inflatable
packer, for example, between the zone isolating tool and
the wellhead. This technique also has the advantage that
selective stimulation of the zone ensures that all areas
of the zone are stimulated, in contrast to a general
stimulation treatment where one or more areas of a zone
may accept all stimulation fluids while other areas
accept none, and therefore remain unstimulated.
To perform selected production using a tubing
l_0 hanger in accordance with the invention, a zone isolating
tool 54 is attached to a bottom end of the tubing
string 24. The zone isolating tool is positioned in the
well bore by adding tubing string joints and stroking the
tubing string down through the wellhead until a position
l_5 is ach=_eved which permits the production of predominantly
a fluid of interest from the well bore. When the zone
isolating tool 54 is near the desired position, a pup
joint is added to the tubing string, if required, the
secondary tubing hanger component is added to a top of
20 the tubing string and the secondary tubing hanger
component 14 is seated in the primary tubing hanger
component 12 (Figs. 1 and 2) so that the zone isolating
tool i.s properly positioned to produce the fluid of
intere~>t from the well. As a boundary between the fluid
25 of interest and other fluids) produced by the production
- 19 -
CA 02229198 1998-02-10
zone changes over time, the positioning process may be
repeated to relocate the position of the zone isolating
tool 59: within the well bore without removing the
wellhead from the well or killing the well. The
advantage is fast and simple well servicing with minimal
equipment.
A tubing hanger in accordance with the
invention may be used for barefoot completions in a
manner described in applicant's first-filed copending
J_0 application. In order to accomplish a barefoot
completion, a well bore is first drilled to within a few
metres of a target formation. The well bore is cased and
headed and a tubing string having a drill bit attached to
its bottom end is run into the well in a manner described
7_5 above. When the drill bit contacts the bottom of the
well bore, the bit is driven to drill through the last
few metres between the bottom of the bore and the
formation. When the bore is completed, the drill bit may
be dropped in the bottom of the borehole and production
20 commenced once the bottom end of the tubing string is
repositioned and the secondary tubing hanger component 14
is attached to a top end of the tubing string and seated
in the primary tubing hanger component 12. The advantage
is the ability to perform a barefoot completion with the
- 20 -
CA 02229198 1998-02-10
wellhead on the well and fluid pressures safely
contained.
Selected production testing of a well bore may
be accomplished using a tubing hanger in accordance with
the in~;rention. In order to perform selected production
testing, a zone isolation tool 54 is connected to a
bottom end of the tubing string 24 and the zone isolating
tool 54 is lowered by stroking the tubing string down
through the wellhead until the zone isolation tool 54 is
7_0 positioned in a location of a production zone desired to
be tested. Testing may be performed by producing fluid
through the tubing string from the selected production
zone. After testing is complete, the location of the
zone isolation tool 54 is shifted to test another region
J_5 of the production zone. Such selected testing may be
used i~o determine an optimum position for a zone
isolating tool in a production zone that produces at
least i:wo fluids of different density. The advantage is
the ability to relocate the position of the zone
20 isolating tool with the wellhead in position.
When wireline logging of a well bore is
desired, the production tubing is preferably removed from
the section of the well bore which requires logging.
With prior art wellhead equipment, it is necessary to
25 kill t:he well, remove the wellhead and pull the tubing
- 21 -
CA 02229198 1998-02-10
from the well before logging can be accomplished without
interference from the tubing string. With a wellhead
equipped with a tubing hanger in accordance with the
invention, as much tubing string as required may be
stroked up through the wellhead until a bottom end of the
tubing string is above the area of the well bore to be
logged. A logging tool may then be run through the
tubing string in a manner well known in the art and
logging can be accomplished. After logging is completed,
7_0 the tubing string may be repositioned to a former or new
position within the well bore. The advantage is the
ability to log a well without removing the wellhead or
killing the well in preparation of logging.
When well bores are abandoned, well owners are
~_5 required by regulation to place cement plugs between each
of the production zones in the well. If a well is
equipped with a tubing hanger in accordance with the
invention, the tubing string can be used to place the
required cement plugs as it is withdrawn from the well
20 and the wellhead can be left in place to ensure
protect=ion against the escape of hydrocarbons into the
atmosphere.
Certain wells produce copious amounts of sand
and/or granular debris. It is a common practice in the
:?5 art in such wells to extend the well bore to form a ~~sand
- 22 -
CA 02229198 1998-02-10
trap". Sand traps commonly fill with debris which
eventually blocks the bottom end of the production tubing
and production from the well ceases. When this happens,
it is necessary to remove the accumulated debris from the
sand trap. With prior art tubing hangers the removal of
sand or debris usually requires that the well be killed,
the we.llhead removed and the tubing string pulled from
the we:l1 far enough to remove the tubing hanger. After
the tubing hanger is removed, blowout preventers are
J.0 mounted to the tubing head, one or more joints are added
to the tubing string and pumping equipment is connected
to a top of the tubing string. The tubing string is then
lowered in the well as sand and/or debris is pumped out
of the well. Once the well is cleaned, the added tubing
7_5 string joints are removed, the blowout preventers are
removed, the tubing hanger is reattached and the wellhead
is remounted to the tubing head. The overburden used to
kill the well is then removed and normal production may
resume.
20 If the wellhead is equipped with a tubing
hanger 10 in accordance with the invention, the tubing
string 24 may be stroked upwardly through the wellhead so
that 'the secondary tubing hanger component can be
removed. A tubing joints) are then added and the tubing
25 string is stroked downwardly as debris is pumped from the
- 23 -
CA 02229198 1998-02-10
sand trap until the well is cleaned of debris. The
tubing string may then be returned to a production
position and production recommenced without removing the
wellhead from the well or killing the well. Time and
expense are therefore minimized.
In view of the examples described above, it is
apparent that the tubing hanger in accordance with the
invent_Lon represents a significant advance in the art.
Changes and modifications to the embodiments
:LO described above will no doubt become apparent to those
skilled in the art. The scope of the invention is
therefore intended to be limited solely by the scope of
the appended claims.
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