U.S. patent application number 11/859617 was filed with the patent office on 2009-03-26 for tubing hanger apparatus and wellhead assembly for use in oil and gas wellheads.
Invention is credited to Douglas W. Schepp.
Application Number | 20090078404 11/859617 |
Document ID | / |
Family ID | 40470401 |
Filed Date | 2009-03-26 |
United States Patent
Application |
20090078404 |
Kind Code |
A1 |
Schepp; Douglas W. |
March 26, 2009 |
TUBING HANGER APPARATUS AND WELLHEAD ASSEMBLY FOR USE IN OIL AND
GAS WELLHEADS
Abstract
A tubing hanger apparatus includes a tubing hanger with a
plurality of segments thereon that engage an annular groove of a
tubing head thus preventing the tubing hanger from sliding down a
well. The internal diameter wellhead bore is consistent from the
master valve downward to the production casing. The tubing hanger
has a plurality of annular seals which are expandable after
insertion into the tubing head. A plurality of lock screws both
expand the seals as well as prevent any further movement of the
tubing hanger. The tubing hanger apparatus is situated below a
master valve. Thus, coiled tubing or jointed tubing can be run down
the well and landed below the master valve. The tubing hanger
contains a back pressure valve, thus the master valve can be opened
without releasing the formation pressure within the live well.
Inventors: |
Schepp; Douglas W.;
(Airdrie, CA) |
Correspondence
Address: |
LOCKE LORD BISSELL & LIDDELL LLP;ATTN: IP DOCKETING
600 TRAVIS, SUITE 3400
HOUSTON
TX
77002-3095
US
|
Family ID: |
40470401 |
Appl. No.: |
11/859617 |
Filed: |
September 21, 2007 |
Current U.S.
Class: |
166/75.14 ;
166/75.11 |
Current CPC
Class: |
E21B 33/04 20130101 |
Class at
Publication: |
166/75.14 ;
166/75.11 |
International
Class: |
E21B 19/00 20060101
E21B019/00 |
Claims
1. A tubing hanger apparatus for a wellhead, comprising: a tubing
head having a bore with a recess in the bore surface and a shoulder
protruding from the bore surface below the recess; a tubing hanger
insertable within the tubing head bore, the tubing hanger having an
upper end, a lower end, connectable to a coiled tubing or jointed
tubing string, and between the upper and lower ends: a bore contact
surface for slidably contacting the bore surface, an engagement
surface below and laterally recessed from the bore contact surface,
and an actuation surface below and laterally recessed from the bore
contact surface; an engagement segment slidable along the
engagement and actuation surfaces of the tubing hanger, an
actuation segment slidable along the actuation surface of the
tubing hanger below the engagement segment; wherein when the tubing
hanger is located in a locked position in the bore, the actuation
segment contacts the bore shoulder, the engagement segment is
located onto the engagement surface by the actuation segment and
engages the bore recess.
2. A tubing hanger apparatus as claimed in claim 1 wherein the bore
contact surface, engagement surface, and actuation surface are
annular and extend around the tubing hanger.
3. A tubing hanger apparatus as claimed in claim 2 wherein the
actuation and engagement segments are annular, and are slidable
along and surround the tubing hanger.
4. A tubing hanger apparatus as claimed in claim 3 wherein the
engagement segment is expandable, wherein the engagement segment is
in an unexpanded position when surrounding the actuation surface
and in an expanded position when surrounding the engagement
surface.
5. A tubing hanger apparatus as claimed in claim 4 wherein the
engagement segment has first and second ends facing each other.
6. A tubing hanger apparatus as claimed in claim 2 wherein the
tubing hanger further comprises: a sealing surface above and
laterally recessed from the bore contact surface; a compressible
annular seal surrounding the sealing surface such that the seal
does not protrude from the bore contact surface when uncompressed;
and a seal compressor movable between an uncompressed position
wherein the seal is uncompressed, and a compressed position wherein
the seal is compressed and protrudes beyond the bore contact
surface to contact the bore surface when the tubing hanger is
inserted inside the bore.
7. A tubing hanger apparatus wherein the seal compressor is annular
and surrounds the tubing hanger adjacent the seal, the seal
compressor being slidable along the tubing hanger between the
uncompressed and compressed positions.
8. A tubing hanger apparatus as claimed in claim 7 wherein the
tubing head further comprises a seal compressor engagement means
operable to engage the seal compressor when the tubing hanger is in
the locked position and move the seal compressor between compressed
and uncompressed positions.
9. A tubing hanger apparatus as claimed in claim 1 further
comprising a lock screw operable to engage the tubing hanger when
in the locked position.
10. A tubing hanger apparatus for a wellhead as claimed in claim 1
further comprising an annular spiral lock located on the tubing
hanger below the actuation and engagement segments and for
preventing the actuation and engagement segments from sliding off
the tubing hanger.
11. The tubing hanger apparatus for a wellhead as claimed in any of
claims 1 to 10 further comprising a master valve located above the
tubing hanger apparatus and having an internal diameter equal to or
greater than that of a production casing attached to the wellhead
without reducing the internal diameter of the tubing head.
12. A wellhead assembly comprising: a blowout preventer; an adaptor
flange connected to the blowout preventer; a master valve connected
to the adaptor flange; and a tubing hanger apparatus as claimed in
claim 1 wherein the tubing head is connected to the master
valve.
13. A wellhead assembly as claimed in claim 12 further comprising:
the addition of a swedge attached at a first end to the tubing head
and a top section attached to a second end of the swedge.
Description
FIELD OF THE INVENTION
[0001] This invention relates generally to tubing hangers for use
in oil and gas wellheads.
BACKGROUND OF THE INVENTION
[0002] Oil and gas wellheads are a combination of components that
prevent pressurized ground substances in a well from being released
above grounds. These components include valves and other components
which are manipulated to control the release of the pressurized
ground substances. The wellhead components also serve to hold a
combination of casings and tubing in a well through which the
pressurized ground substances flow. One such component, a tubing
hanger, primarily acts to suspend the weight of a production tubing
within a casing of the well. Historically, the tubing hanger is
attached to the wellhead by lock screws and additionally to the
tubing below by connectors to ensure the tubing is anchored within
the well. The casing having a larger diameter than the tubing,
serves as a cylindrical enclosure for the tubing to insert through.
Once inserted, the tubing can inject or remove the pressurized
ground substances.
[0003] Because the ground substances are pressurized, a seal is
required between the tubing hanger and a tubing head that surrounds
the tubing. This seal is conventionally provided by O ring seals
attached to the tubing hanger which engage the tubing head
surrounding the tubing hanger. Additionally, wellhead pressure is
controlled by a master valve located above or below the tubing
hanger and by a blowout preventer device which rests on top of the
wellhead and allows for an additional valve to be closed in order
to prevent an untimely explosive pressure release.
[0004] Conventionally, tubing hanger apparatuses utilize a load
shoulder within the lower portion of the tubing head on which the
tubing hanger will land when inserted into the tubing head. This
shoulder reduces the internal diameter of the tubing head to
prevent the tubing hanger from further movement down the well. The
presence of the load shoulder limits the diameter of the bore and
thus limits the width of any components needed to be lowered into
the well. As such, once the tubing head is installed on a well, the
internal diameter of any casings or other objects placed down the
well must be smaller than the internal diameter of the tubing
hanger load shoulder. This is problematic as it is limits the
further utilization of the well.
[0005] Tubing hangers used in conventional wellheads utilize O ring
seals connected to the external circumference of the tubing hanger
to provide a seal between the tubing hanger and the tubing head.
The seal is required to maintain pressure below the tubing hanger.
The O rings are pre-extruded, therefore, the external diameter of
the O ring is greater than the external diameter of the tubing
hanger body and slightly greater than the internal diameter of the
tubing head. When a tubing hanger is lowered into the tubing head,
problems may develop if the external surfaces of the O ring seal
contact other structures on the wellhead and thus possibly damage
or tear the O ring seals. Because the O ring seal extrudes from the
tubing hanger, it is prone to being caught on other wellhead
surfaces. Although care may be taken to insert the tubing hanger;
once an O ring is torn or damaged, the tubing hanger must be
removed and repaired which is both costly and timely.
[0006] In the prior art, a tubing head created by Woodgroup
Pressure Control (the "Woodgroup Tubing Head") incorporates a
tubing hanger that is held in place within the tubing head by a
load shoulder and a plurality of steel lock screws. The tubing
hanger is inserted in the tubing head and comes to rest on the load
shoulder of the tubing head. The hanger is then locked in place by
lock screws. The load shoulder included decreases the internal
diameter of the tubing head resulting in a decreased internal bore
diameter and limits the diameter of any down hole implements to be
used. Further, the Woodgroup Tubing Head utilizes pre-extruded O
ring seals that are prone to damage due to errors in tubing hanger
insertion.
[0007] In conventional oil and gas wellheads a master valve is
installed to control the release of pressurized substances within
the well. The master valve can also be opened to allow further
insertion of drilling components down the well. When tubing hangers
are connected above the master valve, coiled tubing or jointed
tubing must be inserted through the tubing hanger, master valve and
into the well. This is problematic as the coiled tubing running
through the master valve will prevent the closing of the master
valve as the valve will pinch the tubing upon closing. Further,
accidental closing of the master valve whilst inserting tubing
through the master valve will either damage the tubing or the
master valve. In addition once the tubing is being run through the
master valve there is no ability to prevent backflow without first
freezing the well.
SUMMARY OF THE INVENTION
[0008] According to one aspect of the invention, there is provided
tubing hanger apparatus for a wellhead. The apparatus comprises a
tubing head, a tubing hanger, an engagement segment, and an
actuation segment. The tubing head has a bore with a recess in the
bore surface and a shoulder protruding from the bore surface below
the recess. The tubing hanger is insertable within the tubing head
bore, and has an upper end, and a lower end connectable to a coiled
tubing or jointed tubing string. The tubing hanger also has between
the upper and lower ends: a bore contact surface for slidably
contacting the bore surface, an engagement surface below and
laterally recessed from the bore contact surface, and an actuation
surface below and laterally recessed from the bore contact surface.
The engagement segment is slidable along the engagement and
actuation surfaces of the tubing hanger. The actuation segment is
slidable along the actuation surface of the tubing hanger below the
engagement segment. The above components are arranged so that when
the tubing hanger is located in a locked position in the bore, the
actuation segment contacts the bore shoulder, the engagement
segment is located onto the engagement surface by the actuation
segment and engages the bore recess. This aspect of the invention
overcomes one prior art problem of having a narrower internal
diameter of the tubing head because of the need for wide load
shoulders. As such, a full bore wellhead can be provided without
substantially decreasing the internal diameter of the tubing head
or casing strings below it. Further, a master valve can be located
above the tubing hanger apparatus having an internal diameter equal
to or greater than that of the production casing attached to the
wellhead without reducing the internal diameter of the tubing
head.
[0009] The bore contact surface, engagement surface and actuation
surface can be annular and extend around the tubing hanger. The
actuation and engagement segments can also be annular and be
slidable along the tubing hanger. Further, the engagement segment
can be expandable wherein the engagement segment is in an
unexpanded position when surrounding the actuation surface and in
an expanded position when surrounding the engagement surface.
[0010] The tubing hanger apparatus can be further comprised of a
compressible annular seal surrounding a sealing surface that is
laterally recessed from the bore contact surface of the tubing
hanger. This compressible annular seal does not protrude from the
bore contact surface when uncompressed. A seal compressor movable
between an uncompressed position wherein the seal is uncompressed,
and a compressed position wherein the seal is compressed and
protrudes beyond the bore contact surface to contact the bore
surface when the tubing hanger is inserted inside the bore can also
be provided. The seal compressor can be annular and surrounds the
tubing hanger adjacent the seal and is slidable along the tubing
hanger between the uncompressed and compressed positions. A seal
compressor engagement means can also be provided to engage the seal
compressor when the tubing hanger is in the locked position and
move the seal compressor between compressed and uncompressed
positions.
[0011] The tubing hanger apparatus can be further equipped with a
lock screw operable to engage the tubing hanger when in the locked
position. Spiral locks can be located on the tubing hanger below
the actuation and engagement segments and prevent the actuation and
engagement segments from sliding off the tubing hanger.
[0012] In another aspect of the invention, a wellhead assembly is
provided comprising a blowout preventer, an adaptor flange
connected to the blowout preventer; a master valve connected to the
adaptor flange, and a tubing hanger apparatus wherein the tubing
head is connected to the master valve. Alternatively, the wellhead
assembly can comprise the addition of a swedge attached at a first
end to the tubing head and a top section attached to a second end
of the swedge.
[0013] Further preferred features of the invention are in the
following descriptions of illustrative embodiments.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] FIG. 1. is a side view of a conventional wellhead with a
master valve located below a tubing hanger (PRIOR ART);
[0015] FIG. 2. is a schematic cross-sectional side view of a
portion of a wellhead containing a tubing hanger secured by lock
screws (PRIOR ART);
[0016] FIG. 3. is a side cross-sectional view of a tubing hanger
apparatus according to one embodiment of the present invention and
comprising a tubing hanger in a first position inside a tubing
head;
[0017] FIG. 4. is a side cross-sectional view of the tubing hanger
apparatus comprising a tubing hanger in a second position in the
tubing head;
[0018] FIG. 5. is a side cross-sectional view of a portion of the
tubing hanger apparatus illustrating a plurality of seals not
engaged with the tubing head in the first position within the
tubing head;
[0019] FIG. 6. is an expanded side cross-sectional view of the
tubing hanger apparatus illustrating a plurality of engaged
expanded seals in the second position with the tubing head;
[0020] FIG. 7. is a side view of a portion of the tubing hanger
illustrating the annular actuation and spring loaded segments and
annular spiral locks.
[0021] FIG. 8. is an expanded side view of a portion of a wellhead
assembly with a partial cross-sectional view showing the tubing
hanger of FIG. 3 inside the wellhead, and a blowout preventer
located above the tubing hanger apparatus; and
[0022] FIG. 9. is a side view of a portion of an alternative form
of the wellhead assembly including a top portion above the tubing
hanger apparatus.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0023] The prior art as illustrated in FIG. 1 is comprised of a
portion of a wellhead assembly including a prior art tubing hanger
apparatus 2 above a master valve 4, a bell nipple 7 threadably
connected at its upper extremity to said master valve and to a
production casing 8 at its lower extremity. The master valve 4 is
attached to prevent backflow when in its closed position. When
necessary, for example, to remove liquids from the well, a coiled
tubing or jointed tubing 10 is run down the wellhead assembly and
into a well by a lubricator (not shown) and attached to the lower
extremity of the tubing hanger 11. A surface casing 6 surrounds the
production casing and coiled tubing or jointed tubing 10. Because,
the coiled tubing or jointed tubing 10 is inserted into a well
through the master valve 4, there is no ability to close the master
valve 4. As such, there is no ability to prevent backflow without
first freezing the well. In such assemblies, the master valve 4 is
tendered obsolete by the coiled tubing or jointed tubing 10 running
through it and impeding its ability to close.
[0024] FIG. 2 illustrates a portion of the Woodgroup Tubing Head
which is another type of prior art tubing hanger apparatus and
includes a means of locking a tubing hanger 11 within a tubing head
13 by utilizing lock screws 12. Further, this device includes
pre-extruded seals 9 which are susceptible to tearing upon
insertion of the tubing hanger 11 into a wellhead. When lowering
the tubing hanger 11 into the tubing head 13, the pre-extruded
seals 9 are susceptible to catching on the wellhead structures and
thus being damaged. Once damaged, the tubing hanger 11 must be
removed and repaired.
[0025] This Woodgroup Tubing Head device is designed to land the
tubing hanger 11 on a load shoulder 1 within the tubing head 13.
This load shoulder 1 engages the lower extremity of the tubing
hanger 11 thus preventing further downward movement of the tubing
hanger 11. To accomplish this, the load shoulder 1 must create a
narrower internal diameter of the tubing head 13 compared to the
internal diameter of the tubing head 13 above the load shoulder 1.
With the tubing hanger 11 having a greater external diameter than
the internal diameter of the tubing head 13 at the point of the
load shoulder 1, the tubing hanger 11 is prevented from further
downward movement. Further, the Woodgroup Tubing Head is locked in
place by lock screws 12.
[0026] Referring to FIGS. 3-7, in an embodiment of the invention, a
tubing hanger apparatus is comprised of a tubing head 14 and a
tubing hanger 16 located within a bore of the tubing head 14. The
tubing hanger 16 has an upper end and a lower end. The tubing
hanger 16 has an annular bore contact surface 70 having an outer
diameter that is slightly less than the bore diameter of the tubing
head 14 to allow the tubing hanger 16 to be lowered into the tubing
head 14 bore and be slidable therein.
[0027] Below the bore contact surface 70 is an annular engagement
surface 72 laterally recessed from the bore surface, i.e. has a
smaller diameter than the bore surface. Below the engagement
surface is an annular actuation surface 74 that is laterally
recessed from the engagement surface 72, i.e. has a smaller
diameter than the engagement surface 72. A sloped shoulder 76
connects the actuation surface 74 to the engagement surface 72.
[0028] An actuation segment 23 is annular and surrounds the tubing
hanger 16; particularly, the actuation segment 23 is slidable along
the axis of the actuation surface. A spring loaded engagement
segment 24 is annular and surrounds the tubing hanger 16.
Particularly, the engagement segment 24 is slidable along the axis
of both the actuation 74 and engagement 72 surfaces.
[0029] The actuation segment 23 is annular and has an outer surface
with a chamfer extending circumferentially along its lower edge.
The engagement segment 24 is also annular and has a chamfer
extending circumferentially along its lower and upper edges. The
engagement segment is a "c-shaped" spring loaded ring with first
and second ends facing each other. The engagement segment is biased
in unexpanded position wherein the engagement segment is in
slidable contact with the actuation surface. The engagement segment
can be expanded into an expanded position when slid onto the
engagement surface.
[0030] Specifically referring to FIGS. 3, 5 and 7, in a first
position, the tubing hanger 16 is inserted into the bore of the
tubing head 14 but has not yet engaged the tubing head 14 or come
to rest. At this point the actuation segment 23 approaches an
actuation shoulder 25 protruding from the bore surface of the
tubing head 14 and the engagement segment 24 is resting above the
actuation segment 23. The actuation shoulder 25 has sufficient
width to engage the actuation segment 23 surrounding the tubing
hanger 16 but not sufficient width to engage the tubing hanger 16
itself (because the actuation and engagement surfaces are recessed
from the bore contact surface). This actuation shoulder 25 is
unlike load shoulders 1 in the prior art in that its width is
minute when compared to load shoulders 1 and thus it does not
significantly narrow the internal diameter of the tubing bead 14.
Further, the tubing hanger 16 does not engage this actuation
shoulder 25 directly, rather, only the actuation segment 23 engages
this actuation shoulder 25.
[0031] Specifically referring to FIGS. 4 and 6, in a second
"locked" position, the lower, chamfered surface of the actuation
segment 23 engages a corresponding chamfered upper surface of the
actuation shoulder 25 located within the tubing head 14 and pushes
up the actuation segment 23 which in turn pushes up the spring
loaded segment 24 from the actuation surface, over the sloped
shoulder and onto the engagement surface to engage a groove 26 in
the tubing head 14 above the actuation shoulder 25. As discussed
above, the engagement segment expands when pushed onto the
engagement surface. The groove 26 is an annular channel or recess
with tapered side walls. When the spring loaded segment 24 is
engaged within the groove 26, the tubing hanger 16 has no ability
for downward movement. Further, downward movement of the tubing
hanger 16 is prevented by the engagement of the upper surface of
the spring loaded segment 24 and the upper surface of the groove 26
and the lower surface of the actuation segment 23 engaging the
upper surface of the actuation shoulder 25. The weight of the
production tubing below the tubing hanger 16 provides downward
force on the tubing hanger 16 due to the effect of gravity on the
production coiled tubing or jointed tubing 30.
[0032] While in the embodiment shown in the Figures the tubing
hanger 16 and bore are generally cylindrical, it is within the
scope of the invention for these components to have other shapes,
in which case the respective bore contact, engagement and actuation
surfaces would not be annular. Further, the engagement and
actuation segments do not need to be annular, and can instead,
blocks that are aligned with the respective actuation and
engagement surfaces, such that the engagement segment can engage
with the groove in the tubing head bore.
[0033] Referring again to the embodiment shown in the FIGS. 3-7,
the tubing head 14 including the actuation shoulder 25 and the
groove 26 are in one embodiment made of 4140 alloy steel, but could
be made from alternate forms of alloy steel or other material known
to a person skilled in the art. The tubing hanger 16 including the
actuation segment 23 and spring loaded segment 24 are in another
embodiment made of 4130 alloy steel. However, these components
likewise could be made of other forms of alloy steel or other
substances known to one skilled in the art.
[0034] Referring particularly to FIGS. 3-7, a plurality of spiral
locks 18 are located at the top and bottom of the tubing hanger 16.
The spiral locks 18 are annular and fit within an annular groove 42
in the tubing hanger. The spiral locks 18 prevent the actuation
segment 23 and spring loaded segment 24 from sliding off the tubing
hanger 16 when not engaged with the tubing head 14.
[0035] Referring particularly to FIGS. 4, 5 and 8, the tubing head
14 contains laterally extending holes for receiving lock screws 21.
The tubing hanger 16 is further secured within the tubing head 14
by three lock screws 21. These lock screws 21 additionally support
the tubing hanger 16 within a specific position in the tubing head
14 and prevent upward movement of the tubing hanger 16. The lock
screws 21 also contribute to seal engagement as discussed in detail
below.
[0036] Upper and lower compressible annular seals 22, preferably
made of rubber, encircle the tubing hanger 16 along a sealing
surface located above the bore contact surface. The seals 22 are
separated by a middle ring 45 which also encircles and is slidable
along the sealing surface. Referring to FIG. 5, when the tubing
hanger 16 is in the first position, the seals 22 are not compressed
and thus do not expand beyond the bore contact surface of the
tubing hanger 16. In this position the seals 22 remain flush with
the bore contact surface of the tubing hanger 16. By remaining
flush, the seals 22 are not as susceptible to damage upon insertion
into the tubing head 14.
[0037] Referring to FIG. 6, when the tubing hanger 16 is in the
locked position and engaged with the tubing head 14, the seals 22
can be expanded such that they engage the tubing head 14 and create
an annular seal between the tubing hanger 16 and tubing head 14.
This seal is accomplished by the lock screws 21 engaging a top ring
44 located above the upper seal 22 on the tubing hanger 16. The top
ring 44 is slidably movable in an axial direction over the tubing
hanger surface and has an inner diameter slightly greater than the
external diameter of the coiled tubing or jointed tubing 30 that
runs through the tubing hanger 16, and an outer diameter that is
slightly less than the internal diameter of the tubing head 14.
Part of the upper surface of the top ring 44 is chamfered to
correspond to a portion of the distal end of the frusto-conical
shaped lock screw 21. The top ring 44 serves as a seal compressor:
as the lock screws 21 engage the top ring 44, the top ring moves
downwards to compress the seals 21, thereby causing the seals to
protrude from the bore contact surface and engage the bore
surface.
[0038] Referring to FIG. 8, a wellhead assembly is comprised of a
blowout preventer 31 which is flanged attached at its lower
extremity to an adaptor flange 55 that is threadably attached at
its lower extremity to the master valve 34 which is then threadably
attached at its lower extremity to the tubing head 14. The blowout
preventer 31 prevents the sudden backflow release of pressure from
the well. A tubing hanger apparatus as previously described is
included in the wellhead assembly below the master valve 34. Above
the tubing hanger apparatus, a string of coiled tubing or jointed
tubing 30 is centrally fitted through the master valve 34 and then
through a central passage in the tubing hanger 16 and inserted into
the well. Within the well the coiled tubing or jointed tubing 30 is
inserted to a predetermined depth, cut and sealed. The top end of
the coiled tubing or jointed tubing 30 string is engaged with the
tubing hanger's 16 lower extremity by a plurality of threaded
connectors 46 located on the inner surface of the tubing hanger's
16 central passage. As the coiled tubing or jointed tubing 30
passes the plurality of threaded connectors 46, the threaded
connectors 46 engage the outer surface of the coiled tubing or
jointed tubing 30, preventing it from coming loose.
[0039] The tubing hanger 16 is further equipped with a back
pressure valve thread 20 which allows a back pressure valve to be
lubricated and threaded into the tubing hanger 16. With a tubing
hanger 16 containing the back pressure valve 20 in place in the
wellhead, a test port 35 can be utilized to determine if a proper
seal exists between the tubing hanger 16 and tubing head 14.
Referring particularly to FIG. 8, a test port 35 is located within
the tubing head 14 to allow for fluid to be introduced below the
seals 22 to determine if an annular seal exists between the tubing
hanger 16 and tubing head 14. Without the ability to test for a
proper seal created by the seals 22, lock screws 21 and tubing
weight, it would be dangerous to remove the wellhead components
above the tubing hanger 16 without the knowledge that the tubing
hanger 16 is properly engaged and sealed within the tubing head
14.
[0040] The lower extremity of the tubing head 14 is threadably
attached to a bell nipple 36 which is threadably attached at its
lower extremity to a production casing 29 which is inserted into
the well. The bell nipple 36 serves as a connection between the
production casing 29 and tubing head 14. Further, the well is
encased with a surface casing 28 which encircles the production
casing 29. The coiled tubing or jointed tubing string 30 attached
at its upper end to the tubing hanger 16 is inserted into the
production casing 29 and ultimately, into the well.
[0041] Because this wellhead assembly has a master valve 34 above a
tubing hanger 16 apparatus equipped with a backpressure valve 20,
the assembly has multiple means of preventing backflow from the
well. After testing for a seal utilizing the test port 35 as
described above, any pressure above the tubing hanger 16 apparatus
can be bled off and the master valve 34 removed or replaced if
necessary. Any backpressure will be contained by the backpressure
valve 20 within the tubing hanger apparatus. This is necessary for
the ability to replace or repair the master valve 34 or other
components above the tubing hanger 16 without exposing the operator
to the dangerous conditions of a live well or alternatively, having
to freeze the well. By having the master valve 34 above the tubing
hanger 16, there is no tubing running through the master valve 34
which would impede its removal or may cause accidental damage to
the coiled tubing or jointed tubing 30 or master valve 34.
[0042] In an alternate form of this assembly shown in FIG. 9, and
following the removal of the blowout preventer 31 and master valve
34, a swedge 32 can be threadably attached at the upper extremity
of the tubing head 14 with a top section 25 threadably attached at
the upper extremity of the swedge 32 for production purposes. The
swedge 32 allows for connecting the reduced diameter of a top
section 25 to the tubing head 14. The top section 47 may include a
flow tee 48 for branching the wellhead assembly, a ball valve 49
for extracting fluids, and/or a needle valve 50 for bleeding off
pressure, but may include other components that others skilled in
the art would be aware of. The top section 47 can be attached via
the ball valve 49 to a pumping vehicle which can deliver pressure
to the coiled tubing or jointed tubing 30 string within the well in
order to remove a plug (not shown) that had been previously
inserted at the lower extremity of the coiled tubing or jointed
tubing 30. By removing the plug, pressurized substances are free to
move up the coiled tubing or jointed tubing 30 and out of the
wellhead through the top section 47. It should be recognized that a
master valve 34 may also be included in this alternate assembly
between the swedge 32 and tubing head 14.
[0043] Directional terms "above", "below", etc. used are merely
intended to assist the reader in understanding the relative
positions of the components when the apparatus is in operation.
They are not intended, in any manner, to limit the scope of the
claims. One of ordinary skill in the art would recognize other
variations, modifications, and alternatives. It should be
recognized that, while the present invention has been described in
relation to the preferred embodiments thereof, those skilled in the
art may develop a wide variation of structural and operational
details without departing from the principles of the invention.
Therefore, the appended claims are to be construed to cover all
equivalents following within the true scope of spirit of the
invention.
* * * * *