Title:
TUBING HANGER APPARATUS AND WELLHEAD ASSEMBLY FOR USE IN OIL AND GAS WELLHEADS
Kind Code:
A1


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)
Application Number:
11/859617
Publication Date:
03/26/2009
Filing Date:
09/21/2007
Primary Class:
Other Classes:
166/75.11
International Classes:
E21B19/00
View Patent Images:
Related US Applications:



Primary Examiner:
WILLS III, MICHAEL R
Attorney, Agent or Firm:
LOCKE LORD BISSELL & LIDDELL LLP;ATTN: IP DOCKETING (600 TRAVIS, SUITE 3400, HOUSTON, TX, 77002-3095, US)
Claims:
I claim:

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

This invention relates generally to tubing hangers for use in oil and gas wellheads.

BACKGROUND OF THE INVENTION

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

Further preferred features of the invention are in the following descriptions of illustrative embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1. is a side view of a conventional wellhead with a master valve located below a tubing hanger (PRIOR ART);

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);

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;

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;

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;

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;

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.

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

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.