TUBING HANGER

Abstract

A tubing hanger and system for landing a tubing hanger in a tubing head of a wellhead with full well containment. The tubing hanger includes a cylindrical housing with a production port and a penetrator port, each extending through the cylindrical housing and each offset from a center axis of the cylindrical housing. The tubing hanger can land production tubing within a tubing head of a well head with a ratio of outer diameters of the production tubing to the tubing hanger of about 0.50.

Description

CROSS-REFERENCE TO RELATED APPLICATION

The present application claims priority under 35 U.S.C. §119 to U.S. Provisional Patent Application No. 61/941,253, filed on Feb. 18, 2014, titled “TUBING HANGER”, is hereby incorporated by reference in its entirety into the present application.

TECHNICAL FIELD

Aspects of the present disclosure involve a tubing hanger as well as a system and method of landing a tubing hanger in a tubing head with full well containment.

BACKGROUND

During completion of oil and gas production wells, a wellhead is installed above a wellbore as a surface interface with the oil or gas below. The wellhead includes many components, one of which is a tubing hanger. The tubing hanger is a device that attaches to a topmost tubing joint of a string of production tubing and supports the production tubing within the wellhead. The tubing hanger also supports a penetrator, which is a device that provides an electrical interface between a surface junction box and a downhole cable that extends to an electric submersible pump (ESP) within the wellbore. Conventionally, the tubing hanger is secured in place within the tubing head of a wellhead via a rotating flange that provides an interface between the tubing hangar and additional production tubing that leads to a surface reservoir. Once the tubing hanger is installed in the wellhead, the ESP pumps the production fluid (e.g., oil, gas) up the production tubing, through the wellhead, and into the surface reservoir.

During completion, the tubing hanger, along with the production tubing and the penetrator, must be landed or seated into a tubing head of the wellhead. Often, to land the tubing hanger, a blowout preventer (BOP), which is a special valve or device installed above a wellhead to control blowouts of fluid, tools and tubing, must be removed because the tubing hanger cannot fit through the bore of the BOP. By removing the BOP from the wellhead, the well is not contained and is, thus, susceptible to blowout during the landing process.

Conventionally, tubing hangers are landed or seated into the wellhead using a section of production tubing of the same size as the production tubing that hangs below the tubing hanger. This section of production tubing also, conventionally, includes the same type and size of threading to couple with the tubing hanger. In this way, the top and bottom of portions of a production side of the tubing hanger are mirror images of each other. This practice introduces certain limitations in the sizing and design of tubing hangers, which ultimately limits the size of production tubing that can be landed in a particular wellbore.

With these thoughts in mind among others, aspects of a tubing hanger and a system and a method of use disclosed herein were developed.

SUMMARY

Aspects of the present disclosure can include a tubing hanger that includes a penetrator-feed-through port comprising a penetrator passageway extending between openings at a top and a bottom of the penetrator-feed-through port, the penetrator passageway defining a penetrator axis therethrough. The penetrator-feed-through port is parallel to and offset from a longitudinal axis extending between a center points of the top surface and the bottom surface of the tubing hanger. The tubing hanger can also include a production port comprising a production passageway extending between openings at a top and bottom of the production port. The production port is defined within a raised neck member that extends from the top surface of the tubing hanger. The production passageway defining a production axis therethrough that is parallel to and offset from the longitudinal axis.

Aspects of the present disclosure involve a tubing hanger that maximizes a size of production tubing to be landed in a wellbore using a particular design, size, and arrangement of thread patterns on the tubing hanger and the landing tool. Utilization of the tubing hanger described herein enables, for example, landing a 2.25 inch penetrator and a string of 3.5 inch EUE (external-upset-end) production tubing in a 7 inch nominal bowl of a tubing head (i.e., 7 inch being an inner diameter of the tubing head just above the landing area or load shoulder of the tubing head). The tubing hanger described herein is additionally capable of scaling such that a ratio of outer diameters of the production tubing to be landed in the wellbore to the tubing hanger is about 0.50.

Aspects of the present disclosure involve a tubing hanger including a penetrator-feed-through port and a production port. The penetrator-feed-through port includes a penetrator passageway extending between a penetrator top end and a penetrator bottom end. The penetrator-feed-through port also defines a penetrator axis therethrough that is parallel to and offset from a longitudinal axis extending between a center point of a top surface and a bottom surface of the tubing hanger. The production port includes a production passageway extending between a production top end defined in a raised neck member extending from the top surface of the tubing hanger and a production bottom end. The production port defines a production axis therethrough that is parallel to and offset from the longitudinal axis, the production passageway comprising a bottom connection at the production bottom end that is configured to couple with an end of a production tubing to be landed in a tubing head of a well head, the production passageway comprising a top connection at the production top end that is different than the bottom connection and that is configured to couple with an end of a landing tool.

In certain implementations, the production tubing includes an outer diameter of about 3.5 inch and the tubing hanger comprises a cylindrical housing having an outer diameter that is less than 7 inch. The top connection includes a top threaded connection and the bottom connection comprises a bottom threaded connection.

Aspects of the present disclosure involve a system of well completion including a tubing hanger, a penetrator, and a landing tool. The tubing hanger may include a penetrator-feed-through port and a production port. The penetrator-feed-through port includes a penetrator passageway extending between a penetrator top end and a penetrator bottom end. The production port includes a production passageway extending between a production top end defined in a raised neck member extending from a top surface of the tubing hanger and a production bottom end. The production passageway includes a bottom connection at the production bottom end that is configured to couple with an end of a production tubing to be landed in a tubing head of a well head, the production passageway comprising a top connection at the production top end that is different than the bottom connection and that is configured to couple with an end of a landing tool. The penetrator is configured to be positioned within the penetrator-feed-through port and includes electrical leads for connecting with a surface power supply and a plurality of downhole cable for connecting with a downhole cable or an electric submersible pump. The landing tool is configured to couple with and land the tubing hanger in the tubing head of the well head and includes a tubular body and the end including engaging features that are configured to engage with engaging features on the top connection.

Aspects of the present disclosure also include a method of well completion including landing a tubing hanger in a tubing head of a wellhead with a landing tool. The tubing hanger may include a penetrator-feed-through port comprising a penetrator passageway extending between a penetrator top end and a penetrator bottom end. The tubing hanger may additionally include a production port including a production passageway extending between a production top end defined in a raised neck member extending from a top surface of the tubing hanger and a production bottom end. The production passageway includes a bottom connection at the production bottom end that is configured to couple with an end of a production tubing to be landed in a tubing head of a well head. The production passageway also includes a top connection at the production top end that is different than the bottom connection and that is configured to couple with an end of the landing tool.

Additionally, other embodiments are also described and recited herein. Further, while multiple implementations are disclosed, still other implementations of the presently disclosed technology will become apparent to those skilled in the art from the following detailed description, which shows and describes illustrative implementations of the presently disclosed technology. As will be realized, the presently disclosed technology is capable of modification in various aspects, all without departing from the spirit and scope of the presently disclosed technology. Accordingly, the drawings and detailed description are to be regarded as illustrative in nature and not limiting.

BRIEF DESCRIPTION OF THE DRAWINGS

Example embodiments are illustrated in referenced figures of the drawings. It is intended that the embodiments and figures disclosed herein are to be considered illustrative rather than limiting.

FIG. 1A depicts a side view of a tubing hanger;

FIG. 1B depicts a top view and a section view of the tubing hanger of FIG. 1A;

FIG. 2 depicts a side view of a landing tool;

FIG. 3 depicts a side view of a penetrator;

FIG. 4 depicts a side view of the tubing hanger, the penetrator, the landing tool, a check valve, and a production tube;

FIG. 5 depicts a top view and a section view of a rotating flange;

FIG. 6 depicts a top view and a section view of a lock ring that secures the rotating flange to the wellhead;

FIG. 7 depicts a flowchart of a process for landing the tubing hanger in a wellhead;

FIG. 8 depicts a flowchart of another process for landing the tubing hanger in a wellhead; and

FIG. 9 depicts a flowchart of a process for splicing a downhole cable to a penetrator's pigtails.

DETAILED DESCRIPTION

Aspects of the present disclosure include a tubing hanger that includes a penetrator-feed-through port and a production port. The penetrator-feed-through port includes a penetrator passageway extending between openings at a top and a bottom of the penetrator-feed-through port. The penetrator passageway defines a penetrator axis therethrough that is parallel to and offset from a longitudinal that extends through a center point of the top surface and the bottom surface of the tubing hanger. The production port includes a production passageway extending between openings at a top and bottom of the production port. The production port defines a raised neck member that extends a first distance from the top surface of the tubing hanger. The production passageway defines a production axis therethrough that is parallel to and offset from the longitudinal axis that extends through the center point of the top surface and the bottom surface of the tubing hanger.

The tubing hanger is capable of landing a string of production tubing and a penetrator through a blowout preventer (BOP) and into a tubing head of a wellhead. Since the blowout preventer need not be removed, the well is prevented from catastrophic blowouts while landing the tubing hanger and the attached penetrator and production tubing.

Referring to FIGS. 1A-1B, the tubing hanger 10 can include a cylindrical housing 12 with a production port 14 and a penetrator-feed-through (PFT) 16, each extending through the housing 12 and each offset from a center axis 18 of the cylindrical housing 12. The production port 14 can include a raised neck member 20 that extends upward from a top surface 22 of the tubing hanger 10. The raised neck member 20 can include a production passageway 24 extending from a top surface 26 of the raised neck member 20 to a bottom surface 28 of the tubing hanger 10. The production passageway 24 defines a production axis 30 through the passageway 24 that is parallel to the center axis 18 of the cylindrical housing 12. In some implementations, parallel means substantially parallel. In other implementations, parallel may mean perfectly parallel, offset from parallel by about 1 degree, 2 degrees, or otherwise. The production port 14 can include a first set of threading 32 to receive a landing tool 34 at a top portion 36 of the production passageway 24, the production port 14 can include a second set of threading 38 to receive a back-pressure valve (BPV) 40 at a mid-portion 42 of the production passageway 24, and the production port 14 can include a third set of threading 44 to receive a tubing joint 46 of a production tube 48 at a bottom portion 50 of the production passageway 24.

While the embodiment of FIG. 1 describes three sets of threads, the production port 14 can include more or less sets of threading as necessitated by the needs of the well. As an example, the first set of threading 32 can be, for example, 3.5 inch ACME threads. The threading can, however, be a different trapezoidal thread form or an altogether different thread form. The first set of threading 32 is to receive corresponding threads from the landing tool 34, which will be discussed in reference to FIG. 2. While the embodiment of FIG. 1 describes sets of threading, the tubing hanger 10 can include attachment mechanisms or engaging features other than threading to couple the tubing hanger 10 with the production tube 48, BPV 40, and landing tool 34.

The second set of threading 38 can be BPV threads 52 for receiving corresponding threads of a BPV 40. The BPV threads 52 can be, for example, 3 inch threads, 2 and ⅜ inch threads, 3.5 inch threads, among others. The BPV 40 can be installed in the production passageway 24 to prevent a blowout during landing of the tubing hanger 10 and afterwards. Additionally, if a tubing hanger 10 is installed in the tubing head of the well head without a BPV 40 in place, a lubricator can be used to install a BPV 40 to provide well control, should the tree assembly (i.e., valves, spools, and/or gauges above the wellhead) be removed. In short, the BPV 40 provides a means of well control during landing of the tubing hanger 10 and afterwards. An example of a BPV 40 can be a two-way check valve that will stop fluid pressure from traveling up the wellhead while allowing fluids to be pumped into the wellbore from above.

The third set of threading 44 is to engage with a corresponding threading on a landing joint of a topmost tube in the string of production tubing 48 to be landed in the wellbore. Thus, the tubing hanger 10 supports the weight of the string of production tubing 48, while the tubing head, within the wellhead, supports the weight of the tubing hanger 10. In particular, during landing of the tubing hanger 10, the tubing hanger 10 seats on a load shoulder of the tubing head. The tubing hanger 10 is then held in place by lockdown pins within the tubing head. The third set of threading 44 can be, for example, 3.5 inch EUE, 8 round threads, or 3 EUE, inch 8 round threads, among others. While the third set of threading 44 is described as including certain threading patterns, the third set of threading 44 and the corresponding threading on the drill pipe 48 can include an altogether different thread patterns.

Referring to FIGS. 1A-1B, the PFT port 16 can include a penetrator passageway 54 that extends from a top surface 22 of the tubing hanger 10 to the bottom surface 28 of the tubing hanger 10. The penetrator passageway 54 defines a penetrator axis 56 through the passageway 54 that is parallel to the center axis 18 of the cylindrical housing 12 of the tubing hanger 10. In some implementations, parallel means substantially parallel. In other implementations, parallel may mean perfectly parallel, offset from parallel by about 1 degree, 2 degrees, or otherwise. The PFT port 16 is capable of securing a penetrator 58 within the penetrator passageway 54 under low pressure and high pressure well operating conditions. In the embodiment of FIG. 1, the penetrator passageway 54 is cylindrical in order to receive a cylindrical penetrator, but the penetrator passageway 54 can be, for example, rectangular or square, among other possible shapes. In the present embodiment, the penetrator passageway 54 can, for example, have an inner diameter of about 2.515 inches, 2 inches, or 2.25 inches, among others.

The production port 14 and the PFT port 16 are offset from the center axis 18 of the cylindrical housing 12 such that production tubing 48 (e.g., standard 3.5 inch EUE) and penetrators (e.g., standard 2.25 inch outer diameter) can be coupled with the tubing hanger 10 and the tubing hanger 10 can be landed through a BOP 60 having a drift of, for example, 7 inches or 7 and 1/16 inches. As seen in the embodiment of FIG. 1B, the cylindrical housing 12 defines a circular, outer perimeter with the center axis 18 in the center of the tubing hanger 10. The production port 14 and the PFT port 16 are positioned within the circular, outer perimeter and the respective production axis 30 and penetrator axis 56 are offset from the center axis 18 of the tubing hanger 10. In certain tubing hanger 10 variations, the BOP 60 must be removed in order to install a tubing hanger 10 because the hanger 10 is too large to fit within the bore of the BOP 60. With the offset design and the close tolerances between the production port 14 and the PFT port 16, the tubing hanger 10 is sized to fit through the BOP 60 while the BOP 60 is on the wellhead. Thus, the well can be further controlled by landing the tubing hanger 10 in the well head while the BOP 60 is still operating.

Still referring to FIGS. 1A-1B, example dimensions of the tubing hanger 10 can include a cylindrical housing 12 diameter [A] of about 6.985 inches and a height [C] from the top surface 22 to the bottom surface 28 of the tubing hanger 10 of about 5.765 inches. The raised neck 20 can extend upwards [D] from the top surface 22 of the cylindrical outer housing 12 about 2.485 inches such that a total height [B] of the tubing hanger 10 is about 8.25 inches. The penetrator port 16 can include an inner diameter [E] of about 2.515 inches, while the production port 14 can have various inner diameter widths throughout the production passageway 24 to accommodate the first, second, and third sets of threads. A center point [F] of the production port 14 can be about 1.375 inches offset from the center axis 18 of the cylindrical housing 12 [G], which is located about 3.4925 inches from an outer edge of the cylindrical housing 12. A center point of the PFT port 16 [H] can be about 1.885 inches offset from the center point of the cylindrical housing 12 [G]. A furthest portion of the raised neck 20 that extends across the top surface 22 of the cylindrical housing 12 [I] can be about 3.750 inches, while the remaining portion that extends across the top surface 22 of the cylindrical housing 12 [J] can be about 3.235 inches. While these and other dimensions can be seen on FIGS. 1A-1B, the dimensions are intended to be illustrative and can be altered without changing the scope of the disclosure.

Example materials for construction of the tubing hanger 10 and landing tool 34 can be those materials which would be known to people having ordinary skill in the art, and can include steel, among other metals. For example, the material can be 4130 steel.

FIG. 2 depicts a landing tool 34 that is configured to engage with the tubing hanger 10 and to deliver and position the tubing hanger 10 within the tubing head of the wellhead. The landing tool 34 can include a tubular body 62 that includes a first end 68 with a first thread pattern 64 at a bottom side of the landing tool 34 and a second end 70 with a second thread pattern 66 on a topside of the landing tool 34. The first thread pattern 64 can be a male thread pattern that corresponds to the first set of threads 32 on the tubing hanger 10. As an example, the first thread pattern 64 can be 3.5 inch ACME threads, among others, that matingly engage with the female thread pattern on the first set of threads 32 on the tubing hanger 10. The second thread pattern 66 can be a female thread pattern and can be, for example, 3.5 inch EUE, 8 round threads. The second thread pattern 66 can engage with similarly sized drill pipe to that of the production tubing 48 that couples with the production port 14 of the tubing hanger 10.

During landing of the tubing hanger 10, the landing tool 34 is engaged with the tubing hanger 10 by threading the landing tool 34 onto the tubing hanger 10. The tubing hanger 10 is subsequently lowered into the wellhead until the tubing hanger 10 is seated against the load shoulder of the tubing head. The tubing hanger 10 can be positioned appropriately in the tubing head by adjusting the landing tool 34. Once the tubing hanger 10 is properly in place, the tubing hanger 10 can be secured or locked in place. The tubing hanger 10 can be set in place by engaging lockdown pins that secure the tubing hanger 10 in its orientation within the tubing head. Then, the BOP can be removed and a rotating flange can be attached to the tubing head to secure the tubing hanger 10 in place. At this point, the tree assembly can be installed. In one non-limiting example, a length [K] of the landing tool 34 can be 24 inches.

In the embodiments of FIGS. 1-2, the diameter of the production port 14 on the top surface 22 of the tubing hanger 10 can be smaller than a diameter of the production port 14 on the bottom surface 28 of the tubing hanger 10. Similarly, the size of the first set of threads 32 on the tubing hanger 10 can be a smaller diameter than a diameter of the third set of threads 44 in the tubing hanger 10. Once the tubing hanger 10 is landed in the wellhead and secured to the tubing head by the lockdown pins, the landing tool 34 and the BOP 60 are then removed. At this point, a rotating flange 72 and a lock ring 74 are positioned above the tubing hanger 10 to provide a seal or interface between the tubing hanger 10 and the tree assembly. The rotating flange 72 can include ports that match or line-up with the production port 14 and PFT port 16 of the tubing hanger 10. In the disclosed embodiment, the rotating flange 72 is fitted over the tubing hanger 10 and the rotating flange 72 contacts an outer ring portion of the top surface 22 of the tubing hanger 10. The lock ring 74 subsequently secures the rotating flange 72 and the tubing hanger 10 in place within the wellhead. Thus, in order to accommodate the outer ring portion of the rotating flange 72 that contacts the top surface 22 of the tubing hanger 10, the production port 14 and the PFT port 16 must be positioned within the outer ring portion in order to be unobstructed by the rotating flange 72. In addition, the production port 14 and the PFT port 16 must be positioned far enough apart so that each respective port can be individually sealed by the ports in the rotating flange 72. Since the bottom side 28 of the tubing hanger 10 is not constrained by the rotating flange 78 in a similar manner, the diameter of the production port 14 on the bottom 28 of the tubing hanger 10 can be larger than the diameter of the production port 14 on the top side of the tubing hanger 10. Thus, relatively larger diameter production tubing 48 can be landed in a wellbore by using a relatively smaller diameter landing tool 34 that engages with a relatively smaller diameter production port 14 on the top surface 22 of the tubing hanger 10 because the production port 14 can be more centrally positioned such that the rotating flange will not obstruct the relatively smaller diameter production port 14 on the top surface 22 of the tubing hanger 10.

As stated previously, it is conventional to use a short section of production tubing 48, called a “landing joint,” that is identical in shape and thread pattern to the production tubing 48 that is landed within the well head to land the tubing hanger 10 in the tubing head. Conventionally, the landing joint has first and second thread patterns 64, 66 that are the same.

Still referring to FIGS. 1-2, the raised neck member 20 can include an outer diameter [N]. And, as stated previously, the cylindrical housing 12 of the tubing hanger 10 can include an outer diameter [A]. A ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be less than 0.6. In another embodiment, the ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be less than 0.575. In another embodiment, the ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be less than 0.55. In another embodiment, the ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be less than 0.5. In another embodiment, the ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be less than 0.525. In another embodiment, the ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be less than 0.5. In another embodiment, the ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be less than 0.475. In another embodiment, the ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be less than 0.45. In one example, the raised neck member 20 can include an outer diameter [N] of about 3.75 inches and the cylindrical housing 12 of the tubing hanger 10 can include an outer diameter [A] of about 6.985. Thus, the ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be 0.537 in this example.

The ratio of the outer diameter [N] of the raised neck member 20 to the outer diameter [A] of the cylindrical housing 12 of the tubing hanger 10 can be balanced with the strength capabilities of the material of the tubing hanger 10 and the load that the tubing hanger 10 will experience in the wellhead. The raised neck member 20 cannot be sized such that the material cannot withstand the pressure exerted by the weight of the string of production tubing 48 hanging from the tubing hanger 10. As an example, the material for the tubing hanger 10 and the raised neck member 20 can be rated to withstand pressures of up to 5,000 psi and the wall thickness of the raised neck member 20 must not be such that the integrity of the material is compromised when the tubing hanger 10 experiences the weight of the string of production tubing 48. Stated differently, the outer diameter [N] of the raised neck member 20 cannot be reduced so much that the wall thickness threatens premature failure of the tubing hanger 10.

Still referring to FIGS. 1-2 and as discussed previously, in certain implementations, the tubing hanger 10 is configured to land production tubing 48 having an outer diameter of 3.5 inches into a tubing head of a well head having a clearance of 7 inches. That is, the tubing hanger 10 is seated on a load shoulder where an inner diameter of the tubing head just above the load shoulder is 7 inches. In a tubing head of this size, the cylindrical housing 12 of the tubing hanger 10 may include an outer diameter [A] of about 6.985 inches. Thus, a ratio of the outer diameter of production tubing 48 to the outer diameter [A] of the tubing hanger 10 can be about 0.50. In certain implementations, the ratio of the outer diameter of production tubing 48 to the outer diameter [A] of the tubing hanger 10 can be greater than 0.50. In certain implementations, the ratio of the outer diameter of production tubing 48 to the outer diameter [A] of the tubing hanger 10 can be greater than 0.45. In certain implementations, the ratio of the outer diameter of production tubing 48 to the outer diameter [A] of the tubing hanger 10 can be greater than 0.40. A full listing of dimensions of an example embodiment of the tubing hanger 10 can be found in the Appendix to the Specification.

In certain implementations, the production tubing 48 has an outer diameter of greater than 3.0 inches. In certain instances, the production tubing 48 has an outer diameter of greater than 3.25 inches. In certain instances, the production tubing 48 has an outer diameter of greater than 3.40 inches. In certain instances, the production tubing 48 has an outer diameter of greater than 3.45 inches. In certain instances, the production tubing 48 has an outer diameter of about 3.5 inches. In certain instances, the production tubing 48 has an outer diameter of less than 4.0 inches. In certain instances, the production tubing 48 has an outer diameter of less than 3.75 inches. In certain instances, the production tubing 48 has an outer diameter of less than 3.60 inches. In certain instances, the production tubing 48 has an outer diameter of less than 3.55 inches.

While the disclosed embodiments refer to a rotating flange 72 and a lock ring 74 supporting the tubing hanger 10 within the wellhead, other mechanisms can similarly provide a seal between the tubing hanger 10 and the tree assembly. The disclosure of a rotating flange 72 and lock ring 74 are not intended to be limiting as other mechanism can similarly support the tubing hanger 10 within the wellhead.

As an example, to land 3.5 inch production tubing 48 down a 7 inch bowl of a tubing head and through a BOP 60 with about a 7 inch drift, a tubing hanger 10 can include a first set of threads 32 that are 3.5 inch ACME threads, which are smaller, non-tapered threads compared to 3.5 inch EUE 8 round threads which generally require a taper, and a third set of threads 44 that are 3.5 inch EUE 8 round threads. In this example, the size of the first set of threads are relatively smaller than the third set of threads (i.e., the 3.5 inch acme threads do not require a taper) such that the production port 14 and the PFT port 16, on the top surface 22 of the tubing hanger 10, are not obstructed by the rotating flange 72.

As seen in FIG. 1B, the raised neck member 20 could not accommodate a bore for 3.5 inch EUE threading. As seen at the bottom of the production port 14, an inner diameter [O] of the bore for the third set of threading 44 (i.e., 3.5 EUE threading) is about 3.81 inches in diameter. And, as seen at the top of the production port, the outer diameter [N] of the entire raised neck member 20 is 3.75 inches in diameter. Thus, the inner diameter [O] of the bore for the third set of threading 44 is larger than the entirety of the raised neck member 20. Clearly, given the dimensions of the raised neck member 20, a 3.5 inch EUE threading could not be used for the first set of threads 32.

It is conventional in the industry to size down the first and third sets of threading 32, 44, while keeping them the same size, until the first set of threading 32 can fit within the confines of the raised neck member 20. Thus, as an example, if a bore for a 2.5 inch EUE threading could fit within the confines of the raised neck member 20, then a conventional practice in the industry would be to utilize a 2.5 inch EUE threading on the bottom side of the production port 14. Utilizing EUE threading is common in the drilling industry and, thus, it makes sense that, conventionally, EUE threading is utilized on both ends of the tubing hanger 10. Doing so, however, limits the size of production tubing 48 to be landed in a wellhead.

Utilizing a non-tapered thread (i.e., 3.5 inch ACME) on the first set of threading 32 enables a 3.5 inch diameter section of production tubing (i.e., landing tool) with a non-tapered thread to fit within the confines of the raised neck member 20. Stated differently, the first thread pattern 64 on the landing tool 34 that engages with the first set of threads 32 on the tubing hanger 10 can still be machined on the same size production tubing 48 as that of the third set of threading 44. In other words, 3.5 inch outer diameter production tubing can be machined to include either an EUE or trapezoidal (e.g., ACME) thread configuration.

FIG. 3 depicts a penetrator 58 that is configured to couple with the tubing hanger 10 in the PFT port 16. The penetrator 58 is an electrical interface between a surface junction box and an ESP downhole. Power for the ESP is routed from the junction box to the penetrator 58 and then to the ESP via electrical wires known as REDA cables or ESP cables. A topside 76 of the penetrator 58 can include three copper pins or leads for attaching to the electrical wires from the junction box. The penetrator 58 can include a solid body 78 that extends a length of the PFT port 16. On a downhole side of the penetrator 58, three wires known as pigtails 80 extend downward. The pigtails 80 will be spliced with a downhole cable, which spans a length of the string of tubing, all of the way down to the ESP. The penetrator 58 can include a collar 82 on the downhole side of the penetrator 58 that is wider than an outer diameter of the penetrator 58. Anti-rotation bolts 84 can secure the collar 82 to the bottom surface 28 of the tubing hanger 10 to prevent rotation of the penetrator 58 within the penetrator passageway 54. And, the penetrator 58 can also include a surface lock ring nut 86 on the topside of the penetrator 58 to further secure the penetrator 58 within the penetrator passageway 54 and prevent the penetrator 58 from falling through the PFT port 16. The penetrator 58 can also include o-ring seals 88 for sealing the penetrator 58 within the tubing hanger 10, as well o-ring seals 88 for sealing the penetrator within portions of the tree assembly. In one non-limiting example, the outer diameter [L] of the penetrator 58 can be about 2.25 inches and a length [M] of the solid body 78 can be about 14 inches. The pigtails 80 can extend from the downhole side of the penetrator 58 about 10 feet or 8 feet, among other possible distances.

In certain implementations, the outer diameter [L] of the penetrator 58 can be greater than 1.5 inches. In certain instances, the outer diameter [L] of the penetrator 58 can be greater than 1.75 inches. In certain instances, the outer diameter [L] of the penetrator 58 can be greater than 2.0 inches. In certain instances, the outer diameter [L] of the penetrator 58 can be about 2.25 inches. In certain instances, the outer diameter [L] of the penetrator 58 can be less 3.0 inches. In certain instances, the outer diameter [L] of the penetrator 58 can be less than 2.75 inches. In certain instances, the outer diameter [L] of the penetrator 58 can be less than 2.5 inches.

FIG. 4 depicts a system for well control. In particular, the figure depicts a tubing hanger 10 with a penetrator 58 installed in the penetrator passageway 54, a landing tool 34 installed in the first set of threading 32, a BPV 40 installed in the second set of threading 38, and a production tube 48 installed in the third set of threading 44. This system can be landed through a bore of a BOP 60 such that the tubing hanger 10 seats against the load shoulder of a tubing head within the wellhead. Once the system is in the wellhead, lockout pins may be engaged to secure a positioning of the tubing hanger 10 within the tubing head. At this point, the landing tool 34 can be removed. Also, if the BPV 40 was not installed prior to landing, the BPV 40 may be installed after the landing tool 34 is removed. The BOP 60 can then be removed from the wellhead and a rotating flange 72 can be installed on the wellhead to secure the tubing hanger 10 within the tubing head. Next, the tree assembly can be installed on the wellhead and the well can be controlled with the various controls on the tree assembly. At this point, the BPV 40 can be removed.

FIG. 5 illustrates a rotating flange 72 for use in securing the tubing hanger 10 in place within the wellhead. The rotating flange 72 can include ports that are generally coextensive with the production port 14 and the PFT port 16, when the rotating flange 72 is positioned above the tubing hanger 10. As previously stated, the rotating flange 72 and the lock ring 74 extend over an outer ring portion of the top surface 22 of the tubing hanger 10. The production port 14 and the PFT port 16 are positioned on the tubing hanger 10 such that when the rotating flange 72 and lock ring 74 are installed, the ports are within the outer ring portion that are being supported by the rotating flange 72. While the disclosed embodiments refer to a rotating flange 72, other designs are possible to seal or interface between the tubing hanger 10 and the tree assembly.

When coupled with the tubing hanger 10, the raised neck member 20 is partially received within a production side lower opening 102 on a bottom surface 104 of the rotating flange 72. Coextensive with the production side lower opening 102 is a production side upper opening 106 extending from a top surface 108 of the rotating flange 72. As seen in FIG. 5, the production side upper opening 106 is sized for a tapered thread, such as a 3.5 inch EUE (external-upset-end) threading. Also seen in FIG. 5, is a test valve 110 that may be pressurized to ensure an adequate seal between the rotating flange 72 and the raised neck member 20 of the tubing hanger, between the rotating flange 72 and the production tubing 48 extending out the production side upper opening 106, and between the rotating flange 72 and the penetrator 58. In certain implementations, the test valve 110 is a ½ inch diameter test valve.

In one implementation, a tubing hanger 10 coupled with 3.5 inch EUE production tubing 48 and a 2.25 inch penetrator 58 can be landed in a tubing head having a 7 inch bowl when the first set of threading 32 is 3.5 inch ACME threads. As discussed previously, conventional tubing hangers 10 utilize the same threading for the first and third sets of threading 32, 44. There is, however, insufficient room or tolerances in the raised neck member 20 for 3.5 inch EUE threading. To remedy this challenge, conventional tubing hangers 10 reduce the threading sizes for the first and third sets of threading, as well as the size of production tubing, to accommodate EUE threading on both sides of the tubing hanger.

As such, when utilizing a non-tapered threading, such as, for example, ACME threads, larger production tubing 48 can be used on both ends of the tubing hanger 10 because the non-tapered threads generally requires less machining of the raised neck member 20.

FIG. 6 illustrates the lock ring 74 for use in securing the rotating flange 72 above the tubing hanger 10 within the wellhead. FIGS. 5-6 illustrate the nesting relation between the tubing hanger 10, rotating flange 72, and the lock ring 74. As illustrated, once the tubing hanger 10 is landed in the tubing head, the rotating flange 72 is positioned above the tubing hanger 10 with the ports being coextensive, and the lock ring 74 is secured over the rotating flange 72 such that the rotating flange 72 and the tubing hanger 10 are secured sealed in place. While the disclosed embodiments refer to a lock ring 74, other designs are possible to secure the rotating flange 72 in place. For example, any type of fastener with bolts or otherwise can be used in place of the lock ring without departing from the present disclosure.

Referring to FIG. 7, a method of controlling a well while landing a tubing hanger 10 in a wellhead can include the steps of securing a landing joint of a last joint of tubing 48 to be landed in a well within a production port 14 of a tubing hanger 10 [Operation 100]. The method can also include installing a BPV 40 within the production port 14 of the tubing hanger 10 [Operation 110] and securing a landing tool 34 within the production port 14 of the tubing hanger 10 [Operation 120]. The method can further include securing a penetrator 58 in a PFT port 16 of the tubing hanger 10 [Operation 130] and landing the tubing hanger 10 through a BOP 60 and into a tubing head of a wellhead [Operation 140]. Finally, the method can also include securing lockdown pins on the tubing hanger 10 [Operation 150], removing the BOP 60 [Operation 160], and installing a rotating flange 72 to the wellhead in order to secure the tubing hanger 10 within the tubing head [Operation 170].

Referring to FIG. 8, another method of controlling a well while landing a tubing hanger 10 in a wellhead can include measuring a first distance from a top of a bore of a BOP 60 to a center point of a lockdown pin in the tubing head [Operation 200]. The method can further include positioning the tubing hanger 10 over the bore of the BOP 60 [Operation 210] and identifying a point on the landing tool 34 that is the first distance upward from a top surface 22 of the tubing hanger 10 [Operation 220]. The method then can include landing the tubing hanger 10 through the bore of the BOP 60 until the identified point on the landing tool 34 is coextensive or flush with the top of the bore of the BOP 60 [Operation 230]. When the points are flush, the tubing hanger 10 is sufficiently landed within the load shoulder of the tubing head such that the lockdown pins can be engaged and the tubing hanger 10 can be secured within the wellhead.

Referring to FIG. 9, another method of controlling a well while landing a tubing hanger 10 in a wellhead can include splicing the pigtails 80 of the penetrator 58 with the downhole cable while the BOP 60 is connected to the wellhead. The splicing is necessary in order to supply power, which is routed to the penetrator 58, to the ESP. The splicing can be performed outside of the wellbore, before the tubing hanger 10 is landed into the wellhead, and while the BOP 60 is connected to the wellhead. Additionally, enough drill pipe 48 can be exposed out of the wellbore such that the downhole cable is also exposed out of the wellbore for the splicing. The method can include coupling the drill pipe 48 to the tubing hanger 10 [Operation 300] and positioning the penetrator 58 in the PFT port 16 of the tubing hanger 10, while hanging the pigtails flush against the drill pipe 48 [Operation 310]. The method can also include identifying a point where a shortest of the pigtails 80 overlaps with the downhole cable, which is also positioned flush with the drill pipe 48 [Operation 320]. The method can further include removing the penetrator 58 from the tubing hanger 10 [Operation 330], splicing the pigtails 80 with the downhole cable where the downhole cable overlaps with the shortest of the pigtails 80 [Operation 340], reposition the penetrator 58 in the PFT port 16 of the tubing hanger 10 [Operation 350], and landing the tubing hanger 10 in the tubing head of the wellhead [Operation 360].

Although various representative embodiments of this invention have been described above with a certain degree of particularity, those skilled in the art could make numerous alterations to the disclosed embodiments without departing from the spirit or scope of the inventive subject matter set forth in the specification. All directional references (e.g., top, bottom) are only used for identification purposes to aid the reader's understanding of the embodiments of the present invention, and do not create limitations, particularly as to the position, orientation, or use of the invention unless specifically set forth in the claims. Joinder references (e.g., attached, coupled, connected, and the like) are to be construed broadly and can include intermediate members between a connection of elements and relative movement between elements. As such, joinder references do not necessarily infer that two elements are directly connected and in fixed relation to each other.

In methodologies directly or indirectly set forth herein, various steps and operations are described in one possible order of operation, but those skilled in the art will recognize that steps and operations can be rearranged, replaced, or eliminated without necessarily departing from the spirit and scope of the present invention. It is intended that all matter contained in the above description or shown in the accompanying drawings shall be interpreted as illustrative only and not limiting. Changes in detail or structure can be made without departing from the spirit of the invention as defined in the appended claims.

Claims

1. A tubing hanger comprising:

a penetrator-feed-through port comprising a penetrator passageway extending between a penetrator top end and a penetrator bottom end and defining a penetrator axis therethrough that is parallel to and offset from a longitudinal axis extending between a center point of a top surface and a bottom surface of the tubing hanger; and

a production port comprising a production passageway extending between a production top end defined in a raised neck member extending from the top surface of the tubing hanger and a production bottom end, the production port defining a production axis therethrough that is parallel to and offset from the longitudinal axis, the production passageway comprising a bottom connection at the production bottom end that is configured to couple with an end of a production tubing to be landed in a tubing head of a well head, the production passageway comprising a top connection at the production top end that is different than the bottom connection and that is configured to couple with an end of a landing tool.

2. The tubing hanger of claim 1, wherein the production tubing comprises an outer diameter of greater than 3.25 inches and less than 3.75 inches and the tubing hanger comprises a cylindrical housing having an outer diameter that is 7 inches or less, wherein the top connection comprises a top threaded connection and the bottom connection comprises a bottom threaded connection.

3. The tubing hanger of claim 2, wherein the bottom threaded connection is a tapered threaded connection that progressively narrows as it extends from the production bottom end towards the production top end.

4. The tubing hanger of claim 3, wherein the bottom threaded connection is an external-upset-end thread configuration.

5. The tubing hanger of claim 3, wherein the top threaded connection is a non-tapered threaded connection.

6. The tubing hanger of claim 5, wherein the top threaded connection is a trapezoidal thread configuration.

7. The tubing hanger of claim 6, wherein the trapezoidal thread configuration is an ACME thread configuration.

8. The tubing hanger of claim 2, wherein the penetrator-feed-through port is configured to support a penetrator comprising an outer diameter of greater than 1.75 inches and less than 2.5 inches.

9. The tubing hanger of claim 1, wherein a ratio of outer diameters of the production tubing to the tubing hanger is about 0.50.

10. The tubing hanger of claim 1, wherein a ratio of outer diameters of the raised neck member to the tubing hanger is within a range of about 0.5 to about 0.6.

11. The tubing hanger of claim 1, wherein a ratio of outer diameters of the raised neck member to the tubing hanger is within a range of about 0.5 to about 0.55.

12. A system of well completion comprising,

a tubing hanger comprising: a penetrator-feed-through port comprising a penetrator passageway extending between a penetrator top end and a penetrator bottom end; and a production port comprising a production passageway extending between a production top end defined in a raised neck member extending from a top surface of the tubing hanger and a production bottom end, the production passageway comprising a bottom connection at the production bottom end that is configured to couple with an end of a production tubing to be landed in a tubing head of a well head, the production passageway comprising a top connection at the production top end that is different than the bottom connection and that is configured to couple with an end of a landing tool;

a penetrator configured to be positioned within the penetrator-feed-through port and comprising electrical leads for connecting with a surface power supply and a plurality of downhole cable for connecting with a downhole cable or an electric submersible pump; and

a landing tool configured to couple with and land the tubing hanger in the tubing head of the well head and comprising a tubular body and the end comprising engaging features that are configured to engage with engaging features on the top connection.

13. The system of claim 12, wherein the production tubing comprises an outer diameter of greater than 3.25 inches and less than 3.75 inches and the tubing hanger comprises an outer diameter that 7 inches or less, wherein the engaging features of the top connection and the end of the landing tool comprise non-tapered threading.

14. The system of claim 13, wherein the non-tapered threading comprises a trapezoidal thread configuration.

15. The tubing hanger of claim 13, wherein the penetrator-feed-through port is configured to support a penetrator comprising an outer diameter of greater than 1.75 inches and less than 2.5 inches.

16. The tubing hanger of claim 12, wherein a ratio of outer diameters of the production tubing to the tubing hanger is about 0.50.

17. A method of well completion comprising:

landing a tubing hanger in a tubing head of a wellhead with a landing tool, the tubing hanger comprising: a penetrator-feed-through port comprising a penetrator passageway extending between a penetrator top end and a penetrator bottom end; and a production port comprising a production passageway extending between a production top end defined in a raised neck member extending from a top surface of the tubing hanger and a production bottom end, the production passageway comprising a bottom connection at the production bottom end that is configured to couple with an end of a production tubing to be landed in a tubing head of a well head, the production passageway comprising a top connection at the production top end that is different than the bottom connection and that is configured to couple with an end of the landing tool.

18. The method of claim 17, wherein the production tubing comprises an outer diameter of greater than 3.25 inches and less than 3.75 inches and the tubing hanger comprises an outer diameter that 7 inches or less, wherein the top connection and the end of the landing tool comprise non-tapered threading.

19. The method of claim 18, wherein the non-tapered threading comprises a trapezoidal thread configuration.

20. The method of claim 17, wherein a ratio of outer diameters of the production tubing to the tubing hanger is about 0.50.