Tubing Hanger for Wellbore Systems

The present application claims priority to U.S. Provisional Patent Application No. 63/647,767 filed May 15, 2024 entitled “Hangar Assemblies for Wellbore Systems,” which is incorporated herein by reference in its entirety as set forth in full.

Hydrocarbon recovery operations often include drilling of a wellbore into the earth's surface to reach a hydrocarbon reservoir. The wellbore is typically then lined with casing and may be perforated adjacent to the reservoir formation. Production tubing may then be lowered into the wellbore to assist with recovery operations.

Hangers (e.g., casing hanger, tubing hanger) are often used within a receptacle (sometimes referred to as a “bowl” of a head (e.g., casing head, tubing head, wellhead) at the wellsite to suspend casing or tubing within a wellbore. Hangers may also be installed with or without casing or tubing suspended therefrom, such that they function as standalone barriers, making it crucial to securely anchor the hanger within the head. When suspending casing or tubing, hangers may center the casing or tubing, provide a primary seal in the casing annulus, create an annular space, and permit testing of wellhead system connections. Traditional methods of securing the hanger to a head involve the use of a number of lock screws embedded through the head or wellhead flange, with their pointed ends engaging grooves embedded within the hanger. Generally, a large number of lock screws are required to provide for adequate securement of these components. With each lock screw, there is a hole bored into the head, which increases the number of potential leak points given the high pressure and weight load required by these components. Additionally, these hanger systems can be complex given that each lock screw requires gland nuts and packing seals to prevent fluid leakage past each of the lock screws.

A hanger system is needed that can secure a hanger (e.g., casing hanger, tubing hanger) to a head (e.g., casing head, tubing head, wellhead) without requiring a large number of lock screws.

According to one aspect of the subject matter, the present disclosure relates to a hanger assembly that may include a cylindrical body including a top end, a bottom end, an outside surface, and a bore defined therethrough forming an inside surface. The hanger assembly may include an electrical penetrator port running from the top end to the bottom end and configured to enclose an electrical penetrator as it runs through the hanger assembly. The hanger assembly may include a lock ring, the lock ring including: (i) an annular shape having an upper end that may be closest to the top end of the cylindrical body and a lower end that may be closest to the bottom end of the cylindrical body; (ii) an inside surface that contacts a portion of the outside surface of the cylindrical body; and (iii) an outside surface having a diameter that may be greatest at the lower end and smallest at the upper end. In some embodiments, the lock ring may be configured to fit within a load shoulder of a head. The hanger assembly may include a tapered piston seal ring located at the upper end of the lock ring. The tapered piston seal ring may include an annular shape having an upper end that may be closest to the top end of the cylindrical body and a lower end that partially fits into a space between the inside surface of the lock ring and the outside surface of the cylindrical body. The hanger assembly may include a stationary seal having an annular shape having an upper end that may be closest to the top end of the cylindrical body and a lower end that seats against the upper end of the tapered piston seal ring.

According to some embodiments, a wellhead assembly may include a head including (i) a cylindrical body having a hollowed interior and including a top end, a bottom end, an outside surface, and an inside surface; and (ii) an upper flange area located at the top end of the cylindrical body. The upper flange area may include (A) a first threaded port hole running from the outside surface to the inside surface and configured to threadably connect to a threaded fitting, wherein the first threaded port hole may be oriented at an about 90° angle with respect to the hollowed interior of the cylindrical body; a second threaded port hole running from the outside surface to the inside surface and configured to threadably connect to a lockdown screw, wherein the first threaded port hole may be oriented at an angle ranging from about 10° to about 80° with respect to the hollowed interior of the cylindrical body; and a load shoulder located along the inside surface of the cylindrical body and including a diameter that may be greater than a diameter of the inside surface of the cylindrical body. The wellhead assembly may include (b) a hanger assembly including: (i) a cylindrical body including a top end, a bottom end, an outside surface, and a bore defined therethrough forming an inside surface; (ii) an electrical penetrator port running from the top end to the bottom end and configured to enclose an electrical penetrator as it runs through the hanger assembly; and (iii) a lock ring. The lock ring may include an annular shape having an upper end that may be closest to the top end of the cylindrical body and a lower end that may be closest to the bottom end of the cylindrical body; an inside surface that contacts a portion of the outside surface of the cylindrical body; and an outside surface having a diameter that may be greatest the lower end and smallest at the upper end. In some embodiments, the lock ring may be configured to fit within the load shoulder of the head. The hanger assembly may include (iv) a tapered piston seal ring located at the upper end of the lock ring. The tapered piston seal ring may include an annular shape having an upper end that may be closest to the top end of the cylindrical body and a lower end that partially fits into a space between the inside surface of the lock ring and the outside surface of the cylindrical body. The hanger assembly may include (v) a stationary seal including an annular shape, an upper end that may be closest to the top end of the cylindrical body, and a lower end that seats against the upper end of the tapered piston seal ring.

The present disclosure relates to a wellhead system including a head (e.g., casing head, tubing head, wellhead) and a hanger (e.g., casing hanger, tubing hanger) assembly having a lock ring that secures and seals the head to the hanger assembly. Since wellhead systems disclosed herein do not require lock screws (or pins) to secure the head to the hanger assembly, the systems disclosed herein advantageously avoid having a large number of potential leak points contained in conventional systems. In some embodiments, the lock ring of systems disclosed herein may be engaged when the system is “energized” by initiating a flow of hydraulic fluid through the system. Similarly, the lock ring of systems disclosed herein may be disengaged by stopping the flow of hydraulic fluid. Being able to readily engage and disengage the securement and sealing of the hanger assembly to the head in a single step is a significant advantage over conventional systems that require a large number of lock screws to be individually fastened or removed. Systems disclosed herein may also include a threaded port hole that advantageously provides a user with the ability to easily verify that the head is properly secured to the hanger assembly, which is not available in conventional systems.

is a side view of a wellhead systemaccording to the present disclosure that does not require lock screws to secure its head (e.g., casing head, tubing head, wellhead) to its hanger assembly. Conventional wellhead systems may require from 4-12 lock screws that each require a packing seal and a gland nut. If any of these packing seals, gland nuts, or lock screws fail, then the system will leak, leading to significant wellsite downtime to diagnose and fix the problem.

With reference again to, a hanger assemblyaccording to the present disclosure is shown positioned within an upper portion of a tubing head. The tubing headforms generally part of the wellhead assembly. As will be described further herein, the hanger assemblydoes not require lock screws (also referred to as “pins”) to secure to the tubing head.

In some embodiments, the tubing headmay be made of any steel. For example, the tubing headmay be made of an alloy steel, a stainless steel, a carbon steel, a vanadium steel alloy, a tungsten alloy, a silicon steel alloy, a low carbon steel, a maraging steel, an austenitic steel, a cobalt steel alloy, a titanium steel alloy, a chromium steel alloy, a manganese steel alloy, a copper steel alloy, an aluminum steel alloy, a molybdenum steel alloy, a medium carbon steel, a high carbon steel, mixtures thereof, and alloys thereof.

Similarly, the hanger assemblymay be made of any steel. For example, the hanger assemblymay be made of an alloy steel, a stainless steel, a carbon steel, a vanadium steel alloy, a tungsten alloy, a silicon steel alloy, a low carbon steel, a maraging steel, an austenitic steel, a cobalt steel alloy, a titanium steel alloy, a chromium steel alloy, a manganese steel alloy, a copper steel alloy, an aluminum steel alloy, a molybdenum steel alloy, a medium carbon steel, a high carbon steel, mixtures thereof, and alloys thereof.

illustrates a side perspective view of the hanger assembly. The hanger assemblytakes the form of a cylindrical body that includes a hydraulic top sleevepositioned about an upper portion of the hanger assembly. A hydraulic press sleeveis positioned below the hydraulic top sleeve. The hydraulic press sleeveis adapted to engage a lock ringin order to seal the hanger assembly into the tubing headas will be described. The hanger assemblyfurther includes orifices extended downwardly therethrough, including a tubing portand penetrator portto accommodate penetrators, such as the Speed Feed® penetrator.

shows a cross-sectional view of the tubing headsecured to a hanger assemblythat has not been “energized” with hydraulic fluid. As discussed above, the wellhead systemmay include the tubing headand the hanger assembly. The tubing headincludes a cylindrical body having a hollowed interior. In some embodiments, instead of a tubing head, the head may be a casing head or a wellhead. The tubing head includes a top end, a bottom end, an outside surface, and an inside surface. The hollowed interior may be threaded and configured to couple to a casing string (not shown).

The tubing headmay include an upper flange arealocated at a top end of a cylindrical body. The upper flange areamay include a threaded port holerunning through the upper flange area. The threaded portmay be configured to threadably connect to a threaded fitting. In some embodiments, the threaded portmay be oriented at about a 90° angle with respect to the hollowed interior of the cylindrical body. The upper flange areamay include more than one threaded port hole. For example, the upper flange area may include from 2-4 threaded port holes. Not all threaded port holes are oriented at an angle of about 90° with respect to the hollowed interior of the cylindrical body. According to some embodiments, the upper flange areamay include a threaded port holethat is oriented at an angle ranging from about 10° to about 80° with respect to the hollowed interior of the cylindrical body. For example, the upper flange area may include the threaded port hole that is oriented at an angle of about 1°, or about 10°, or about 20° or about, 30° or about, 40° or about, 50° or about, 60° or about, 70° or about, 80° or about, 90° or about, with respect to the hollowed interior of the cylindrical body, where about includes plus or minus 5°. The threaded port hole(s)may be configured to threadably connect to a threaded fittingthat may permit a user to determine a status of a seal between the tubing headand the hanger assembly.

As shown in, the tubing headincludes a load shoulderlocated along an inside surface of the tubing head. The load shoulderhas a diameter that is greater than the diameter of the inside surface of the tubing head. In some embodiments, the threaded port holebegins from an outside surface of the tubing headand ends at the load shoulder. Having the threaded port holeleading to the load shouldermay advantageously permit a user to determine if the tubing headis properly forming a seal with the hanger assemblyby directly assessing a status of the lock ring, and whether hydraulic fluid is leaking.

The lock ringhas an annular shape having an upper end that is closest to a top end of the hanger assemblyand a lower end that is closest to a bottom end of the hanger assembly. The lock ringhas an inside surface that contacts a portion of the outside surface of the hanger assembly. The lock ringmay have an outside surface having a diameter that is greatest at the lower end of the lock ring and smallest at the upper end of the lock ring. In some embodiments, the lock ring is configured to fit within the load shoulderof the tubing head.

As shown in, when “energized” (as will be described) the lock ringmay compress and expand in diameter to substantially fill the space of the load shoulder, thereby forming a seal between the tubing headand the hanger assembly. The lock ringmay have any relative inside diameter and outside diameter to fit the disclosed purposes. The lock ringmay have a height ranging from about 0.1 inch to about 2 inches, or greater. For example, the lock ringmay have a height of about 0.1 inch, or about 0.5 inches, or about 1 inch, or about 1.5 inches, or about 2 inches, where about includes plus or minus 0.25 inches. The lock ringmay have an inside diameter ranging from about 1 inch to about 10 inches. For example, the locking ring may have an inside diameter of about 1 inch, or of about 2 inches, or of about 3 inches, or of about 4 inches, or of about 5 inches, or of about 6 inches, or of about 7 inches, or of about 8 inches, or of about 9 inches, or of about 10 inches, where about includes plus or minus 0.5 inches. The lock ringmay have an outside diameter ranging from about 2 inches to about 11 inches. For example, the lock ringmay have an outside diameter of about 2 inches, or of about 3 inches, or of about 4 inches, or of about 5 inches, or of about 6 inches, or of about 7 inches, or of about 8 inches, or of about 9 inches, or of about 10 inches, or of about 11 inches, where about includes plus or minus 0.5 inches.

The lock ringmay be made of a polymer including a polyethylene, a polystyrene, a polyurethane, a nylon, a polypropylene, a polyethylene terephthalate, a polymethylmethacrylate, a polyacrylonitrile, a polyvinyl chloride, a polycarbonate, a silicone, a polyester, mixtures thereof, and copolymers thereof.

As discussed previously, the hanger assemblyincludes the hydraulic press sleeve(which also may be referred to as a tapered piston seal ring). The tapered piston seal ringis located at the upper end of the lock ring. The tapered piston seal ringmay have an upper end that is closest to a top end of the hanger assemblyand a lower end that is adapted to contact the lock ring.

When the system is “energized,” (e.g., hydraulic pressure is applied), the tapered piston seal ringis pushed towards and into contact with the lock ringto compress the lock ring within the load shoulder, thereby substantially filling the space of the load shoulder to form a seal between the tubing headand the hanger assembly.

The tapered piston seal ringmay have any relative inside diameter and outside diameter to fit the disclosed purposes. The tapered piston seal ringmay have a height ranging from about 0.1 inch to about 6 inches, or greater. For example, the tapered piston seal ringmay have a height of about 0.1 inch, or about 1 inch, or about 2 inches, or about 4 inches, or about 6 inches, where about includes plus or minus 1 inch. The tapered piston seal ringmay have an inside diameter ranging from about 1 inch to about 10 inches. For example, the tapered piston seal ringmay have an inside diameter of about 1 inch, or of about 2 inches, or of about 3 inches, or of about 4 inches, or of about 5 inches, or of about 6 inches, or of about 7 inches, or of about 8 inches, or of about 9 inches, or of about 10 inches, where about includes plus or minus 1 inches. The tapered piston seal ringmay have an outside diameter ranging from about 2 inches to about 11 inches. For example, the tapered piston seal ringmay have an outside diameter of about 2 inches, or of about 3 inches, or of about 4 inches, or of about 5 inches, or of about 6 inches, or of about 7 inches, or of about 8 inches, or of about 9 inches, or of about 10 inches, or about 11 inches, where about includes plus or minus 0.5 inches.

The tapered piston seal ringmay be made of a polymer including a polyethylene, a polystyrene, a polyurethane, a nylon, a polypropylene, a polyethylene terephthalate, a polymethylmethacrylate, a polyacrylonitrile, a polyvinyl chloride, a polycarbonate, a silicone, a polyester, mixtures thereof, and copolymers thereof.

According to some embodiments, as shown in, the hanger assemblymay include the hydraulic top sleeve, which may also be referred to as a stationary seal ring. The stationary seal ringhas an annular shape with an upper end that is closest to the top end of the hanger assembly, and a lower end that seats against an upper end of the tapered piston seal ring. The stationary seal ring may provide for an upper seal area for the hydraulic fluid to “push against” in order for the piston seal ringto move downward. The stationary seal ringmay also act as a retention device for the tapered piston seal ring, and may act as a positive stop for the top of the tapered piston seal ring.

The stationary seal ringmay have any relative inside diameter and outside diameter to fit the discloses purposes. The stationary seal ringmay have a height ranging from about 0.1 inch to about 6 inches, or greater. For example, the stationary seal ring may have a height of about 0.1 inch, or about 1 inch, or about 2 inches, or about 4 inches, or about 6 inches, where about includes plus or minus 1 inch. The stationary seal ring may have an inside diameter ranging from about 1 inch to about 10 inches. For example, the stationary seal ring may have an inside diameter of about 1 inch, or of about 2 inches, or of about 3 inches, or of about 4 inches, or of about 5 inches, or of about 6 inches, or of about 7 inches, or of about 8 inches, or of about 9 inches, or of about 10 inches, where about includes plus or minus 1 inches. The stationary seal ring may have an outside diameter ranging from about 2 inches to about 11 inches. For example, the stationary seal ring may have an outside diameter of about 2 inches, or of about 3 inches, or of about 4 inches, or of about 5 inches, or of about 6 inches, or of about 7 inches, or of about 8 inches, or of about 9 inches, or of about 10 inches, or about 11 inches, where about includes plus or minus 0.5 inches.

Further, the stationary seal ringmay be made of a polymer including a polyethylene, a polystyrene, a polyurethane, a nylon, a polypropylene, a polyethylene terephthalate, a polymethylmethacrylate, a polyacrylonitrile, a polyvinyl chloride, a polycarbonate, a silicone, a polyester, mixtures thereof, and copolymers thereof.

In practice, the hanger assemblyis landed into the tubing headas shown inuntil it rests on a load surfaceof the tubing head. As shown, tubing stringis positioned within the hanger assembly. Upon being positioned within the tubing head, the hanger assemblymay then be actuated to engage the tubing head in a sealing arrangement by pumping hydraulic fluid to cause the tapered piston seal ringto push the lock ringdownward into the space defined by the load shoulderas further described above with respect toand B. In the depicted arrangement of, in an unenergized state, the tapered piston seal ringis disposed above the lock ringwith a tip of the tapered piston seal ring in contact with or slightly displaced from an inner surface of the lock ring. Once energized, and as shown more clearly in, the tapered piston seal ringis actuated downwardly (via hydraulic fluid) such that the tapered portion of the tapered piston seal ringpushes the lock ringinto the load shoulderto form the seal. In this sealing arrangement, the tapered piston seal ringis positioned in a space between the inside surface of the lock ringand the outside surface of the hanger assembly.

When it is desired to remove the hanger assemblyfrom the tubing head, a bleeder tool (not shown) may be attached to port(see) to release pressure, thereby disengaging the lock ringfrom its sealing position. Further, a test pump (not shown) may be attached to the port hole(see) to pump pressure (e.g., 1,000 psi) further disengaging the lock ring. At this point, the hanger assemblymay be removed from the tubing head.

The figures and descriptions provided herein may have been simplified to illustrate aspects that are relevant for a clear understanding of the herein described devices, systems, and methods, while eliminating, for the purpose of clarity, other aspects that may be found in typical similar devices, systems, and methods. Those of ordinary skill may recognize that other elements and/or operations may be desirable and/or necessary to implement the devices, systems, and methods described herein. But because such elements and operations are well known in the art, and because they do not facilitate a better understanding of the present disclosure, a discussion of such elements and operations may not be provided herein. However, the present disclosure is deemed to inherently include all such elements, variations, and modifications to the described aspects that would be known to those of ordinary skill in the art.

The terminology used herein is for the purpose of describing particular example embodiments only and is not intended to be limiting. For example, as used herein, the singular forms “a”, “an” and “the” may be intended to include the plural forms as well, unless the context clearly indicates otherwise. The terms “comprises,” “comprising,” “including,” and “having,” are inclusive and therefore specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. The method steps, processes, and operations described herein are not to be construed as necessarily requiring their performance in the particular order discussed or illustrated, unless specifically identified as an order of performance. It is also to be understood that additional or alternative steps may be employed.

Although the terms first, second, third, etc., may be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms. These terms may be only used to distinguish one element, component, region, layer or section from another element, component, region, layer, or section. That is, terms such as “first,” “second,” and other numerical terms, when used herein, do not imply a sequence or order unless clearly indicated by the context. Reference in the specification to “one implementation” or “an implementation” means that a particular feature, structure, or characteristic described in connection with the implementation is included in at least one implementation of the disclosure. The appearances of the phrase “in one implementation,” “in some implementations,” “in one instance,” “in some instances,” “in one case,” “in some cases,” “in one embodiment,” or “in some embodiments” in various places in the specification are not necessarily all referring to the same implementation or embodiment.

Finally, the above descriptions of the implementations of the present disclosure have been presented for the purposes of illustration and description. It is not intended to be exhaustive or to limit the present disclosure to the precise form disclosed. Many modifications and variations are possible considering the above teaching. It is intended that the scope of the present disclosure be limited not by this detailed description, but rather by the claims of this application. As will be understood by those familiar with the art, the present disclosure may be embodied in other specific forms without departing from the spirit or essential characteristics thereof. Accordingly, the present disclosure is intended to be illustrative, but not limiting, of the scope of the present disclosure, which is set forth in the following claims.