TUBING HEAD WITH INSTALLABLE SHOULDER

FIELD OF THE INVENTION

The present disclosure relates generally to wellhead systems used in oil and gas applications. More particularly, the present disclosure relates to a tubing head to support casing during wellbore operations.

BACKGROUND

In exploration and production of formation minerals, such as oil and gas, wellbores may be drilled into an underground formation. The wellbores may be cased wellbores where a casing (or tubular piping string) is positioned against a wall of the borehole, where cement may be injected to secure the casing string to the formation. A casing string is typically supported at its upper end by a casing hanger, which is located (or landed) within a wellhead at the surface. At the lower end, the casing string is connected to the wellbore via this long strand of pipes that connect the pressurized well to the surface.

In oil and gas production, wellhead control is required to safely install components, test the components of a system, control back pressure from the well, and ultimately produce oil and gas from a well. Multiple different valves and pressure regulating systems are used in typical installations to support the safe production of oil and gas. Typically, various sealing mechanisms are used to protect the installation of the top side well control system that will ultimately support production, workovers and other operations on the well.

SUMMARY

The disclosed subject matter relates to wellhead systems. In certain embodiments, a tubing head is disclosed that comprises a tubing head body defining a bore extending longitudinally between a first end and a second end, the bore defining a cavity portion disposed longitudinally between a first portion of the bore and a second portion of the bore, wherein the cavity portion has a cavity diameter greater than a first diameter of the first portion of the bore; and an installable shoulder comprising a plurality of shoulder segments configured to be installed within the cavity portion and collectively form an annular ring, wherein the annular ring defines a bearing surface configured to support a wellhead component and the annular ring further defines a shoulder diameter less than the cavity diameter and greater than the first diameter of the first portion of the bore.

In certain embodiments, a method to isolate a wellbore is disclosed that comprises introducing a casing isolation plug into the wellbore through a wellhead housing; introducing a shoulder into the tubing head; coupling a tubing head to the wellhead housing; and retrieving the casing isolation plug through a bore of the tubing head and an inner diameter of the shoulder.

In certain embodiments, a wellhead system is disclosed that comprises a wellhead housing; a tubing head coupled to the wellhead housing, the tubing head comprising: a tubing head body defining a bore in fluid communication with the wellhead housing and extending longitudinally between a first end and a second end; and an installable shoulder disposed within the bore; and a wellhead component disposed within the bore of the tubing head and supported by the installable shoulder.

It is understood that various configurations of the subject technology will become readily apparent to those skilled in the art from the disclosure, wherein various configurations of the subject technology are shown and described by way of illustration. As will be realized, the subject technology is capable of other and different configurations and its several details are capable of modification in various other respects, all without departing from the scope of the subject technology. Accordingly, the summary, drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are included to provide further understanding and are incorporated in and constitute a part of this specification, illustrate disclosed embodiments and together with the description serve to explain the principles of the disclosed embodiments. In the drawings:

FIG. 1 is a partial cross-sectional view of a production wellhead assembly.

FIG. 2 is a partial cross-sectional view of a tubing head of the wellhead assembly of FIG. 1.

FIG. 3 is a partial cross-sectional view of a load shoulder of the tubing head of FIG. 2.

FIG. 4 is a top elevation view of the load shoulder of FIG. 3.

FIG. 5 is a perspective view of a segment of the load shoulder of FIG. 4.

FIG. 6 is a partial cross-sectional view of a frac tie back wellhead assembly.

FIG. 7 is a partial cross-sectional view of a tubing head of the wellhead assembly of FIG. 6.

FIG. 8 is a partial cross-sectional view of a load shoulder of the tubing head of FIG. 7.

FIG. 9 is a top elevation view of the load shoulder of FIG. 8.

FIG. 10 is a perspective view of a segment of the load shoulder of FIG. 9.

FIG. 11 is a partial cross-sectional view of a wellhead assembly with a casing isolation plug.

FIG. 12 is a partial cross-sectional view of a wellhead assembly with a temporary abandonment cap.

DETAILED DESCRIPTION

The disclosed tubing head incorporates a bore and an installable shoulder. The bore of the tubing head and inner diameter of the installable shoulder can allow for the passage of components, such as a casing isolation plug or other components, while also allowing for the support of wellhead components, such as a tubing hanger or a tie back hanger. By utilizing an installable shoulder, relatively large diameter components can be removed through the bore of the tubing head and inner diameter of the installable shoulder, while relatively small diameter components can be supported by the shoulder installed in the bore of the tubing head, increasing the safety and simplifying the process or workflow to prepare a wellbore for fracturing or production operations.

The detailed description set forth below is intended as a description of various configurations of the subject technology and is not intended to represent the only configurations in which the subject technology may be practiced. The detailed description includes specific details for the purpose of providing a thorough understanding of the subject technology. However, it will be apparent to those skilled in the art that the subject technology may be practiced without these specific details. In some instances, well-known structures and components are shown in block diagram form in order to avoid obscuring the concepts of the subject technology. Like components are labeled with identical element numbers for ease of understanding. Reference numbers may have letter suffixes appended to indicate separate instances of a common element while being referred to generically by the same number without a suffix letter.

While the following description is directed to the removal of casing isolation plugs in connection with fracturing and production operations using the disclosed wellhead system, it is to be understood that this description is only an example of usage and does not limit the scope of the claims. Various aspects of the disclosed wellhead system may be used in any application where it is desirable to remove a component from a downhole location with a simplified or safer process.

During certain conventional operations, a back pressure valve (“BPV”) can be installed in the casing string after drilling is complete to remove components from the wellsite before production tubing and production equipment, such as the tubing head and Christmas tree elements can be installed. In some applications, this procedure can include the removal of the blow out preventer (“BOP”) and other components from the wellhead prior to installation of the production equipment. During certain conventional removal operations, a mechanical barrier is installed to ensure that the well pressure is not released. In some applications, it is required to have double barriers (double block system) to maintain well pressure and safety of the well.

The disclosed wellhead system overcomes several challenges discovered with respect to certain conventional wellhead systems. In some applications, a bridge plug may be utilized to provide a pressure barrier. One challenge with the use of certain conventional bridge plugs is that wireline personnel and equipment may be required to install and remove the bridge plug. In certain conventional applications, a BPV is installed in the casing string to mechanically seal the components on the wellhead, providing a first barrier or block against well pressure. In some applications, a cemented barrier in the toe of the well can provide a secondary barrier or block against well pressure. One challenge with certain conventional wellhead systems, is that certain BPVs cannot be retrieved through a tubing head during the removal process, because the bore of the tubing head and/or the inner diameter of the shoulder is smaller than the outer diameter of the BPV. Therefore, certain conventional wellhead systems require that the BPV is removed prior to installation of the tubing head, creating time consuming, complex, and expensive operations and removing one of the barriers or blocks against well pressure. In some applications, performing operations with a single barrier may lead to reduced well control, unsafe conditions, or well failure, and may require additional pressure testing procedures. In some applications, the bore of the tubing head may be increased in size to allow BPVs or other components to be retrieved. However, one challenge with increasing the size of the tubing head bore is that an increased inner diameter may reduce the wall thickness or bearing surface of the integrated shoulder to support components, such as tubing hangers, which may reduce the overall load capacity of the tubing head, or may require additional load testing to confirm the load capabilities of the tubing head.

Therefore, in recognition of the limitations of certain conventional wellhead systems and in accordance with the present disclosure, it is advantageous to provide a wellhead system as described herein that allows for components, such as the BPV or casing plug to stay in place during installation of the tubing head to maintain isolation via multiple (e.g., two) barriers and maintain control of the well, avoiding the need to test the well below the plug. Further, it is advantageous to provide a tubing head with a bore and installable shoulder with an inner diameter that is large enough to allow components, such as the BPV or casing plug to be retrieved through the bore or inner diameter without the need for specialized equipment. Additionally, it is advantageous to provide a tubing head with an installable shoulder to support additional components, such as a tubing hanger or a tie back hanger, avoiding the need to perform additional testing or certification of the tubing head.

Examples of wellhead systems that allow components to be removed through the tubing head to maintain isolation are now described.

FIG. 1 is a partial cross-sectional view of a production wellhead assembly 100. With reference to FIG. 1, in the depicted example, the production wellhead assembly 100 can facilitate and control the flow of production fluids (e.g., oil and gas) out of a formation. As described herein, the production wellhead assembly 100 can be installed at a wellsite after a drilling operation or a fracturing operation.

As illustrated, the wellhead 110 can be installed on conductor pipe 102a and support other components of the production wellhead assembly 100. In some embodiments, the conductor pipe 102a can be 20 inch conductor pipe. As illustrated, formation fluids can flow through casing 102b extending through the wellhead 110. In some applications, the casing 102b can be 10¾ inch casing. Further, in some embodiments, formation fluids can flow through casing 102c extending through the wellhead housing 110. In some applications, the casing 102c can be 7⅝ inch casing. Optionally, the production wellhead assembly 100 can be utilized with an electrical submersible pump (ESP) via the casing 102c.

In the depicted example, production tubing 102d can be supported by a tubing head 120. As illustrated, the tubing head 120 can be coupled to the wellhead 110 via a flange. As described herein, the tubing head 120 can have a bore that allows for isolating components, such as a back pressure valve or a casing isolation plug to be retrieved through the tubing head 120. In some applications, the production tubing 102d can be 2⅞ inch casing or tubing.

As illustrated, a production tree 130 can control the flow of formation fluid from the wellbore. The production tree 130 can include one or more valves or other flow control devices to control flow and pressure of fluid through the production wellhead assembly 100. In some applications, the production tree 130 can be coupled to the tubing head 120 via a flange.

FIG. 2 is a partial cross-sectional view of a tubing head 120 of the wellhead assembly 100 of FIG. 1. With reference to FIGS. 1 and 2, the tubing head 120 supports a tubing hanger 150, which in turn supports the production tubing 102d in the wellbore. In the depicted example, the tubing hanger 150 is coupled to the production tubing 102d. In some applications, the production tubing 102d can extend great distances within the wellbore and apply significant load on the tubing hanger 150, and in turn the tubing head 120. During operation, the production tubing 102d and the tubing hanger 150 can be inserted into the bore 122 of the tubing head 120. As illustrated, the bore 122 of the tubing head 120 can extend longitudinally between the ends of the tubing head 120.

FIG. 3 is a partial cross-sectional view of a load shoulder 140 of the tubing head 120 of FIG. 2. FIG. 4 is a top elevation view of the load shoulder 140 of FIG. 3. With reference to FIGS. 2-4, the tubing hanger 150 can be positioned and supported within the bore 122 of the tubing head 120 by an installable load shoulder 140. In some embodiments, the load shoulder 140 can transfer load from the tubing hanger 150 (and the associated production tubing 102d) to the tubing head 120. In the depicted example, the load shoulder 140 is shaped as an annular ring. In some applications, the load shoulder 140 can be any suitable shape. Advantageously, the use of the installable load shoulder 140 allows for increased load carrying capacity by providing a load shoulder 140 with optimized material yield strength and bearing area, avoiding the need for qualitative testing of the load shoulder 140, while allowing for relatively large components to pass through the bore 122 of the tubing head 120.

In conventional tubing heads, the shoulder supporting the load from the tubing hanger is formed integrally with the tubing head. Tubing heads are typically manufactured using a steel with relatively low yield strength. Accordingly, when the shoulder is formed from such a material, it generally must have a relatively large surface area to support the weight of the tubing string. A large shoulder reduces the diameter of the bore through the tubing head, which limits the operator's ability to remove components such as the back pressure valve or casing plug after the tubing head has been installed. Alternatively, a relatively small shoulder may be used, but such a design may be subject to failure due to the weight of the tubing string. Even if the shoulder does not fail, repeated testing is required to ensure continued structural soundness. The installable load shoulder 140 of the present invention resolves both of these issues because a relatively small shoulder may be manufactured using a steel with a much higher yield strength.

As illustrated, the load shoulder 140 includes one or more bearing surfaces 142 to support the tubing hanger 150. In the depicted example, the bearing surfaces 142 can engage with mating surfaces 152 of the tubing hanger 150 to transfer load from the tubing hanger 150 to the tubing head 120. In some embodiments, the bearing surface 142 of the load shoulder 140 can be angled or beveled relative to the bore 122 or longitudinal axis of the tubing head 120 to self-align with the tubing hanger 150. The mating surfaces 152 of the tubing hanger 150 can have a similar angle or bevel. Advantageously, the installable configuration of the load shoulder 140 allows the load shoulder 140 to provide a larger bearing surface 142 relative to certain conventional load shoulders that are integrated in the tubing head to allow for increased load capacity while allowing for relatively large diameter items to pass through the bore 122 of the tubing head 120.

In the depicted example, an inner diameter 149 of the load shoulder 140 can be large enough to allow isolation components, such as a casing isolation plug and/or a back pressure valve to pass through the inner diameter 149 of the load shoulder 140. In some applications, the inner diameter 149 can be drift compatible with 7⅝″ casing, or otherwise have an inner diameter that is the same or similar to the inner diameter of 7⅝″ casing that may be typically suitable for use with ESP operations, such as casing 102c. In some embodiments, the inner diameter 149 of the load shoulder 140 can be greater than or equal to 6½ inches. Advantageously, the embodiments described herein allow for a relatively large inner diameter without increasing the outer diameter or envelope of the load shoulder 140. Further, the inner diameter 149 of the load shoulder 140 can allow production tubing 102d and/or portions of the tubing hanger 150 to pass therethrough.

In the depicted example, the load shoulder 140 is supported within the bore 122 of the tubing head 120. As illustrated, the load shoulder 140 is positioned and supported by a cavity 124 defined within the bore 122 of the tubing head 120. In some embodiments, an outer diameter 144 of the load shoulder 140 is disposed within the cavity 124. During operation, a radial surface 126 of the cavity 124 can support a radial load from a mating radial surface 146 of the load shoulder 140. Similarly, an axial surface 128 of the cavity 124 can support an axial load from a mating axial surface 148 of the load shoulder 140. In some applications, the load applied from the tubing hanger 150 and/or production tubing 102d on the angled bearing surface 142 can result in both an axial and radial load against the cavity 124 and the tubing head 120.

As illustrated, the cavity 124 is disposed between a first portion of the bore 122, above the cavity 124, and a second portion of the bore 122, below the cavity 124. In some embodiments, the diameter of the cavity 124 is greater than the inner diameter of the first portion of the bore 122. In some embodiments, the diameter of the cavity 124 is greater than the inner diameter of the second portion of the bore 122. Optionally, the inner diameter of the first portion of the bore 122 above the cavity 124 is greater than the inner diameter of the second portion of the bore 122 below the cavity 124.

In the depicted example, the outer diameter 144 of the load shoulder 140 is less than the inner diameter of the cavity 124. Optionally, the outer diameter 144 of the load shoulder 140 is greater than the inner diameter of the first portion of the bore 122. Further, the outer diameter 144 of the load shoulder 140 can be greater than the inner diameter of the second portion of the bore 122.

In the depicted example, the inner diameter of the bore 122, including both the portion above the cavity 124 and the portion below the cavity 124 can have an inner diameter large enough to allow isolation components, such as a casing isolation plug and/or a back pressure valve to pass through the bore 122 of the tubing head 120. In some applications, the inner diameter of the bore 122 can have a diameter that is drift compatible with 7⅝″ casing, or otherwise have an inner diameter that is the same or similar to the inner diameter of 7⅝″ casing that may be typically suitable for use with ESP operations, such as casing 102c. In some embodiments, the inner diameter of the bore 122 can be greater than or equal to 6½ inches. Advantageously, the embodiments described herein allow for a relatively large inner diameter without increasing the outer diameter or envelope of the tubing head 120 or the wellhead assembly 100 overall.

FIG. 5 is a perspective view of a segment 140a of the load shoulder 140 of FIG. 4. With reference to FIGS. 4 and 5, in the depicted example, the load shoulder 140 is a separate component that can be installed in the cavity 124 within the tubing head 120. As illustrated, the load shoulder 140 can be formed from two or more segments 140a, 140b, 140c that can be collectively assembled to form the load shoulder 140. During operation, the segments 140a, 140b, 140c can be inserted into the bore 122 of the tubing head 120 and assembled within the cavity 124 to collectively form the load shoulder 140. In some embodiments, the segments 140a, 140b, 140c can be assembled to form an annular ring shape. Optionally, the segments 140a, 140b, 140c can each be 30 degree, 60 degree, 90 degree, 120 degree, or 180 degree segments of an annular ring shape. Advantageously, by assembling multiple smaller segments 140a, 140b, 140c within the bore 122, a load shoulder 140 with an outer diameter 144 larger than the inner diameter of the bore 122 can be installed within the tubing head 120. Further, in some applications, the load shoulder 140 can be removed from the cavity 124 to facilitate replacement of the load shoulder 140, increase access to the bore 122 to remove downhole components such as the casing isolation plug and/or the back pressure valve, or for other operations.

In the depicted example, the load shoulder 140 is formed from any suitable material that allows the load shoulder 140 to support the load of the tubing hanger 150 and the coupled production tubing 102d. In some embodiments, the load shoulder 140 is formed from a metal with a high yield or tensile strength. For example, the load shoulder 140 can be formed from steel with a tensile strength in excess of 120 kilopounds per square inch (ksi), in excess of 150 ksi, or greater. As noted above, by utilizing a suitable material for the load shoulder 140, the load shoulder 140 can support the tubing hanger 150 without requiring qualitative testing of the load shoulder 140.

In some embodiments, the load shoulder 140 is formed from a material that is different than the material of the tubing head 120. Optionally, the load shoulder 140 is formed from a material with a tensile strength that is higher than the material of the tubing head 120. In some applications, the load shoulder 140 can be formed from a material that may be difficult, impractical, and/or costly to use for the entire tubing head 120.

FIG. 6 is a partial cross-sectional view of a frac tie back wellhead assembly 200. In some embodiments, certain features of the frac tie back wellhead assembly 200 are similar to the features of the production wellhead assembly 100 and therefore may be referred to with the same reference numbers.

With reference to FIG. 6, in the depicted example, the frac tie back wellhead assembly 200 can facilitate and control fracturing operations, including, but not limited to the flow of fracturing fluid and proppant in and out of a formation. As described herein, the frac tie back wellhead assembly 200 can be installed at a wellsite after a drilling operation. In the depicted example, frac casing 202d can be supported by a tubing head 120. In some applications, the frac casing 202d can be 5½ inch casing. As illustrated, a frac adapter 230 can control the flow of fracturing fluid to and from the wellbore. The frac adapter 230 can include one or more valves or other flow control devices to control flow and pressure of fluid and proppant through the frac tie back wellhead assembly 200.

FIG. 7 is a partial cross-sectional view of a tubing head 120 of the wellhead assembly 200 of FIG. 6. With reference to FIGS. 6 and 7, the tubing head 120 supports a tie back hanger 250, which in turn supports the frac casing 202d in the wellbore. In the depicted example, the tie back hanger 250 is coupled to the frac casing 202d. In some applications, the frac casing 202d can extend great distances within the wellbore and apply significant load on the tie back hanger 250 and in turn the tubing head 120. During operation, the frac casing 202d and the tie back hanger 250 can be inserted into the bore 122 of the tubing head 120.

FIG. 8 is a partial cross-sectional view of a load shoulder 240 of the tubing head 120 of FIG. 7. FIG. 9 is a top elevation view of the load shoulder 240 of FIG. 8. With reference to FIGS. 7-9, the tie back hanger 250 can be positioned and supported within the bore 122 of the tubing head 120 by an installable load shoulder 240. In some embodiments, the load shoulder 240 can transfer load from the tie back hanger 250 (and the associated frac casing 202d) to the tubing head 120. In the depicted example, the load shoulder 240 is shaped as an annular ring. In some applications, the load shoulder 240 can be any suitable shape. As illustrated, the load shoulder 240 can have a geometry that complements or otherwise correspond with the geometry of the tie back hanger 250. In some embodiments, since the geometry of the tie back hanger 250 can differ from the geometry of tubing hanger 250, the load shoulder 240 may have a geometry or profile that differs from load shoulder 140.

As illustrated, the load shoulder 240 includes one or more bearing surfaces 242 to support the tie back hanger 250. In the depicted example, the bearing surfaces 242 can engage with mating surfaces 252 of the tie back hanger 250 to transfer load from the tie back hanger 250 to the tubing head 120. In some embodiments, the bearing surface 242 of the load shoulder 240 can be angled or beveled relative to the bore 122 or longitudinal axis of the tubing head 120 to self-align with the tie back hanger 250. The mating surfaces 252 of the tie back hanger 250 can have a similar angle or bevel.

In the depicted example, an inner diameter 249 of the load shoulder 240 can be large enough to allow isolation components, such as a casing isolation plug and/or a back pressure valve to pass through the inner diameter 249 of the load shoulder 240. In some applications, the inner diameter 249 can be drift compatible with 7⅝″ casing, or otherwise have an inner diameter that is the same or similar to the inner diameter of 7⅝″ casing that may be typically suitable for use with ESP operations, such as casing 102c. In some embodiments, the inner diameter 249 of the load shoulder 240 can be greater than or equal to 6½ inches. Advantageously, the embodiments described herein allow for a relatively large inner diameter without increasing the outer diameter or envelope of the load shoulder 240. Further, the inner diameter 249 can allow frac casing 202d and/or portions of the tie back hanger 250, such as the hanger extension 259 to pass therethrough.

In the depicted example, the load shoulder 240 is supported within the bore 122 of the tubing head 120. As illustrated, the load shoulder 240 is positioned and supported by a cavity 124 defined within the bore 122 of the tubing head 120. In some embodiments, an outer diameter 244 of the load shoulder 240 is disposed within the cavity 124. In the depicted example, the outer diameter 244 of the load shoulder 240 is less than the inner diameter of the cavity 124.

FIG. 10 is a perspective view of a segment 240a of the load shoulder 240 of FIG. 9. With reference to FIGS. 9 and 10, in the depicted example, the load shoulder 240 is a separate component that can be installed from the cavity 124 within the tubing head 120. As illustrated, the load shoulder 240 can be formed from two or more segments 240a, 240b, 240c that can be collectively assembled to form the load shoulder 240.

FIG. 11 is a partial cross-sectional view of a wellhead assembly 300 with a casing isolation plug 362. As described herein, isolation components, such as the casing isolation plug 362 and/or the back pressure valve 364 can be introduced into the wellbore through the wellhead 110 to maintain wellbore isolation after drilling operations. In some embodiments, the casing isolation plug 362 and/or the back pressure valve 364 can be utilized in conjunction with an additional seal or barrier to allow for multiple barriers. Optionally, the casing isolation plug 362 and/or the back pressure valve 364 can be disposed within a casing isolation bushing 360.

After installing the isolation components and prior to resuming well operations, the tubing head 120 can be installed or otherwise attached to the wellhead 110. In accordance with embodiments described herein, isolation components, such as the casing isolation plug 362 and/or the back pressure valve 364 can be retrieved through the bore 122 of the tubing head 120, including the inner diameter 149 of the load shoulder 140. In some embodiments, the isolation components can be removed by a rig or a removal tool lanced through the bore 122 of the tubing head 120. In some operations, the back pressure valve 364 and/or the casing isolation plug 362 can be removed from the wellbore and wellhead system 300.

Advantageously, since isolation components such as the casing isolation plug 362 and/or the back pressure valve 364 can be removed after the tubing head 120 is installed on the wellhead 110, operators can avoid removing isolation components prior to the installation of the tubing head 120 or avoid removing an installed tubing head 120 to remove the isolation components.

After the isolation components are retrieved, a tie back hanger 250 or a tubing hanger 150 along with the corresponding tubing can be introduced into the bore 122 of the tubing head 120 to be supported by the load shoulder 140 to begin fracturing and/or production operations.

FIG. 12 is a partial cross-sectional view of a wellhead assembly 400 with a temporary abandonment cap 470. In some applications, the well site can be temporarily abandoned after installing isolation components, such as the casing isolation plug 362 and/or the back pressure valve 364. In some embodiments, a temporary abandonment cap 470 can be coupled to the wellhead 110. Optionally, the temporary abandonment cap 470 can utilize elastomer seals. Advantageously, by utilizing elastomer seals, the temporary abandonment cap 470 can be installed without preloading, allowing the temporary abandonment cap 470 to be installed relatively quickly with less effort compared to certain conventional devices.

In some embodiments, the temporary abandonment cap 470 can include one or more ports 474a, 474b, 474c to test the integrity of seals within the wellhead assembly 400 without removing the temporary abandonment cap 470. In the depicted example, the ports 474a, 474b, 474c are in fluid communication with various sealed volumes to test the integrity of seals associated with those volumes. Advantageously, prior to resuming operations, a technician can be deployed to the wellsite with minimal equipment and test the integrity of downhole seals via ports 474a, 474b, 474c of the temporary abandonment cap 470. In some applications, the temporary abandonment cap 470 can be removed and a tubing head can be installed after a successful test. Advantageously, the well can be tested and prepared for fracturing operations or production operations without comprising isolation of the well.

The present disclosure is provided to enable any person skilled in the art to practice the various aspects described herein. The disclosure provides various examples of the subject technology, and the subject technology is not limited to these examples. Various modifications to these aspects will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other aspects.

Various examples of aspects of the disclosure are described as numbered clauses (1, 2, 3, etc.) for convenience. These are provided as examples, and do not limit the subject technology. Identifications of the figures and reference numbers are provided below merely as examples and for illustrative purposes, and the clauses are not limited by those identifications.

Clause 1. A tubing head including: a tubing head body defining a bore extending longitudinally between a first end and a second end, the bore defining a cavity portion disposed longitudinally between a first portion of the bore and a second portion of the bore, wherein the cavity portion has a cavity diameter greater than a first diameter of the first portion of the bore; and an installable shoulder including a plurality of shoulder segments configured to be installed within the cavity portion and collectively form an annular ring, wherein the annular ring defines a bearing surface configured to support a wellhead component and the annular ring further defines a shoulder diameter less than the cavity diameter and greater than the first diameter of the first portion of the bore.

Clause 2. The tubing head of Clause 1, wherein the cavity diameter is greater than a second diameter of the second portion of the bore.

Clause 3. The tubing head of Clause 1, wherein the tubing head includes an upper flange disposed at the first end and a lower flange disposed at the second end.

Clause 4. The tubing head of Clause 1, wherein the first diameter of the first portion of the bore is greater than 6½ inches.

Clause 5. The tubing head of Clause 4, wherein a second diameter of the second portion of the bore is greater than 6½ inches.

Clause 6. The tubing head of Clause 1, wherein the first diameter of the first portion of the bore is configured to permit a casing isolation plug to pass therethrough.

Clause 7. The tubing head of Clause 6, wherein a second diameter of the second portion of the bore is configured to permit the casing isolation plug to pass therethrough.

Clause 8. The tubing head of Clause 1, wherein the first diameter of the first portion of the bore is drift compatible with 7⅝ inch casing.

Clause 9. The tubing head of Clause 1, wherein each shoulder segment of the plurality of shoulder segments is less than or equal to a 180 degree segment of the annular ring.

Clause 10. The tubing head of Clause 1, wherein the tubing head body is formed from a first material and the installable shoulder is formed from a second material that is different than the first material.

Clause 11. The tubing head of Clause 10, wherein the second material has a tensile strength greater than the first material.

Clause 12. The tubing head of Clause 10, wherein the second material has a tensile strength of at least approximately 120 kilopounds per square inch.

Clause 13. The tubing head of Clause 1, wherein the bearing surface of the annular ring is angled relative to the bore.

Clause 14. A method to isolate a wellbore, the method including: introducing a casing isolation plug into the wellbore through a wellhead housing; introducing a shoulder into the tubing head; coupling a tubing head to the wellhead housing; and retrieving the casing isolation plug through a bore of the tubing head and an inner diameter of the shoulder.

Clause 15. The method of Clause 14, further including: introducing a wellhead component through the bore of the tubing head; and supporting the wellhead component relative to the tubing head via the shoulder.

Clause 16. The method of Clause 14, wherein the tubing head is formed from a first material and the shoulder is formed from a second material that is different than the first material.

Clause 17. The method of Clause 14, wherein introducing the shoulder into the tubing head includes introducing a plurality of shoulder segments into the tubing head to collectively form an annular ring within the tubing head.

Clause 18. A wellhead system including: a wellhead housing; a tubing head coupled to the wellhead housing, the tubing head including: a tubing head body defining a bore in fluid communication with the wellhead housing and extending longitudinally between a first end and a second end; and an installable shoulder disposed within the bore; and a wellhead component disposed within the bore of the tubing head and supported by the installable shoulder.

Clause 19. The wellhead system of Clause 18, wherein the tubing head body is formed from a first material and the installable shoulder is formed from a second material that is different than the first material.

Clause 20. The wellhead system of Clause 18, wherein the installable shoulder includes a plurality of shoulder segments.

A reference to an element in the singular is not intended to mean “one and only one” unless specifically so stated, but rather “one or more.” Unless specifically stated otherwise, the term “some” refers to one or more. Pronouns in the masculine (e.g., his) include the feminine and neuter gender (e.g., her and its) and vice versa. Headings and subheadings, if any, are used for convenience only and do not limit the invention.

The word “exemplary” is used herein to mean “serving as an example or illustration.” Any aspect or design described herein as “exemplary” is not necessarily to be construed as preferred or advantageous over other aspects or designs. In one aspect, various alternative configurations and operations described herein may be considered to be at least equivalent.

A phrase such as an “aspect” does not imply that such aspect is essential to the subject technology or that such aspect applies to all configurations of the subject technology. A disclosure relating to an aspect may apply to all configurations, or one or more configurations. An aspect may provide one or more examples. A phrase such as an aspect may refer to one or more aspects and vice versa. A phrase such as an “embodiment” does not imply that such embodiment is essential to the subject technology or that such embodiment applies to all configurations of the subject technology. A disclosure relating to an embodiment may apply to all embodiments, or one or more embodiments. An embodiment may provide one or more examples. A phrase such an embodiment may refer to one or more embodiments and vice versa. A phrase such as a “configuration” does not imply that such configuration is essential to the subject technology or that such configuration applies to all configurations of the subject technology. A disclosure relating to a configuration may apply to all configurations, or one or more configurations. A configuration may provide one or more examples. A phrase such a configuration may refer to one or more configurations and vice versa.

In one aspect, unless otherwise stated, all measurements, values, ratings, positions, magnitudes, sizes, and other specifications that are set forth in this specification, including in the claims that follow, are approximate, not exact. In one aspect, they are intended to have a reasonable range that is consistent with the functions to which they relate and with what is customary in the art to which they pertain.

In one aspect, the term “coupled” or the like may refer to being directly coupled. In another aspect, the term “coupled” or the like may refer to being indirectly coupled.

Terms such as “top,” “bottom,” “front,” “rear” and the like if used in this disclosure should be understood as referring to an arbitrary frame of reference, rather than to the ordinary gravitational frame of reference. Thus, a top surface, a bottom surface, a front surface, and a rear surface may extend upwardly, downwardly, diagonally, or horizontally in a gravitational frame of reference.

Various items may be arranged differently (e.g., arranged in a different order, or partitioned in a different way) all without departing from the scope of the subject technology. All structural and functional equivalents to the elements of the various aspects described throughout this disclosure that are known or later come to be known to those of ordinary skill in the art are expressly incorporated herein by reference and are intended to be encompassed by the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 U.S.C. § 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or, in the case of a method claim, the element is recited using the phrase “step for.” Furthermore, to the extent that the term “include,” “have,” or the like is used, such term is intended to be inclusive in a manner similar to the term “comprise” as “comprise” is interpreted when employed as a transitional word in a claim.

The Title, Background, Summary, Brief Description of the Drawings and Abstract of the disclosure are hereby incorporated into the disclosure and are provided as illustrative examples of the disclosure, not as restrictive descriptions. It is submitted with the understanding that they will not be used to limit the scope or meaning of the claims. In addition, in the Detailed Description, it can be seen that the description provides illustrative examples and the various features are grouped together in various embodiments for the purpose of streamlining the disclosure. This method of disclosure is not to be interpreted as reflecting an intention that the claimed subject matter requires more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive subject matter lies in less than all features of a single disclosed configuration or operation. The following claims are hereby incorporated into the Detailed Description, with each claim standing on its own as a separately claimed subject matter.

The claims are not intended to be limited to the aspects described herein, but is to be accorded the full scope consistent with the language claims and to encompass all legal equivalents. Notwithstanding, none of the claims are intended to embrace subject matter that fails to satisfy the requirement of 35 U.S.C. § 101, 102, or 103, nor should they be interpreted in such a way.

TUBING HEAD WITH INSTALLABLE SHOULDER

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