Monobore well completion

Abstract

a method of completing a well having a wellbore extending through a subterranean formation, the method comprising: running a liner assembly into the wellbore, inside a production casing; hanging the liner assembly from the production casing at a location above a leak and cementing the liner assembly in the wellbore; running a tubing string into the wellbore, inside the production casing, the tubing string having a diameter which is the same as a diameter of the liner assembly; and connecting a lower end of the tubing string to an upper end of the liner assembly at a polished bore receptacle.

Description

[0001] Title: MONOBORE WELL COMPLETION

[0002] Inventors:

[0003] Jay Cecil

[0004] Ibrahim Mohamed

[0005] Omar Abou-Sayed

[0006] Cross-Reference to Related Applications

[0007] This is an international application for patent filed under the auspices of the Patent Cooperation Treaty and claims priority to U.S. Provisional Application 63 / 491,033 filed March 17 / , 2023, entitled Slurry Injection Well Completion.

[0008] FIELD:

[0009]

[0001] The disclosed methods and apparatus generally relate to methods and apparatus for completing a well using a liner and tubing combination having a monobore.

[0010] BRIEF DESCRIPTION OF THE DRAWING:

[0011]

[0002] Drawings of the preferred embodiments of the present disclosure are attached hereto so that the embodiments of the present disclosure may be better and more fully understood:

[0012]

[0003] FIG. 1 is a cross-sectional view of a typical prior art wellbore completion;

[0013]

[0004] FIG. 2 is a cross-sectional elevation view of a wellbore having an exemplary liner and tubing assembly according to aspects of the disclosure; and

[0014]

[0005] FIG. 3 is a cross-sectional elevation view of a wellbore completion of the prior art for damaged casing.

[0015]

[0006] FIG. 4 is a cross-sectional elevation view of a wellbore having an exemplary completion repairing a damaged casing according to aspects of the disclosure.

[0016] DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

[0017]

[0007] FIG. 1 is a cross-sectional view of a typical prior art wellbore completion. A wellbore 10 extends through a subterranean formation 20 having multiple zones. Closer to the surface, an upper casing 22 having a generally wide diameter is cemented in place. That is, a borehole is drilled, the upper casing run into place and cement 24 packed into the annulus between the upper casing and the wellbore. The cement provides a seal against fluid flow from the formation into the wellbore and upper casing and maintains the casing in place. The upper casing typically runs hundreds of feet deep and extends through protected zones of the formation, such as fresh water zones. The upper casing can extend through multiple protected zones in some cases. The upper casing 22 has an effective diameter and is typically a larger diameter tubular. For example, typical casing sizes for upper casing can be 13-3 / 8 inch, 16 inch, 18-5 / 8 inch, 20 inch and larger.

[0018]

[0008] It is typical to drill a wellbore with a wide diameter at the surface, and then narrowing the diameter as the well is extended into the formation. A wellbore can have several associated diameters, as seen. Any casing or liner is of smaller diameter than the drilled wellbore. An anulus is created between the casing or liner and the wellbore. Where a smaller diameter tubular is run into a larger diameter tubular, an annulus is defined between the tubulars of differing diameters. It is understood by those of skill in the art that terms such as “casing, “tubing,” “liner,” and the like can refer to an assembly of tubulars of similar diameters joined together at joints, connections, or the like.

[0019]

[0009] It is typical to position a production casing 26 in the wellbore 10 after placement of the upper casing 22. The production casing 26 is run into the wellbore, inside the upper casing 22, and extends, when in position, from the surface toward a lower end of the wellbore. At its upper end, the production casing is often connected to a Christmas tree or other surface equipment. The production casing 26, once positioned, is cemented in place with cement 28 packing the annulus between the production casing and the wellbore. An annular seal is created between the production casing 26 and the upper casing 22, such as by setting a packer or the like, as is known in the art. The production casing has a production casing diameter that is smaller than that of the upper casing, allowing the production casing to be run through the upper casing. For example, typical production casing sizes can be 9-5 / 8 inch down to 4-1 / 2 inches.

[0020]

[0010] It is also common to position a liner 30 below the production casing 26, again narrowing the diameter of the available space for later workstrings or tubing strings. The liner 30 has a diameter that is smaller than the production casing 26. The liner 30 is inserted into the wellbore, extending below the production casing, and is cemented 32 in place. The liner is “hung” off the production casing and does not extend to the surface. A hanger 34 positioned at the upper end of the liner 30 is “set,” radially expanded, into sealing and gripping engagement with the production casing 26, thereby sealing the annulus between the liner and the production casing. Perforations 39 can be created in the liner along the target zone, and slurry injected into the formation through the perforations. For example, typical liner hung from production casing can be 5-1 / 2 or 4-1 / 2 inches.

[0021] [OH] In a typical prior art well, after placement of the liner, various workstrings or tubing strings 36 are lowered into the wellbore inside the liner. Obviously, the tubing string 36 is of a smaller diameter than the liner. For example, a perforating tubing string can be lowered to create perforations 39 in the liner. As another example, an injection tubing can be lowered into the production casing to deliver injection fluids through the perforations and into a target zone of the formation. As another example, a production tubing string can be lowered into the liner. The tubing can, for example, be 3-1 / 2 or 4-1 / 2 inches.

[0022]

[0012] The tubing string 36 is run into the liner 30 and an annular seal created in the annulus between the tubing string 36 and the liner 30, such as with a packer 38 or the like. FIG. 1 shows the tubing string 36 extending only a short distance into the liner 30. It is understood that depending on the operation, the tubing string may be extended further into the liner.

[0023]

[0013] It is understood that the diameters given for casing, liners and tubing are exemplary. The actual sizes will depend on the specifics of the well, wellbore, equipment, purpose of the well, etc. Persons of skill in the art will recognize the various sizes of tubulars that can be employed.

[0024]

[0014] In some applications, the narrowing of the effective tubulars near the bottom of the wellbore does not create substantial problems. In fact, the narrowing of the wellbore has advantages in requiring less time and effort to drill than a larger diameter hole. But in some cases it is preferable to have a wider diameter final tubular in position in the wellbore, allowing for larger diameter tubing strings and the like, or for wider diameter tubulars for flowing fluids along the wellbore. For example, in slurry injection operations and slurry fracturing operations, a relatively smaller diameter injection tubing results in significant friction energy losses when injecting the slurry.

[0025]

[0015] A slurry, typically made up of finely ground solid particles carried in a carrier fluid, is injected into selected, target zones of the formation. The slurry, for example, can be comprised of waste materials, such as oil and gas waste fluids, biological waste materials, etc., as is known in the art. The slurry is heavier and more viscous than many injection fluids, resulting in greater losses of energy to friction as the slurry runs along the tubing, etc. These losses result in a reduction of efficiency in use of pumping energy or can require more powerful pumps to inject the slurry into the formation and / or create fractures in the formation during injection.

[0026]

[0016] Accordingly, the disclosure presents methods and apparatus for use of a larger diameter tubing (or other workstring) by eliminating the typical step-down in diameter required by use of a liner. Stated another way, a monobore is created across the liner and tubing string.

[0027]

[0017] FIG. 2 is a cross-sectional elevation view of a wellbore having an exemplary liner and tubing assembly according to aspects of the disclosure. Like part numbers are used to save on redundant explanations. The wellbore 10 again extends into a subterranean formation having an upper casing 22, production casing 26 and liner 30. However, the liner 30 has positioned at its upper end a liner hanger 34 and polished bore receptacle (PBR) 40. The liner hanger 34 is set into sealing engagement with the production casing 26. The FIG. 2 shows the liner hanger 34 and PBR together for ease of illustration. Person of skill will understand that a liner hanger is typically several feet long and a typical PBR can be six to 20 feet long. These lengths are exemplary. Persons of skill will also recognize the manners in which a PBR can be attached, directly or indirectly, to a liner hanger. The liner can be perforated, etc., as before. The PBR 40, positioned above the hanger, provides a connection 42 for a tubing string 44 of the same diameter as the liner 30.

[0028]

[0018] Hence the liner and tubing string are monobore. The PBR and liner hanger are assembled together as is known in the art. The tubing string is stung into or connected to the PBR as is known in the art. Later operations, such as production or injection are performed through the tubing string and liner of the same diameter.

[0029]

[0019] FIG. 3 is a cross-sectional elevation view of a wellbore completion of the prior art for damaged casing. Like numbers are used in the figure to reduce redundant discussion. In some cases, the casing becomes damaged and leaks fluids from the formation into the casing. When this occurs, it is typical to repair the casing by placing a “patch” along the damaged or leaking portion of the casing. In FIG. 3, the production casing 26 is damaged along a portion 50 of the casing. To repair the leak, a liner 30 is run into the production casing and hung from the production casing, at a liner hanger 34, from a location uphole of the leaking casing. The liner hanger is set against the production casing providing an annular seal between the production casing and the liner.

[0030]

[0020] After placement of the liner, a workstring or tubing string 36 can be lowered into the wellbore inside the liner 30. Obviously, the tubing string 36 is of a smaller diameter than the liner 30. For example, a perforating tubing string can be lowered to create perforations 39 in the liner and formation. As another example, an injection tubing can be lowered into the production casing to deliver injection fluids through the perforations 39 and into a target zone of the formation. As another example, a production tubing string can be lowered into the liner. The tubing string 36 is run into the liner 30 and an annular seal created in the annulus between the tubing string 36 and the liner 30, such as with a packer 38 or the like. FIG. 3 shows the tubing string 36 extending only a short distance into the liner 30. It is understood that depending on the operation, the tubing string may be extended further into the liner.

[0031]

[0021] FIG. 4 is a cross-sectional elevation view of a wellbore having an exemplary completion repairing a damaged casing according to aspects of the disclosure. Like part numbers are used to reduce redundancy. The wellbore 10 again extends into a subterranean formation having an upper casing 22, production casing 26 and liner 30. The production casing 26 is damaged along a casing portion 50. A liner 30 is run into the production casing and hung from the production casing 26 at a location uphole from the damaged portion 50. The liner 30 is hung by a liner hanger 34 which seals the annular area between the production casing and the liner. The liner can be perforated, etc., as before. Positioned uphole of the liner hanger 34 is a PBR 40. The PBR 40, positioned above the hanger, provides a connection 42 for a tubing string 44 of the same diameter as the liner 30.

[0032]

[0022] Hence the liner and tubing string are monobore. The PBR and liner hanger are assembled together as is known in the art. The tubing string is stung into or connected to the PBR as is known in the art. Later operations, such as production or injection are performed through the tubing string and liner of the same diameter.

[0033] Conclusion

[0034]

[0023] The words or terms used herein have their plain, ordinary meaning in the field of this disclosure, except to the extent explicitly and clearly defined in this disclosure or unless the specific context otherwise requires a different meaning. If there is any conflict in the usages of a word or term in this disclosure and one or more patent(s) or other documents that may be incorporated by reference, the definitions that are consistent with this specification should be adopted.

[0035]

[0024] Whenever a numerical range of degree or measurement with a lower limit and an upper limit is disclosed, any number and any range falling within the range is also intended to be specifically disclosed. For example, every range of values (in the form “from a to b,” or “from about a to about b,” or “from about a to b,” “from approximately a to b,” and any similar expressions, where “a” and “b” represent numerical values of degree or measurement) is to be understood to set forth every number and range encompassed within the broader range of values.

[0025] While the foregoing written description of the disclosure enables one of ordinary skill to make and use the embodiments discussed, those of ordinary skill will understand and appreciate the existence of variations, combinations, and equivalents of the specific embodiments, methods, and examples herein. The disclosure should therefore not be limited by the above described embodiments, methods, and examples. While this disclosure has been described with reference to illustrative embodiments, this description is not intended to be construed in a limiting sense. Various modifications and combinations of the illustrative embodiments as well as other embodiments of the disclosure will be apparent to persons skilled in the art upon reference to the description. It is, therefore, intended that the appended claims encompass any such modifications or embodiments.

[0036]

[0026] The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the present disclosure. The various elements or steps according to the disclosed elements or steps can be combined advantageously or practiced together in various combinations or sub-combinations of elements or sequences of steps to increase the efficiency and benefits that can be obtained from the disclosure. It will be appreciated that one or more of the above embodiments may be combined with one or more of the other embodiments, unless explicitly stated otherwise. Furthermore, no limitations are intended to the details of construction, composition, design, or steps herein shown, other than as described in the claims.

[0037]

[0027] The systems, methods, and apparatus in the embodiments described above are exemplary. Therefore, many details are neither shown nor described. Even though numerous characteristics of the embodiments of the present disclosure have been set forth in the foregoing description, together with details of the structure and function of the present disclosure, the present disclosure is illustrative, such that changes may be made in the detail, especially in matters of shape, size and arrangement of the components within the principles of the present disclosure to the full extent indicated by the broad general meaning of the terms used in the attached claims. The description and drawings of the specific examples above do not point out what an infringement of this patent would be but are to provide at least one explanation of how to make and use the present disclosure. The limits of the embodiments of the present disclosure and the bounds of the patent protection are measured by and defined in the following claims.

Claims

It is Claimed:

1. A method of completing a well having a wellbore extending through a subterranean formation, the formation having a protected zone and at least one target zone positioned deeper than the protected zone, the method comprising: cementing an upper casing in the wellbore, the upper casing extending from a surface to below the protected zone, the upper casing having a first diameter; positioning a production casing in the wellbore extending through the upper casing to a lower end of the wellbore, the production casing having a second diameter of less than the first diameter, and cementing the production casing in the wellbore; in response to developing a leak in the production casing at a location below the upper casing: running a liner into the wellbore, inside the production casing, the liner assembly having a third diameter of less than the second diameter; hanging the liner assembly from the production casing at a location above the leak and cementing the liner assembly in the wellbore; running a tubing string into the wellbore, inside the production casing, the tubing string having a fourth diameter which is the same as the third diameter; and connecting a lower end of the tubing string to an upper end of the liner assembly at a polished bore receptacle.

2. The method of claim 1, further comprising creating perforations in the liner assembly at a location below the polished bore receptacle.

3. The method of claim 2, further comprising injecting slurry into the target zone of the formation through the perforations in the liner assembly.

4. The method of claim 1, wherein hanging the liner assembly further comprises setting a liner hanger assembly in the production casing, the liner hanger assembly positioned at an upper end of the liner assembly, the set liner hanger assembly sealing an annulus formed between the production casing and the liner assembly.

5. The method of claim 4, wherein the liner assembly comprises the liner hanger and the polished bore receptacle positioned above the liner hanger.

6. A method of completing a well having a wellbore extending through a subterranean formation, the wellbore having a cemented upper casing extending from the surface through a protected zone, and having a cemented production casing extending through the upper casing, through a target zone, and to a lower end of the wellbore, the production casing having a leak allowing fluid flow between the formation and the production casing, the method comprising: running a liner assembly into the wellbore, inside the production casing, the liner assembly having a first diameter; hanging the liner assembly from the production casing at a location above the leak and cementing the liner assembly in the wellbore; running a tubing string into the wellbore, inside the production casing, the tubing string having a second diameter which is the same as the first diameter; and connecting a lower end of the tubing string to an upper end of the liner assembly at a polished bore receptacle.

7. The method of claim 6, further comprising creating perforations in the liner assembly at a location below the polished bore receptacle.

8. The method of claim 7, further comprising injecting slurry into the target zone of the formation through the perforations in the liner assembly.

9. The method of claim 6, wherein hanging the liner assembly further comprises setting a liner hanger in the production casing, the liner hanger positioned at an upper end of the liner assembly, the set liner hanger sealing an annulus formed between the production casing and the liner assembly.

10. The method of claim 9, wherein the liner assembly comprises the liner hanger and the polished bore receptacle positioned above the liner hanger.

11. A method of completing a well having a wellbore extending through a subterranean formation, the formation having a protected zone and at least one target zone positioned deeper than the protected zone, the method comprising: running an upper casing into the wellbore, positioning the upper casing to extend from a surface to below the protected zone, the upper casing having a first diameter; cementing the upper casing in the wellbore by positioning cement in an annulus between the upper casing and the wellbore; running a production casing into the wellbore, inside the upper casing, positioning the production casing to extend through the target zone, the production casing having a second diameter of less than the first diameter; cementing the production casing in the wellbore by positioning cement in an annulus between the production casing and the wellbore; running a liner assembly into the wellbore, inside the upper casing, the liner assembly having a third diameter of less than the second diameter; positioning the liner assembly in the wellbore, inside the production casing, to extend from a lower end of the production casing to a lower end of the wellbore; hanging the liner assembly from the production casing and sealing an annulus between the liner assembly and the upper casing; running a tubing string into the wellbore, inside the production casing, the tubing string having a fourth diameter which is the same as the third diameter; and sealingly connecting a lower end of the tubing string to an upper end of the liner assembly at a polished bore receptacle.

12. The method of claim 11, further comprising creating perforations in the liner assembly at a location below the polished bore receptacle.

13. The method of claim 12, further comprising injecting slurry into the target zone of the formation through the perforations in the liner assembly.

14. The method of claim 11, wherein hanging the liner assembly further comprises setting a liner hanger in the production casing, the liner hanger positioned at an upper end of the liner assembly, the set liner hanger sealing the annulus formed between the production casing and the liner assembly.

15. The method of claim 14, wherein the liner assembly comprises the liner hanger and the polished bore receptacle positioned above the liner hanger.

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