Riser-less managed pressure drilling with subsea fluid handling

Abstract

A well drilling system can include a drill string free of a riser string enclosing the drill string, a rotating control device assembly connected above a subsea wellhead and sealing about the drill string, and a fluid return line connected to the rotating control device assembly. The fluid return line is configured to flow fluid from the rotating control device assembly without the fluid being flowed to the drilling rig. A method of drilling can include drilling a wellbore without a riser connected between a subsea wellhead and a drilling rig, the drilling including sealing about a drill string with a rotating control device assembly, flowing fluid into the wellbore during the drilling, and returning the fluid from the wellbore during the drilling. The fluid remains subsea after the flowing step and during the drilling step.

Description

CROSS-REFERENCE TO RELATED APPLICATION

[0001] The present application claims the benefit of the filing date of U.S. provisional application No. 63 / 780,748 filed on 31 Mar. 2025. The entire disclosure of the prior application is incorporated herein by this reference for all purposes.BACKGROUND

[0002] This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an example described below, more particularly provides for riderless managed pressure drilling with subsea fluid handling.

[0003] In water-based drilling operations, drilling fluid is typically processed at the surface (such as, on a rig having mud pumps, mud tanks, well control equipment, a gas separator, fluid conditioning equipment, etc.). It is important that the drilling fluid be maintained or adjusted to a desired condition (e.g., having a certain density, solids content, lubricity, additives, etc.) when the drilling fluid is pumped back into a wellbore being drilled.

[0004] It will, therefore, be readily appreciated that improvements are continually needed in the art of fluid handling in well drilling operations. The present disclosure provides such improvements, which may be used with a wide variety of different types of well drilling operations (such as, subsea riser-less managed pressure drilling).BRIEF DESCRIPTION OF THE DRAWINGS

[0005] FIG. 1 is a representative schematic view of an example of a well system which can embody principles of this disclosure.

[0006] FIG. 2 is a representative flow chart for an example of a method that can be used with the FIG. 1 system.

[0007] FIG. 3 is a representative schematic view of another example of the well system.

[0008] FIG. 4 is a representative flow chart for an example of a method that can be used with the FIG. 3 system.

[0009] FIG. 5 is a representative schematic view of another example of the well system.

[0010] FIG. 6 is a representative flow chart for an example of a method that can be used with the FIG. 5 system.

[0011] FIG. 7 is a representative schematic view of another example of the well system.

[0012] FIG. 8 is a representative flow chart for an example of a method that can be used with the FIG. 7 system.

[0013] FIG. 9 is a representative schematic view of another example of the well system.

[0014] FIG. 10 is a representative flow chart for an example of a method that can be used with the FIG. 9 system.DETAILED DESCRIPTION

[0015] Representatively illustrated in FIGS. 1 & 2 are examples of a well drilling system 10 and associated method 30 which can embody principles of this disclosure. However, it should be clearly understood that the system 10 and method 30 are merely examples of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system 10 and method 30 as described herein and / or depicted in the drawings.

[0016] In the FIGS. 1 & 2 system 10 and method 30, fluid 12 is flowed from one or more drilling rig 14 into one or more wellbore 16 via a fluid delivery line 18. Below a water line 20, a rotating control device assembly 22 is connected above a blowout preventer stack 24, which is connected above a subsea wellhead 26. The rotating control device assembly 22 includes a rotatable annular seal that seals about a drill string 28 used to drill the wellbore 16.

[0017] The drilling operation performed with the system 10 and method 30 can be of the type known to those skilled in the art as managed pressure drilling, in which the wellbore 16 is isolated from atmosphere (or the subsea environment in the FIGS. 1 & 2 example) using the rotating control device assembly 22. The fluid 22 can serve a variety of different purposes, such as, lubricating a drill bit at a distal end of the drill string 28, controlling hydrostatic pressure in the wellbore 16, stabilizing the wellbore, etc.

[0018] The fluid 12 in this example can be returned from the wellbore 16 via a return line 44, processed and flowed back to the wellbore 16, while remaining subsea (below the water line 20). Thus, the fluid 12 is recirculated subsea, without being flowed to the surface above the water line 20.

[0019] Cuttings 40 produced by the drilling process may be separated from the fluid 12 using a cuttings separator 42 connected to the fluid return line 44. In this example, the cuttings 40 are discharged subsea via a discharge line 46.

[0020] Gas 48 received in the wellbore 16 during the drilling process may be separated from the fluid 12 using a gas separator 50 connected to the return line 44. In this example, the gas 48 is discharged subsea via the discharge line 46.

[0021] The cuttings separator 42 and the gas separator 50 are included in a subsea processing unit 52. In this example, the processing unit 52 is also capable of removing waste 54 from the fluid 12 returned from the wellbore 16. The waste 54 may be discharged subsea via the discharge line 46.

[0022] The fluid 12 flows from the processing unit 52 to a pump unit 56. The pump unit 56 includes one or more pump 60 that pumps the fluid 12 back to the wellbore 16 via a line 62. In this example, the pump unit 56 can be configured for managed pressure drilling operations (such as, with a choke manifold for regulating pressure in the wellbore 16 by adjusting back pressure applied to the return line 44).

[0023] Note that the fluid 12 is not flowed to the surface above the water line 20 at any point between being returned from the wellbore 16, and being flowed back into the wellbore 16 via the line 62. Instead, the fluid 12 remains subsea after it has been initially flowed into the wellbore 16 via the delivery line 18.

[0024] The method 30 is depicted in FIG. 2 in flowchart form. In an initial step 32, the fluid 12 is pumped into a well. In the FIG. 1 system 10, the fluid 12 is initially flowed from the drilling rig 14 into the wellbore 16 via the delivery line 18.

[0025] In step 34, returns from the wellbore 16 are flowed to subsea processing equipment. In the FIG. 1 system 10, the returns include the fluid 12, cuttings 40, gas 48 and waste 54, which are flowed to the processing unit 52 via the return line 44.

[0026] In step 36, the waste 54 is discharged into the surrounding water via the discharge line 46. In the FIG. 1 system 10, the gas 48 and cuttings 40 are also discharged into the surrounding water. In other examples, any, or any combination, of the waste 54, gas 48, cuttings 40 and a portion of the fluid 12 may be discharged into the surrounding water.

[0027] In step 38, the processed fluid 12 is pumped back to the well. In the FIG. 1 system 10, the fluid 12 is pumped by the pump unit 56 back to the wellbore 16 via the line 62.

[0028] Referring additionally now to FIGS. 3 & 4, further examples of the system 10 and method 30 are representatively illustrated. The FIGS. 3 & 4 examples are similar to the FIGS. 1 & 2 examples. However, in the FIGS. 3 & 4 examples, the waste 54 (and / or the cuttings 40, gas 48 and a portion of the fluid 12) is / are flowed from the processing unit 52 to a subsea container 64.

[0029] The waste 54, cuttings 40, gas 48 and / or fluid 12 can be stored in the container 64 for an extended period of time. The container 64 may be emptied when it is full or whenever convenient.

[0030] In the FIG. 4 method 30, a step 66 is substituted for the step 36 of the FIG. 2 method 30. In the step 66, the waste 54 (and / or cuttings 40, gas 48 and a portion of the fluid 12) is / are flowed to the subsea container 64. In an additional step 68, the waste 54 (and / or cuttings 40, gas 48 and a portion of the fluid 12) is / are removed from the subsea container 64 and are disposed of.

[0031] Referring additionally now to FIGS. 5 & 6, further examples of the system 10 and method 30 are representatively illustrated. The FIGS. 5 & 6 examples are similar to the FIGS. 1-4 examples. However, in the FIGS. 5 & 6 examples, the fluid 12 is not flowed back to the wellbore 16, and is not stored in the subsea container 64. Instead, the fluid 12 returned from the wellbore 16 is pumped by the pump unit 56 to one or more injection wellbore 70. Any combination of the cuttings 40, gas 48 and / or waste 54 can also be pumped to the injection wellbore 70.

[0032] In the FIG. 6 method 30, a new step 72 is substituted for the steps 34-38, 66, 68 of the FIGS. 2 & 4 methods 30. In the step 72, returns (including any one or more of the fluid 12, the cuttings 40, the gas 48 and the waste 54) are pumped into the injection wellbore 70.

[0033] Referring additionally now to FIGS. 7 & 8, further examples of the system 10 and method 30 are representatively illustrated. The FIGS. 7 & 8 examples are similar to the FIGS. 1-6 examples. However, in the FIGS. 7 & 8 examples, the cuttings 40, gas 48 and waste 54 are removed from the fluid 12 after it returns from the wellbore 16 via the return line 44. The fluid 12 is pumped back to the wellbore 16 via the line 62. The cuttings 40, gas 48 and waste 54 (or any combination thereof) are pumped into the injection wellbore 70. A portion of the fluid 12 may also be pumped into the injection wellbore 70 with the cuttings 40, gas 48 and / or waste 54.

[0034] In the FIG. 8 method 30, a new step 74 is substituted for the step 36 in the FIG. 1 method 30. In the step 74, the waste 54 (and / or the cuttings 40, gas 48 and a portion of the fluid 12) is / are pumped into the injection wellbore 70. The step 38 remains in the FIG. 8 method 30 (e.g., the fluid 12 is pumped back to the wellbore 16 via the line 62 after processing).

[0035] Referring additionally now to FIGS. 9 & 10, further examples of the system 10 and method 30 are representatively illustrated. The FIGS. 9 & 10 examples are similar to the FIGS. 1-8 examples. However, in the FIGS. 9 & 10 examples, the cuttings 40, gas 48 and / or waste 54 (or any combination thereof) are discharged subsea from the discharge line 46, as well as being pumped into the injection wellbore 70.

[0036] Thus, after being returned from the wellbore 16 and after being processed (e.g., using the processing unit 52), a portion of the fluid 12 is flowed back to the wellbore 16, a portion of the fluid 12 may be pumped into the injection wellbore 70, and / or a portion of the fluid 12 may be discharged to the surrounding water via the discharge line 46. The cuttings 40, gas 48 and / or waste 54, after being removed from the fluid 12 by the processing unit 52 is / are pumped into the injection wellbore 70 and / or discharged to the surrounding water via the discharge line 46.

[0037] In the FIG. 10 method 30, both of the steps 36 and 74 are included to indicate that one or more of the waste 54, cuttings 40, gas 48 and a portion of the fluid 12 is / are both injected into the wellbore 70 and flowed into the surrounding water. In any of the above examples of the method 30, any substance discharged into the surrounding water is preferably environmentally safe.

[0038] It may now be fully appreciated that the above disclosure provides significant advancements to the art of well drilling in a subsea environment. In examples described herein, the fluid 12 does not need to be pumped to the surface above the water line 20 during drilling operations. Instead, the fluid 12 can remain below the water line 20 while it is processed and flowed back to the wellbore 16, discharged into the surrounding water or pumped into the injection wellbore 70.

[0039] A method 30 of drilling a subterranean well is provided to the art by this disclosure. In one example, the method can comprise: drilling a first wellbore 16 without a riser connected between a subsea wellhead 26 and a drilling rig 14, the drilling step including sealing about a drill string 28 with a rotating control device assembly 22; flowing fluid 12 into the first wellbore 16 during the drilling; and returning the fluid 12 from the first wellbore 16 during the drilling. The fluid 12 remains subsea after the flowing step and during the drilling step.

[0040] The fluid 12 returned from the first wellbore 16 may be discharged subsea.

[0041] The method 30 may include removing cuttings 40 from the fluid 12 returned from the first wellbore 16. The removing step may be performed subsea. The method 30 may include discharging the cuttings 40 subsea.

[0042] The method 30 may include removing waste 54 from the fluid 12 returned from the first wellbore 16. The removing step may be performed subsea. The method 30 may include discharging the waste 54 subsea.

[0043] The method 30 may include separating gas 48 from the fluid 12 returned from the first wellbore 16. The separating step may be performed subsea.

[0044] The method 30 may include injecting the fluid 12 returned from the first wellbore 16 into a second wellbore 70.

[0045] The method 30 may include injecting a first portion of the fluid 12 returned from the first wellbore 16 into a second wellbore 70, and flowing a second portion of the fluid 12 returned from the first wellbore 16 back into the first wellbore 16. The method 30 may include discharging subsea a third portion of the fluid 12 returned from the first wellbore 16.

[0046] This disclosure also provides to the art a well drilling system 10. In one example, the system 10 comprises: a drill string 28 extending from a drilling rig 14 into a first wellbore 16, the drill string 28 being free of a riser string enclosing the drill string 28; a rotating control device assembly 22 connected above a subsea wellhead 26, the rotating control device assembly 22 sealing about the drill string 28; and a fluid return line 44 connected to the rotating control device assembly 22, the fluid return line 44 being configured to flow fluid 12 from the rotating control device assembly 22 without the fluid 12 being flowed to the drilling rig 14.

[0047] The fluid return line 44 may be configured so that the fluid 12 flowed from the rotating control device assembly 22 is maintained subsea.

[0048] The system 10 may include a discharge line 46 configured to discharge subsea at least a portion of the fluid 12 flowed from the rotating control device assembly 22.

[0049] The system 10 may include a cuttings separator 42 positioned subsea and connected to the fluid return line 44. The system 10 may include a discharge line 46 configured to discharge cuttings 40 subsea.

[0050] The system 10 may include a processing unit 52 positioned subsea and connected to the fluid return line 44, the processing unit 52 being configured to remove waste 54 from the fluid 12. The system 10 may include a discharge line 46 configured to discharge the waste 54 subsea.

[0051] The system 10 may include a gas separator 50 positioned subsea and connected to the fluid return line 44.

[0052] The system 10 may include a pump 60 positioned subsea and connected to the fluid return line 44. The pump 60 may be configured to pump the fluid 12 from the fluid return line 44 into a second wellbore 70. The pump 60 may be configured to pump a first portion of the fluid 12 into a second wellbore 70, and to pump a second portion of the fluid to the first wellbore 16.

[0053] Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and / or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.

[0054] Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.

[0055] It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.

[0056] In the above description of the representative examples, directional terms (such as “above,”“below,”“upper,”“lower,”“upward,”“downward,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.

[0057] The terms “including,”“includes,”“comprising,”“comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.”

[0058] Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.

Examples

Embodiment Construction

[0015]Representatively illustrated in FIGS. 1 & 2 are examples of a well drilling system 10 and associated method 30 which can embody principles of this disclosure. However, it should be clearly understood that the system 10 and method 30 are merely examples of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system 10 and method 30 as described herein and / or depicted in the drawings.

[0016]In the FIGS. 1 & 2 system 10 and method 30, fluid 12 is flowed from one or more drilling rig 14 into one or more wellbore 16 via a fluid delivery line 18. Below a water line 20, a rotating control device assembly 22 is connected above a blowout preventer stack 24, which is connected above a subsea wellhead 26. The rotating control device assembly 22 includes a rotatable annular seal that seals about a drill string 28 used to drill the wellbore 16.

[0...

CROSS-REFERENCE TO RELATED APPLICATION

[0001] The present application claims the benefit of the filing date of U.S. provisional application No. 63 / 780,748 filed on 31 Mar. 2025. The entire disclosure of the prior application is incorporated herein by this reference for all purposes.BACKGROUND

[0002] This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an example described below, more particularly provides for riderless managed pressure drilling with subsea fluid handling.

[0003] In water-based drilling operations, drilling fluid is typically processed at the surface (such as, on a rig having mud pumps, mud tanks, well control equipment, a gas separator, fluid conditioning equipment, etc.). It is important that the drilling fluid be maintained or adjusted to a desired condition (e.g., having a certain density, solids content, lubricity, additives, etc.) when the drilling fluid is pumped back into a wellbore being drilled.

[0004] It will, therefore, be readily appreciated that improvements are continually needed in the art of fluid handling in well drilling operations. The present disclosure provides such improvements, which may be used with a wide variety of different types of well drilling operations (such as, subsea riser-less managed pressure drilling).BRIEF DESCRIPTION OF THE DRAWINGS

[0005] FIG. 1 is a representative schematic view of an example of a well system which can embody principles of this disclosure.

[0006] FIG. 2 is a representative flow chart for an example of a method that can be used with the FIG. 1 system.

[0007] FIG. 3 is a representative schematic view of another example of the well system.

[0008] FIG. 4 is a representative flow chart for an example of a method that can be used with the FIG. 3 system.

[0009] FIG. 5 is a representative schematic view of another example of the well system.

[0010] FIG. 6 is a representative flow chart for an example of a method that can be used with the FIG. 5 system.

[0011] FIG. 7 is a representative schematic view of another example of the well system.

[0012] FIG. 8 is a representative flow chart for an example of a method that can be used with the FIG. 7 system.

[0013] FIG. 9 is a representative schematic view of another example of the well system.

[0014] FIG. 10 is a representative flow chart for an example of a method that can be used with the FIG. 9 system.DETAILED DESCRIPTION

[0015] Representatively illustrated in FIGS. 1 & 2 are examples of a well drilling system 10 and associated method 30 which can embody principles of this disclosure. However, it should be clearly understood that the system 10 and method 30 are merely examples of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system 10 and method 30 as described herein and / or depicted in the drawings.

[0016] In the FIGS. 1 & 2 system 10 and method 30, fluid 12 is flowed from one or more drilling rig 14 into one or more wellbore 16 via a fluid delivery line 18. Below a water line 20, a rotating control device assembly 22 is connected above a blowout preventer stack 24, which is connected above a subsea wellhead 26. The rotating control device assembly 22 includes a rotatable annular seal that seals about a drill string 28 used to drill the wellbore 16.

[0017] The drilling operation performed with the system 10 and method 30 can be of the type known to those skilled in the art as managed pressure drilling, in which the wellbore 16 is isolated from atmosphere (or the subsea environment in the FIGS. 1 & 2 example) using the rotating control device assembly 22. The fluid 22 can serve a variety of different purposes, such as, lubricating a drill bit at a distal end of the drill string 28, controlling hydrostatic pressure in the wellbore 16, stabilizing the wellbore, etc.

[0018] The fluid 12 in this example can be returned from the wellbore 16 via a return line 44, processed and flowed back to the wellbore 16, while remaining subsea (below the water line 20). Thus, the fluid 12 is recirculated subsea, without being flowed to the surface above the water line 20.

[0019] Cuttings 40 produced by the drilling process may be separated from the fluid 12 using a cuttings separator 42 connected to the fluid return line 44. In this example, the cuttings 40 are discharged subsea via a discharge line 46.

[0020] Gas 48 received in the wellbore 16 during the drilling process may be separated from the fluid 12 using a gas separator 50 connected to the return line 44. In this example, the gas 48 is discharged subsea via the discharge line 46.

[0021] The cuttings separator 42 and the gas separator 50 are included in a subsea processing unit 52. In this example, the processing unit 52 is also capable of removing waste 54 from the fluid 12 returned from the wellbore 16. The waste 54 may be discharged subsea via the discharge line 46.

[0022] The fluid 12 flows from the processing unit 52 to a pump unit 56. The pump unit 56 includes one or more pump 60 that pumps the fluid 12 back to the wellbore 16 via a line 62. In this example, the pump unit 56 can be configured for managed pressure drilling operations (such as, with a choke manifold for regulating pressure in the wellbore 16 by adjusting back pressure applied to the return line 44).

[0023] Note that the fluid 12 is not flowed to the surface above the water line 20 at any point between being returned from the wellbore 16, and being flowed back into the wellbore 16 via the line 62. Instead, the fluid 12 remains subsea after it has been initially flowed into the wellbore 16 via the delivery line 18.

[0024] The method 30 is depicted in FIG. 2 in flowchart form. In an initial step 32, the fluid 12 is pumped into a well. In the FIG. 1 system 10, the fluid 12 is initially flowed from the drilling rig 14 into the wellbore 16 via the delivery line 18.

[0025] In step 34, returns from the wellbore 16 are flowed to subsea processing equipment. In the FIG. 1 system 10, the returns include the fluid 12, cuttings 40, gas 48 and waste 54, which are flowed to the processing unit 52 via the return line 44.

[0026] In step 36, the waste 54 is discharged into the surrounding water via the discharge line 46. In the FIG. 1 system 10, the gas 48 and cuttings 40 are also discharged into the surrounding water. In other examples, any, or any combination, of the waste 54, gas 48, cuttings 40 and a portion of the fluid 12 may be discharged into the surrounding water.

[0027] In step 38, the processed fluid 12 is pumped back to the well. In the FIG. 1 system 10, the fluid 12 is pumped by the pump unit 56 back to the wellbore 16 via the line 62.

[0028] Referring additionally now to FIGS. 3 & 4, further examples of the system 10 and method 30 are representatively illustrated. The FIGS. 3 & 4 examples are similar to the FIGS. 1 & 2 examples. However, in the FIGS. 3 & 4 examples, the waste 54 (and / or the cuttings 40, gas 48 and a portion of the fluid 12) is / are flowed from the processing unit 52 to a subsea container 64.

[0029] The waste 54, cuttings 40, gas 48 and / or fluid 12 can be stored in the container 64 for an extended period of time. The container 64 may be emptied when it is full or whenever convenient.

[0030] In the FIG. 4 method 30, a step 66 is substituted for the step 36 of the FIG. 2 method 30. In the step 66, the waste 54 (and / or cuttings 40, gas 48 and a portion of the fluid 12) is / are flowed to the subsea container 64. In an additional step 68, the waste 54 (and / or cuttings 40, gas 48 and a portion of the fluid 12) is / are removed from the subsea container 64 and are disposed of.

[0031] Referring additionally now to FIGS. 5 & 6, further examples of the system 10 and method 30 are representatively illustrated. The FIGS. 5 & 6 examples are similar to the FIGS. 1-4 examples. However, in the FIGS. 5 & 6 examples, the fluid 12 is not flowed back to the wellbore 16, and is not stored in the subsea container 64. Instead, the fluid 12 returned from the wellbore 16 is pumped by the pump unit 56 to one or more injection wellbore 70. Any combination of the cuttings 40, gas 48 and / or waste 54 can also be pumped to the injection wellbore 70.

[0032] In the FIG. 6 method 30, a new step 72 is substituted for the steps 34-38, 66, 68 of the FIGS. 2 & 4 methods 30. In the step 72, returns (including any one or more of the fluid 12, the cuttings 40, the gas 48 and the waste 54) are pumped into the injection wellbore 70.

[0033] Referring additionally now to FIGS. 7 & 8, further examples of the system 10 and method 30 are representatively illustrated. The FIGS. 7 & 8 examples are similar to the FIGS. 1-6 examples. However, in the FIGS. 7 & 8 examples, the cuttings 40, gas 48 and waste 54 are removed from the fluid 12 after it returns from the wellbore 16 via the return line 44. The fluid 12 is pumped back to the wellbore 16 via the line 62. The cuttings 40, gas 48 and waste 54 (or any combination thereof) are pumped into the injection wellbore 70. A portion of the fluid 12 may also be pumped into the injection wellbore 70 with the cuttings 40, gas 48 and / or waste 54.

[0034] In the FIG. 8 method 30, a new step 74 is substituted for the step 36 in the FIG. 1 method 30. In the step 74, the waste 54 (and / or the cuttings 40, gas 48 and a portion of the fluid 12) is / are pumped into the injection wellbore 70. The step 38 remains in the FIG. 8 method 30 (e.g., the fluid 12 is pumped back to the wellbore 16 via the line 62 after processing).

[0035] Referring additionally now to FIGS. 9 & 10, further examples of the system 10 and method 30 are representatively illustrated. The FIGS. 9 & 10 examples are similar to the FIGS. 1-8 examples. However, in the FIGS. 9 & 10 examples, the cuttings 40, gas 48 and / or waste 54 (or any combination thereof) are discharged subsea from the discharge line 46, as well as being pumped into the injection wellbore 70.

[0036] Thus, after being returned from the wellbore 16 and after being processed (e.g., using the processing unit 52), a portion of the fluid 12 is flowed back to the wellbore 16, a portion of the fluid 12 may be pumped into the injection wellbore 70, and / or a portion of the fluid 12 may be discharged to the surrounding water via the discharge line 46. The cuttings 40, gas 48 and / or waste 54, after being removed from the fluid 12 by the processing unit 52 is / are pumped into the injection wellbore 70 and / or discharged to the surrounding water via the discharge line 46.

[0037] In the FIG. 10 method 30, both of the steps 36 and 74 are included to indicate that one or more of the waste 54, cuttings 40, gas 48 and a portion of the fluid 12 is / are both injected into the wellbore 70 and flowed into the surrounding water. In any of the above examples of the method 30, any substance discharged into the surrounding water is preferably environmentally safe.

[0038] It may now be fully appreciated that the above disclosure provides significant advancements to the art of well drilling in a subsea environment. In examples described herein, the fluid 12 does not need to be pumped to the surface above the water line 20 during drilling operations. Instead, the fluid 12 can remain below the water line 20 while it is processed and flowed back to the wellbore 16, discharged into the surrounding water or pumped into the injection wellbore 70.

[0039] A method 30 of drilling a subterranean well is provided to the art by this disclosure. In one example, the method can comprise: drilling a first wellbore 16 without a riser connected between a subsea wellhead 26 and a drilling rig 14, the drilling step including sealing about a drill string 28 with a rotating control device assembly 22; flowing fluid 12 into the first wellbore 16 during the drilling; and returning the fluid 12 from the first wellbore 16 during the drilling. The fluid 12 remains subsea after the flowing step and during the drilling step.

[0040] The fluid 12 returned from the first wellbore 16 may be discharged subsea.

[0041] The method 30 may include removing cuttings 40 from the fluid 12 returned from the first wellbore 16. The removing step may be performed subsea. The method 30 may include discharging the cuttings 40 subsea.

[0042] The method 30 may include removing waste 54 from the fluid 12 returned from the first wellbore 16. The removing step may be performed subsea. The method 30 may include discharging the waste 54 subsea.

[0043] The method 30 may include separating gas 48 from the fluid 12 returned from the first wellbore 16. The separating step may be performed subsea.

[0044] The method 30 may include injecting the fluid 12 returned from the first wellbore 16 into a second wellbore 70.

[0045] The method 30 may include injecting a first portion of the fluid 12 returned from the first wellbore 16 into a second wellbore 70, and flowing a second portion of the fluid 12 returned from the first wellbore 16 back into the first wellbore 16. The method 30 may include discharging subsea a third portion of the fluid 12 returned from the first wellbore 16.

[0046] This disclosure also provides to the art a well drilling system 10. In one example, the system 10 comprises: a drill string 28 extending from a drilling rig 14 into a first wellbore 16, the drill string 28 being free of a riser string enclosing the drill string 28; a rotating control device assembly 22 connected above a subsea wellhead 26, the rotating control device assembly 22 sealing about the drill string 28; and a fluid return line 44 connected to the rotating control device assembly 22, the fluid return line 44 being configured to flow fluid 12 from the rotating control device assembly 22 without the fluid 12 being flowed to the drilling rig 14.

[0047] The fluid return line 44 may be configured so that the fluid 12 flowed from the rotating control device assembly 22 is maintained subsea.

[0048] The system 10 may include a discharge line 46 configured to discharge subsea at least a portion of the fluid 12 flowed from the rotating control device assembly 22.

[0049] The system 10 may include a cuttings separator 42 positioned subsea and connected to the fluid return line 44. The system 10 may include a discharge line 46 configured to discharge cuttings 40 subsea.

[0050] The system 10 may include a processing unit 52 positioned subsea and connected to the fluid return line 44, the processing unit 52 being configured to remove waste 54 from the fluid 12. The system 10 may include a discharge line 46 configured to discharge the waste 54 subsea.

[0051] The system 10 may include a gas separator 50 positioned subsea and connected to the fluid return line 44.

[0052] The system 10 may include a pump 60 positioned subsea and connected to the fluid return line 44. The pump 60 may be configured to pump the fluid 12 from the fluid return line 44 into a second wellbore 70. The pump 60 may be configured to pump a first portion of the fluid 12 into a second wellbore 70, and to pump a second portion of the fluid to the first wellbore 16.

[0053] Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and / or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.

[0054] Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.

[0055] It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.

[0056] In the above description of the representative examples, directional terms (such as “above,”“below,”“upper,”“lower,”“upward,”“downward,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.

[0057] The terms “including,”“includes,”“comprising,”“comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.”

[0058] Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.

Examples

Embodiment Construction

[0015]Representatively illustrated in FIGS. 1 & 2 are examples of a well drilling system 10 and associated method 30 which can embody principles of this disclosure. However, it should be clearly understood that the system 10 and method 30 are merely examples of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system 10 and method 30 as described herein and / or depicted in the drawings.

[0016]In the FIGS. 1 & 2 system 10 and method 30, fluid 12 is flowed from one or more drilling rig 14 into one or more wellbore 16 via a fluid delivery line 18. Below a water line 20, a rotating control device assembly 22 is connected above a blowout preventer stack 24, which is connected above a subsea wellhead 26. The rotating control device assembly 22 includes a rotatable annular seal that seals about a drill string 28 used to drill the wellbore 16.

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Claims

1. A method of drilling a subterranean well, the method comprising:drilling a first wellbore without a riser connected between a subsea wellhead and a drilling rig positioned over a body of water, the drilling including sealing about a drill string with a rotating control device assembly;flowing fluid into the first wellbore during the drilling; andreturning the fluid from the first wellbore during the drilling,in which the fluid is not returned to the drilling rig after the returning the fluid from the first wellbore, and in which at least a portion of the fluid is pumped into at least one of the first wellbore and a second wellbore while the fluid remains subsea.

2. The method of claim 1, in which the fluid returned from the first wellbore is discharged subsea into a processing unit.

3. The method of claim 1, further comprising removing cuttings from the fluid returned from the first wellbore, the removing being performed subsea.

4. The method of claim 3, further comprising discharging the cuttings subsea into the body of water.

5. The method of claim 1, further comprising removing waste from the fluid returned from the first wellbore, the removing being performed subsea.

6. The method of claim 5, further comprising discharging the waste subsea into the body of water.

7. The method of claim 1, further comprising separating gas from the fluid returned from the first wellbore, the separating being performed subsea.

8. The method of claim 1, further comprising injecting the fluid returned from the first wellbore into the second wellbore.

9. The method of claim 1, further comprising injecting a first portion of the fluid returned from the first wellbore into the second wellbore, and flowing a second portion of the fluid returned from the first wellbore back into the first wellbore.

10. The method of claim 9, further comprising discharging subsea into the body of water a third portion of the fluid returned from the first wellbore.

11. A well drilling system, comprising:a drill string extending from a drilling rig into a first wellbore, the drill string being free of a riser string enclosing the drill string;a rotating control device assembly connected above a subsea wellhead, the rotating control device assembly sealing about the drill string; anda fluid return line connected to the rotating control device assembly, in which fluid which exits the rotating control device assembly is not returned to the drilling rig, and in which at least a portion of the fluid is pumped into at least one of the first wellbore and a second wellbore while the fluid remains subsea.

12. The system of claim 11, in which the fluid return line is configured so that the fluid which exits the rotating control device assembly is maintained subsea.

13. The system of claim 11, further comprising a discharge line configured to discharge subsea at least a portion of the fluid which exits the rotating control device assembly.

14. The system of claim 11, further comprising a cuttings separator positioned subsea and connected to the fluid return line.

15. The system of claim 14, further comprising a discharge line configured to discharge cuttings subsea.

16. The system of claim 11, further comprising a processing unit positioned subsea and connected to the fluid return line, the processing unit being configured to remove waste from the fluid.

17. The system of claim 16, further comprising a discharge line configured to discharge the waste subsea.

18. The system of claim 11, further comprising a gas separator positioned subsea and connected to the fluid return line.

19. The system of claim 11, further comprising a pump positioned subsea and connected to the fluid return line, the pump being configured to pump the fluid from the fluid return line into the second wellbore.

20. The system of claim 11, further comprising a pump positioned subsea and connected to the fluid return line, the pump being configured to pump a first portion of the fluid into the second wellbore, and to pump a second portion of the fluid to the first wellbore.

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