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Title:
RUNNING TOOL ASSEMBLY AND METHOD
Document Type and Number:
WIPO Patent Application WO/2019/168981
Kind Code:
A1
Abstract:
A running tool configured to install one or more components of a well system includes a mandrel, a first latch including a collet finger that includes an engagement member, a piston slidably disposed about the mandrel, and a second latch pivotally coupled to the mandrel, wherein the first latch is configured to releasably couple with a first component of the well system.

Inventors:
BENNETT, Dean (7909 Parkwood Circle Drive, Houston, Texas, 77036, US)
KULKARNI, Ajay (7909 Parkwood Circle Drive, Houston, Texas, 77036, US)
ZAGOURIS, Andoni (7909 Parkwood Circle Drive, Houston, Texas, 77036, US)
WANG, Yang (7909 Parkwood Circle Drive, Houston, Texas, 77036, US)
Application Number:
US2019/019826
Publication Date:
September 06, 2019
Filing Date:
February 27, 2019
Export Citation:
Click for automatic bibliography generation   Help
Assignee:
NATIONAL OILWELL VARCO, L.P. (7909 Parkwood Circle Drive, Houston, Texas, 77036, US)
International Classes:
E21B23/04
Foreign References:
US5040598A1991-08-20
GB2058879A1981-04-15
US5655606A1997-08-12
US4756364A1988-07-12
US3638988A1972-02-01
Other References:
None
Attorney, Agent or Firm:
HOOPER, James A. et al. (575 N. Dairy Ashford Rd, Suite 1102Houston, Texas, 77079, US)
Download PDF:
Claims:
CLAIMS

What is claimed is:

1. A running tool configured to install one or more components of a well system, comprising:

a mandrel;

a first latch comprising a collet finger that includes an engagement member;

a piston slidably disposed about the mandrel; and

a second latch pivotally coupled to the mandrel;

wherein the first latch is configured to releasably couple with a first component of the well system.

2. The running tool of claim 1, wherein the piston is configured to maintain a first position relative to the mandrel and a second position relative to the mandrel, wherein the second position is axially spaced from the first position.

3. The running tool of claim 2, further comprising:

a first chamber in the piston; and

a second chamber in the piston, wherein fluid communication is restricted between the first chamber and the second chamber;

wherein the piston is configured to actuate from the first position to the second position in response to pressurizing the first chamber; and

wherein the piston is configured to actuate from the second position to the first position in response to pressurizing the second chamber.

4. The running tool of claim 3, wherein:

the first component comprises a protective sleeve landable in an outer housing of a rotating control device (RCD);

when the piston is disposed in the first position, the first latch is configured to axially lock to the protective sleeve; and

when the piston is disposed in the second position, the first latch is configured to axially unlock from the sleeve.

5. The running tool of claim 3, wherein the mandrel comprises a radial port in fluid communication with a central passage of the mandrel.

6. The running tool of claim 5, wherein an inner surface of the mandrel comprises an annular seat configured to receive an obturating member that is configured to restrict fluid flow through the central passage of the mandrel.

7. The running tool of claim 2, further comprising a biasing member configured to bias the piston towards the first position.

8. The running tool of claim 2, wherein the second latch is configured to releasably couple with a second component of the well system.

9. The running tool of claim 8, wherein:

the second component comprises a seal assembly landable in an outer housing of a rotating control device (RCD); and

when the piston is disposed in the first position, the second latch is configured to axially lock to the seal assembly.

10. The running tool of claim 9, wherein, when the piston is disposed in the second position, the second latch is configured to axially unlock from the seal assembly.

11. A running tool configured to install components of a well system, comprising:

a mandrel;

a first engagement member coupled to the mandrel;

a piston slidably disposed about the mandrel; and

a second engagement member coupled to the mandrel;

wherein the first engagement member is configured to releasably couple with an inner surface of a first component of the well system and the second engagement member is configured to releasably couple with an outer surface of a second component of the well system.

12. The running tool of claim 11, wherein the first component comprises a protective sleeve of a rotating control device (RCD) and the second component comprises a seal assembly of the RCD.

13. The running tool of claim 11, further comprising a collet finger coupled to the mandrel, wherein the first engagement member forms a terminal end of the collet finger.

14. The running tool of claim 11, further comprising:

a piston slidably disposed about the mandrel; and

a latch pivotally coupled to the mandrel, wherein the second engagement member forms a terminal end of the latch;

wherein the piston is configured to maintain a first position permitting relative movement between the latch and the mandrel, and a second position axially spaced from the first position that restricts relative movement between the latch and the mandrel.

15. The running tool of claim 14, further comprising:

a first chamber in the piston; and

a second chamber in the piston, wherein fluid communication is restricted between the first chamber and the second chamber;

wherein the piston is configured to actuate from the first position to the second position in response to pressurizing the first chamber;

wherein the piston is configured to actuate from the second position to the first position in response to pressurizing the second chamber.

16. The running tool of claim 15, wherein:

the mandrel comprises a radial port in fluid communication with a central passage of the mandrel; and

an inner surface of the mandrel comprises an annular seat configured to receive an obturating member to restrict fluid flow through the central passage of the mandrel.

17. The running tool of claim 14, wherein:

the piston includes an outer surface having a groove formed therein;

the first engagement member is axially spaced from the groove when the piston is in the first position; and the first engagement member is axially aligned with the groove when the piston is in the second position.

18. The running tool of claim 17, wherein:

the first engagement member is permitted to be displaced from a radially outer position into a radially inner position at least partially received in the groove of the piston when the piston is disposed in the second position; and

the first engagement member is restricted from being displaced into the radially inner position when the piston is in the first position.

19. The running tool of claim 14, further comprising a biasing member configured to bias the piston towards the first position.

20. The running tool of claim 11, further comprising a stabbing nose coupled to an end of the mandrel, wherein the stabbing nose comprises a frustoconical outer surface.

21. A method for installing components in a well system using a running tool, comprising:

(a) actuating a piston of the running tool to lock a first engagement member of the running tool to an inner surface of a first component of the well system; and

(b) actuating the piston to lock a second engagement member of the running tool to an outer surface of a second component of the well system.

22. The method of claim 21, further comprising:

(c) landing or retrieving the first component within the well system using the running tool; and

(d) landing or retrieving the second component within the well system using the running tool.

23. The method of claim 21, wherein the first component comprises a protective sleeve of a rotating control device (RCD) and the second component comprises a seal assembly of the RCD.

24. The method of claim 21, further comprising: (c) pressurizing a first chamber located in the piston to actuate the piston from a first position to a second position; and

(d) pressurizing a second chamber located in the piston to actuate the piston from the second position to the first position.

25. The method of claim 24, further comprising:

(e) landing an obturating member against a seat formed in a central passage of the mandrel; and

(f) pressurizing the second chamber in response to landing the obturating member against the seat.

26. The method of claim 21, further comprising:

(c) biasing the piston from a first position to a second position with a biasing member; and

(d) pressurizing a second chamber located in the piston to actuate the piston from the second position to the first position.

Description:
RUNNING TOOL ASSEMBLY AND METHOD

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims priority to U.S. provisional patent application No. 62/636,625 filed February 28, 2018, and entitled“Running Tool Assembly and Method” which is incorporated herein by reference in its entirety

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] Not applicable.

BACKGROUND

[0003] To drill a wellbore in an earthen formation to a subterranean reservoir, a drilling rig is positioned over the desired location of the wellbore and a drillstring suspended from the drilling rig through a blowout preventer (BOP) mounted to a wellhead at the surface and into the subterranean formation. During the drilling process, drilling fluid or mud is pumped through the drill string and exits the face of a drill bit connected to the lower end of the drillstring. The drilling fluid exiting the drill bit is recirculated to the surface via the annulus between the drillstring and the inner surface of the wellbore and then through the annulus between the drilling and the inner surface of the BOP. In onshore drilling applications, a rotating control device (RCD) is typically mounted to an upper end of the BOP and controls the flow and pressure of drilling fluid out the BOP annulus, and hence, controls the flow and pressure of drilling fluid from the wellbore annulus. For instance, the RCD often includes an inner rotating seal for sealingly engaging the outer surface of the drillstring as the drillstring rotates and an annular outer seal that sealingly engages the BOP, thereby effectively capping the upper end of the annulus. The RCD may include one or more side outlets for allowing the passage of drilling fluid from the annulus of the wellbore.

[0004] Some offshore applications also include RCDs or similar devices for controlling flow and pressure from the annulus. For instance, in offshore applications, the drillstring typically extends from a drilling vessel at the surface of the water through a marine riser extending between the drilling vessel and the subsea BOP mounted to the wellhead at the sea floor into the wellbore. The recirculated drilling fluid flows through the wellbore annulus, the BOP annulus, and the annulus between the drillstring and the inner surface of the marine riser to the drilling vessel. In some applications, an RCD is coupled to an upper end of the marine riser proximal the drilling vessel. The RCD includes an inner seal assembly for sealingly engaging the outer surface of the drillstring as the drillstring rotates and an annular outer seal that sealingly engages the upper end of the marine riser, thereby effectively capping the upper end of the annulus in the marine riser, and hence, capping the BOP annulus and the wellbore annulus. In some applications, the seal assembly may be both removable and installable within an outer housing of the RCD using a running tool suspended from the drilling rig.

SUMMARY OF THE DISCLOUSRE

[0005] An embodiment of a running tool configured to install one or more components of a well system comprises a mandrel, a first latch comprising a collet finger that includes an engagement member, a piston slidably disposed about the mandrel, and a second latch pivotally coupled to the mandrel, wherein the first latch is configured to releasably couple with a first component of the well system. In some embodiments, the piston comprises a first position relative to the mandrel and a second position relative to the mandrel, wherein the second position is axially spaced from the first position. In some embodiments, the running tool further comprises a first chamber formed in the piston, and a second chamber formed in the piston, wherein fluid communication is restricted between the first chamber and the second chamber, wherein the piston is configured to actuate from the first position to the second position in response to pressurizing the first chamber, wherein the piston is configured to actuate from the second position to the first position in response to pressurizing the second chamber. In certain embodiments, the first component comprises a protective sleeve landable in an outer housing of a rotating control device (RCD), when the piston is disposed in the first position, the first latch is configured to axially lock to the protective sleeve, and when the piston is disposed in the second position, the first latch is configured to axially unlock from the sleeve. In certain embodiments, the mandrel comprises a radial port in fluid communication with a central passage of the mandrel. In some embodiments, an inner surface of the mandrel comprises an annular seat configured to receive an obturating member to restrict fluid flow through the central passage of the mandrel. In some embodiments, the running tool further comprises a biasing member configured to bias the piston towards the first position. In certain embodiments, the second latch is configured to releasably couple with a second component of the well system. In certain embodiments, the second component comprises a seal assembly landable in an outer housing of a rotating control device (RCD), and when the piston is disposed in the first position, the second latch is configured to axially lock to the seal assembly. In some embodiments, when the piston is disposed in the second position, the second latch is configured to axially unlock from the seal assembly.

[0006] An embodiment of a running tool configured to install components of a well system comprises a mandrel, a first engagement member coupled to the mandrel, a piston slidably disposed about the mandrel, and a second engagement member coupled to the mandrel, wherein the first engagement member is configured to releasably couple with an inner surface of a first component of the well system and the second engagement member is configured to releasably couple with an outer surface of a second component of the well system. In some embodiments, the first component comprises a protective sleeve of a rotating control device (RCD) and the second component comprises a seal assembly of the RCD. In some embodiments, the running tool further comprises a collet finger coupled to the mandrel, wherein the first engagement member forms a terminal end of the collet finger. In certain embodiments, the running tool further comprises a piston slidably disposed about the mandrel, and a latch pivotally coupled to the mandrel, wherein the second engagement member forms a terminal end of the latch, wherein the piston comprises a first position restricting permitting relative movement between the latch and the mandrel, and a second position axially spaced from the first position that restricts relative movement between the latch and the mandrel. In some embodiments, the running tool further comprises a first chamber formed in the piston, and a second chamber formed in the piston, wherein fluid communication is restricted between the first chamber and the second chamber, wherein the piston is configured to actuate from the first position to the second position in response to pressurizing the first chamber, wherein the piston is configured to actuate from the second position to the first position in response to pressurizing the second chamber. In certain embodiments, the mandrel comprises a radial port in fluid communication with a central passage of the mandrel, and an inner surface of the mandrel comprises an annular seat configured to receive an obturating member to restrict fluid flow through the central passage of the mandrel. In certain embodiments, the piston includes an outer surface having a groove formed therein, the first engagement member is axially spaced from the groove when the piston is in the first position, and the first engagement member is axially aligned with the groove when the piston is in the second position. In some embodiments, the first engagement member is permitted to be displaced from a radially outer position into a radially inner position at least partially received in the groove of the piston when the piston is disposed in the second position, and the first engagement member is restricted from being displaced into the radially inner position when the piston is in the first position. In some embodiments, the running tool further comprises a biasing member configured to bias the piston towards the first position. In certain embodiments, the running tool further comprises a stabbing nose coupled to an end of the mandrel, wherein the stabbing nose comprises a frustoconical outer surface.

[0007] An embodiment of a method for installing components in a well system using a running tool comprises (a) actuating a piston of the running tool to lock a first engagement member of the running tool to an inner surface of a first component of the well system, and (b) actuating the piston to lock a second engagement member of the running tool to an outer surface of a second component of the well system. In some embodiments, the method further comprises (c) landing or retrieving the first component within the well system using the running tool, and (d) landing or retrieving the second component within the well system using the running tool. In some embodiments, the first component comprises a protective sleeve of a rotating control device (RCD) and the second component comprises a seal assembly of the RCD. In certain embodiments, the method further comprises (c) pressurizing a first chamber located in the piston to actuate the piston from a first position to a second position, and (d) pressurizing a second chamber located in the piston to actuate the piston from the second position to the first position. In certain embodiments, the method further comprises (e) landing an obturating member against a seat formed in a central passage of the mandrel, and (f) pressurizing the second chamber in response to landing the obturating member against the seat. In some embodiments, the method further comprises (c) biasing the piston from a first position to a second position with a biasing member, and (d) pressurizing a second chamber located in the piston to actuate the piston from the second position to the first position.

BRIEF DESCRIPTION OF THE DRAWINGS

[0008] For a detailed description of various exemplary embodiments, reference will now be made to the accompanying drawings in which:

[0009] Figure 1 is a schematic view of an embodiment of an offshore drilling system in accordance with the principles disclosed herein;

[0010] Figure 2 is a perspective view of an embodiment of a running tool for installing and removing components of a rotating control device (RCD) of the drilling system of Figure 1 in accordance with principles disclosed herein;

[0011] Figure 3 is a front view of the running tool of Figure 2;

[0012] Figure 4 is a cross-sectional view along lines 4-4 of Figure 3 of the running tool of Figure 2; [0013] Figure 5 is a side cross-sectional view of an embodiment of a piston body of the running tool of Figure 2 disposed in a lower position in accordance with principles disclosed herein;

[0014] Figure 6 is a side cross-sectional view of the piston body of Figure 5 disposed in an upper position;

[0015] Figure 7 is a side cross-sectional view of an embodiment of the RCD of the drilling system of Figure 1, an embodiment of a protective sleeve of the RCD, and the running tool of Figure 2 shown in a first position;

[0016] Figure 8 is a side cross-sectional view of the RCD and protective sleeve of Figure 7 and the running tool of Figure 2 shown in a second position;

[0017] Figure 9 is a side cross-sectional view of the RCD and protective sleeve of Figure 7 and the running tool of Figure 2 shown in a second position;

[0018] Figure 10 is a side cross-sectional view of an embodiment of a seal assembly of the RCD of Figure 7 and the running tool of Figure 2 shown in a first position;

[0019] Figure 11 is a side cross-sectional view of the seal assembly of Figure 10 and the running tool of Figure 2 shown in a second position;

[0020] Figure 12 is a front view of another embodiment of a running tool for installing and removing components of the RCD of the drilling system of Figure 1 in accordance with principles disclosed herein;

[0021] Figure 13 is a side cross-sectional view of the running tool of Figure 12; and

[0022] Figure 14 is a side cross-sectional view of another embodiment of a running tool for installing and removing components of the RCD of the drilling system of Figure 1 in accordance with principles disclosed herein.

DETAILED DESCRIPTION OF THE DISCLOSED EXEMPLARY EMBODIMENTS

[0023] The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

[0024] Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

[0025] In the following discussion and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to... ." Also, the term "couple" or "couples" is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms "axial" and "axially" generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms "radial" and "radially" generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. As used herein, the term“well site personnel” is used broadly to include any individual or group of individuals who may be disposed or stationed on a rig or worksite or offsite at a remote monitoring location (such as a remote office location). The term also would include any personnel involved in the drilling and/or production operations at or for an oil and gas well such as, for example, technicians, operators, engineers, analysts, etc.

[0026] Referring now to Figure 1, an embodiment of an offshore drilling or well system 10 for drilling a subsea wellbore 24 in an earthen formation 7 is shown. In the embodiment of Figure 1, system 10 generally includes a drilling vessel 12 disposed at the surface 3 of the water (i.e., at the waterline 3), a wellhead 20 disposed at the sea floor 5, a BOP stack 56 mounted atop the wellhead 20, a lower marine riser package (LMRP) 54 mounted atop BOP stack 56, casing 24 extending from wellhead 20 into wellbore 24, and a marine riser system 30 extending from the drilling vessel 12 to LMRP 54. Wellbore 24, casing 24, wellhead 20, BOP stack 56, LMRP 54, and riser system 30 share a common, generally vertically oriented central or longitudinal axis 15. Drilling vessel 12 includes a drilling floor 14 and a derrick 16 extending upwards from the drilling floor 14. In this embodiment, drilling vessel 12 is a floating offshore structure, and more particularly, a floating semi-submersible platform. However, in other embodiments, the drilling vessel (e.g., vessel 12) may comprise other drilling vessels known in the art, such as drilling ships, tension leg platform, jack-up platform, and the like. [0027] Marine riser system 30 provides a conduit for flowing drilling fluid or mud through the water between the drilling vessel 12 and the LMRP 54, BOP stack 56, and wellhead 24 disposed at the sea floor 5. More specifically, during drilling operations, drilling fluid is pumped from drilling vessel 12 down a drillstring 18 (shown with dashed lines) suspended from vessel 12 through marine riser system 30, LMRP 54, BOP stack 56, wellhead 20, and casing 24 into wellbore 22. The drilling fluid exits the drillstring 18 at a drill bit (not shown) connected to the lower end of drillstring 18 in the wellbore 24. Upon exiting the drillstring 18, the drilling fluid circulates back to the drilling vessel 12 through a series of contiguous, interconnected annuli radially positioned between drillstring 18 and the inner surfaces of wellbore 22, casing 24, wellhead 20, BOP stack 56, LMRP 54, and riser system 30.

[0028] Referring still to Figure 1, and moving downward from vessel 12, in this embodiment, marine riser system 30 includes a diverter bowl 32 disposed just below and proximal drilling floor 14, a rotating control device (RCD) 300 coupled to a lower end of diverter bowl 32, a telescopic joint 34 having an upper end coupled to RCD 300, a tension ring 40 attached to joint 34, , an annular blowout preventer (BOP) 44 coupled to telescopic joint 34, and a tubular marine riser 52 extending from annular BOP 44 to LMRP 54. Diverter bowl 32 defines the upper end of the marine riser system 30 and generally functions to divert annular flow (e.g., gas flows) during installation of marine riser system 30. Joint 34 includes an inner housing 36 and an outer housing 38 that can slide axially relative to each other, thereby allowing joint 34 to axially extend and contract. This functionality compensates for heave (relative vertical movement) between the marine riser system 30 and the drilling vessel 12. In this manner, heave experienced by drilling vessel 12 is accommodated without damaging components of marine riser system 30. In some embodiments, an annular packer is positioned between the inner housing 36 and the outer housing 38 to seal therebetween.

[0029] Tension ring 40 is disposed about and securely attached to the outside of outer housing 38 and suspended from a plurality of tension cables 42 extending from vessel 12. Thus, tension ring 40 and cables 42 support the components of marine riser system 30 suspended from outer housing 38 and apply tensile loads thereto.

[0030] RCD 300 is coupled to the lower end of telescopic joint 34. As will be described in more detail below, RCD 300 seals the upper end of the continuous annulus extending through marine riser system 30 from wellbore 24, thereby allowing flow of drilling fluid through the annulus to be controlled and pressurized. Annular BOP 44 is coupled to the lower end of RCD 300 and can be actuated in response to an uncontrolled influx of fluids from formation 7 into wellbore 24 to completely seal and close the annulus extending through marine riser system 30, thereby shutting in wellbore 24. A plurality of accumulators 46 are provided along riser system 30 for operating annular BOP 44. Accumulators 46 may also be utilized to actuate components of RCD 300, as will be discussed further herein.

In this embodiment, RCD 300 is positioned above tension ring 40 and includes a plurality of side outlets or return lines 302 that extend from RCD 300 and provide a flow path for drilling fluid in the annulus of marine riser system 30 to return to drilling vessel 12. Thus, in this embodiment, drilling fluid returning from wellbore 24 passes through the annulus within riser system 30 to RCD 300, and is then routed from RCD 300 through return conduits 302 extending therefrom to vessel 12. In other embodiments, RCD 300 may not include side outlets 302, and instead, fluids flowing from wellbore 24 may be circulated to the drilling vessel 12 via a diverter spool coupled to marine riser 52, the diverter spool including return conduits extending to drilling vessel 12.

[0031] Referring to Figures 1-6, an embodiment of a running tool 100 for installing components in and/or removing components from RCD 300 is shown in Figures 2-6. Although in this embodiment running tool 100 is described in the context of manipulating components of RCD 300, in other embodiments, running tool 100 may be used to manipulate, install, and/or uninstall other components of drilling system 10. In the embodiment of Figures 2-6, running tool 100 has a central or longitudinal axis 105 and generally includes a mandrel 102, a stabbing nose 120, a first or upper latch 130, a piston assembly 160, and a plurality of second or lower latches 200. Mandrel 102 is generally cylindrical and has a first or upper end 102A, a second or lower end 102B opposite upper end 102A, a central bore or passage 104 defined by a generally cylindrical inner surface 106 extending between ends 102A and 102B, and a generally cylindrical outer surface 108 extending between ends 102 A and 102B.

[0032] In this embodiment, inner surface 106 of mandrel 102 includes a releasable first or upper connector 110A at the upper end 102 A of mandrel 102. Upper connector 110A may releasably (e.g., threadably) couple with a corresponding releasable connector of a conveyance string or other device for lowering running tool 100 into and out of the marine riser system 30 of drilling system 10. In some embodiments, drillstring 18 may be retracted from wellbore 24 and upper connector 110A of mandrel 102 may be threadably connected to a lower end of drillstring 18. In this configuration, drillstring 18 and running tool 100 may be lowered into marine riser system 30 via the derrick 16 of drilling vessel 12. Additionally, the outer surface 108 of mandrel 102 includes a releasable second or lower connector 110B at the lower end 102B of mandrel 102 for releasably (e.g., threadably) coupling mandrel 102 with stabbing nose 120. Further, mandrel 102 includes a plurality of circumferentially spaced pivotal connectors 112 positioned on the outer surface 108 of mandrel 102 that pivotally couple lower latches 200 to mandrel 102. In this embodiment, stabbing nose 120 includes a releasable connector 122 located on an inner surface thereof that releasably connects with the lower connector 110B of mandrel 102. Stabbing nose 120 also includes a frustoconical or profiled outer surface 124 that assists in the stabbing of running tool 100 into the riser system 30 of drilling system 10.

[0033] In this embodiment, upper latch 130 comprises a base or hub 132 including an inner annular connector 134 coupled to the outer surface 108 of mandrel 102, and a plurality of circumferentially spaced collet fingers 136 extending axially from hub 132. The terminal end of each collet finger 136 comprises an engagement member 138. In this embodiment, hub 132 of upper latch 130 includes an annular internal shoulder 140 A that defines an upper end of the annular space formed between connector 134 and collet fingers 136. Additionally, hub 132 includes an annular external shoulder 140B. Additionally, hub 132 includes a pair of circumferentially spaced passages 142A, 142B that extend axially therethrough.

[0034] In this embodiment, piston assembly 160 of running tool 100 includes a piston or piston body 162 and an annular flange or stop member 190. Piston body 162 of piston assembly 160, which is slidably disposed about mandrel 102, is generally cylindrical and includes a first or upper end 162A, a second or lower end 162B, a generally cylindrical inner surface 164 extending between ends 162 A and 162B, and a generally cylindrical outer surface 166 extending between ends 162A and 162B. Inner surface 164 of piston body 162 comprises an annular seal 165 and a radially inwards extending flange 168 that includes an annular seal 170 positioned thereon, where seal 170 sealingly engages the outer surface 108 of mandrel 102. In this embodiment, flange 190 of piston assembly is coupled to the outer surface 108 of mandrel 102 and includes an annular shoulder 192 positioned proximal an upper end of flange 190 and an annular seal 194 located on an outer cylindrical surface of flange 190.

[0035] An annular first or upper chamber 172 is formed radially between the inner surface 164 of piston body 162 and the outer surface 108 of mandrel 102, where upper chamber 172 extends axially between seals 165, 170 of piston body 162. Additionally, an annular second or lower chamber 174 is also formed radially between the inner surface 164 of piston body 162 and the outer surface 108 of mandrel 102, where lower chamber 174 extends axially between seal 170 of piston body 162 and seal 194 of flange 190. In this embodiment, piston body 162 of piston assembly 160 includes a pair of fluid passages 176A, 176B extending from upper end 162A. Particularly, first fluid passage 176A extends between upper end 162A and upper chamber 172 while second fluid passage 176B extends between upper end 162A and lower chamber 174. Further, piston assembly 160 includes a pair of fluid conduits 178A, 178B coupled to the upper end 162A of piston body 162. Particularly, first conduit 178A is slidably disposed in the first passage 142A of hub 132 and is in fluid communication with first fluid passage 176A of piston body 162 while second conduit 178B is slidably disposed in the second passage 142B of hub 132 and is in fluid communication with second fluid passage 176B of piston body 162.

[0036] In this embodiment, the inner surface 164 of piston body 162 further includes an annular shoulder 180 that matingly engages the shoulder 192 of flange 190, as will be described further herein. Additionally, the outer surface 166 of piston body 162 includes an annular groove 182 configured to matingly receive the engagement members 138 of the collet fingers 136 of upper latch 130, as will be described further herein. Further, in this embodiment, a lower terminal end of each lower latch 200 comprises an engagement member 202. As will be described further herein in the context of RCD 300, upper latch 130 of running tool 100 permits running tool 100 to selectively latch or lock onto an inner cylindrical surface or profile of a tubular member while lower latches 200 permit running tool 100 to selectively latch or lock onto an outer cylindrical surface or profile of a tubular member. Thus, running tool 100 provides the ability to manipulate tubular members by selectively locking onto both inner and outer surfaces of the tubular member. In this manner, running tool 100 may reduce the number of separate running tools required for installing tubular members, such as tubular members of the riser system 30 of drilling system 10.

[0037] Each of fluid conduits 178 A, 178B may be connected to a fluid conduit or tubing extending between running tool 100 and drilling vessel 12 such that fluid conduits 178A, 178B may be selectively pressurized from drilling vessel 12 following the deployment of running tool 100 into marine riser system 30. Particularly, first fluid conduit 178A may be pressurized from drilling vessel 12 while second fluid conduit 178B is permitted to vent, thereby applying fluid pressure against a first or upper side 168A (shown in Figures 5, 6) of the flange 168 of piston body 162. The application of fluid pressure against the upper side 168A of flange 168 forces piston body 162 into an axially lower position (shown in Figure 5) respective upper latch 130 and lower latches 200. In the lower position of piston body 162, shoulder 180 of piston body 162 contacts the shoulder 192 of flange 190 (restraining downward movement of piston body 162 relative mandrel 102), the engagement members 138 of collet fingers 136 are axially spaced from the groove 182 of piston body 162, and the lower end 162B of piston body 162 is positioned over or covers the engagement members 202 of lower latches 200.

[0038] Second fluid conduit 178B may be pressurized from drilling vessel 12 while first fluid conduit 178A is permitted to vent, thereby applying fluid pressure against a second or lower side 168B (shown in Figures 5, 6) of the flange 168 of piston body 162. The application of fluid pressure against the lower side 168A of flange 168 forces piston body 162 upwards until the upper end 162A of piston body 162 contacts the internal shoulder 140A of upper latch 130, disposing piston body 162 in an axially upper position (shown in Figure 5) respective upper latch 130 and lower latches 200. In the upper position of piston body 162, the lower end 162B of piston body 162 is axially spaced from the engagement members 202 of lower latches 200 and the engagement members 138 of collet fingers 136 are axially aligned with groove 182 of piston body 162. In some embodiments, running tool 100 may include an annular retainer 210 (shown in Figures 2, 3) clamped to the outer surface 166 of piston body 162 to retain piston body 162 in the upper position when running tool 100 is not in use (e.g., when tool 100 is being stored on drilling vessel 12). Retainer 210 covers groove 182 of piston body 162, thereby preventing the engagement members 138 of upper latch 130 from becoming latched in groove 182. Although in this embodiment piston body 162 is actuatable between upper and lower positions in response to the application of hydraulic pressure to chambers 172, 174, in other embodiments, piston body 162 may be actuated in response to the application of mechanical (e.g., a biasing member), electrical, or other mechanisms.

[0039] Referring to Figures 1, 4, and 7-9, an embodiment of the RCD 300 of the drilling system of Figure 1 is shown in Figures 7-9. In the embodiment of Figures 7-9, RCD 300 has a central or longitudinal axis 305 and generally includes an outer housing 302, a plurality of actuatable locking members or dogs 320, a cylindrical protective sleeve 340 positionable within outer housing 302, and a seal assembly 360 (shown in Figures 10, 11) also positionable within outer housing 302, as will be described further herein.

[0040] In this embodiment, housing 302 of RCD 300 is generally cylindrical and includes a first or upper end 302A, a second or lower end (not shown in Figures 7-9) opposite upper end 302A, a central bore or passage 304 defined by a generally cylindrical inner surface 306 that extends between upper end 302A and the lower end of housing 302, and a plurality of circumferentially spaced apertures 308 extending radially between inner surface 306 and a generally cylindrical outer surface of housing 302, and a pair of circumferentially spaced ports 310 extending radially between inner surface 306 and the outer surface of housing 302, where ports 310 are in fluid communication with side outlets 302 (not shown in Figures 7-9) following the installation of RCD 300 in drilling system 10. The inner surface 306 of housing 302 includes at least one annular landing shoulder or profile 312 configured to matingly engage a corresponding landing shoulder or profile of the seal assembly 360 of RCD 300, as will be described further herein. Locking dogs 320 of RCD 300 are positioned in apertures 308 of outer housing 302 and are configured to selectively actuate from a first or radially inner position (shown in Figures 7, 8) respective central axis 305 and a second or radially outer position (shown in Figure 9). In this embodiment, locking dogs 320 are actuated between their respective radially inner and outer positions in response to the application of fluid pressure controlled at drilling vessel 12; however, in other embodiments, the actuation of locking dogs 320 may be controlled via other mechanisms (e.g., electrically, mechanically, pneumatically, etc.).

[0041] Protective sleeve 340 of RCD 300 protects the inner surface 306 of housing 302 from damage resulting from contact with abrasive fluids and/or equipment transported through passage 304 during the operation of drilling system 10. For instance, protective sleeve 340 may be used to cover and thereby protect the landing profile 312 of housing 302 from damage prior to the installation of the seal assembly 360 of RCD 300 in housing 302. In this embodiment, protective sleeve 340 includes a first or upper end 340 A, a second or lower end 340B opposite upper end 340A, a central bore or passage defined by a generally cylindrical inner surface 342 extending between upper end 340A and lower end 340B, and a generally cylindrical outer surface 344 extending between ends 340A, 340B. In this embodiment, the inner surface 342 of protective sleeve 340 includes an annular inner landing profile or shoulder 346 located proximal upper end 340A and an inner locking groove 348. The outer surface 344 of protective sleeve 340 includes an annular outer locking groove 350 and an annular outer landing profile or shoulder 352. Additionally, in this embodiment, a plurality of annular seals 354 are positioned on the outer surface 344 of protective sleeve 340 to restrict fluid in passage 304 of housing 302 from contacting portions of the inner surface 306 of housing 302.

[0042] In some applications, following the installation of the housing 302 (including protective sleeve 340 coupled thereto) of RCD 300 in drilling system 10, it may be desirable to remove protective sleeve 340 from housing 302 such that seal assembly 360 of RCD 300 may installed within housing 302. The embodiment of running tool 100 shown in Figure 4 may be used to both remove protective sleeve 340 from housing 302 and install seal assembly 360 within housing 302. Particularly, in this embodiment, mandrel 102 is coupled to a conveyance member (e.g., drillstring 18) and run into riser system 30 (with piston body 162 being disposed in the lower position) until engagement members 138 of upper latch 130 lands against the inner landing profile 346 of protective sleeve 340 (shown in Figure 7), thereby preventing further downward travel of running tool 100 through riser system 30 (diverter bowl 32 is hidden in Figures 7-9). In this manner, contact between engagement members 138 of upper latch 130 and inner landing profile 346 of protective sleeve 340 provides a positive indication to personnel of drilling system 10 located at drilling vessel 12 of the landing of running tool 100 within the housing 302 of RCD 300.

[0043] Following the landing of running tool 100 against protective sleeve 340, the upper chamber 172 of piston assembly 160 is vented while lower chamber 174 is pressurized from drilling vessel 12 via fluid conduits 178A, 178B (hidden in Figures 7-9), thereby forcing piston body 162 upwards into the upper positon where engagement members 138 of the collet fingers 136 of upper latch 130 are axially aligned with groove 182 of piston body 162. With piston body 162 disposed in the upper position, engagement members 138 of collet fingers 136 are permitted to flex inwards and running tool 100 may be run further into riser system 30 until engagement members 138 of upper latch 130 land against the inner locking groove 348 of protective sleeve 340 (shown in Figure 8), thereby preventing further downward travel of running tool 100 through riser system 30. In this manner, contact between engagement members 138 of upper latch 130 and inner locking groove 348 provides a positive indication to personnel of drilling system 10 that running tool 100 has fully landed within housing 302 such that engagement members 348 are axially aligned with inner locking groove 348.

[0044] With running tool 100 fully landed within housing 302 of RCD 300, the upper chamber 172 of piston assembly 160 is pressurized while lower chamber 174 is vented from drilling vessel 12 via fluid conduits 178A, 178B, thereby forcing piston body 162 downwards into the lower position. In the lower position of piston body 162 with engagement members 138 now axially misaligned with groove 182 of piston body 162, engagement members 138 are held or locked into inner locking groove 348 of protective sleeve 340 by contact from the outer surface 166 of piston body 162, thereby axially locking upper latch 130 of running tool 100 with protective sleeve 340.

[0045] Once running tool 100 is locked against protective sleeve 340, an axially directed upward force may be applied to running tool 100 from drilling vessel 12 (sometimes referred to as a“pull test”) to confirm the locking of running tool 100 with protective sleeve 340. Following the successful performance of the pull test against protective sleeve 340, locking dogs 320 are actuated into their radially outer positions, thereby disengaging locking dogs 320 from the outer locking groove 350 of protective sleeve 340 (shown in Figure 9). With locking dogs 320 disengaged from outer locking groove 350 of protective sleeve 340, relative axial movement is permitted between protective sleeve 340 and housing 302 and running tool 100, along with protective sleeve 340, may be retrieved to the drilling vessel 12.

[0046] Referring to Figures 1, 4, 10, and 11, an embodiment of the seal assembly 360 of the RCD 300 of Figures 7-9 is shown in Figures 10, 11. Seal assembly 360 is configured to seal against a tubular member (e.g. drillstring 18) extending through passage 304 of housing 302 while permitting relative rotation between the tubular member and housing 302. In the embodiment of Figures 10, 11, seal assembly 360 generally includes an outer or bearing housing 362, a bearing assembly 380, and a tubular seal housing 390. Bearing housing 362 couples seal assembly 360 with housing 302 and has a first or upper end 362A, a second or lower end 362B opposite upper end 362A, a central passage 364, and a generally cylindrical outer surface 366 extending between ends 362A, 362B. The outer surface 366 of bearing housing 362 includes an annular landing profile 368 for matingly engaging the landing profile 312 of housing 302, and a plurality of annular seals 370 for preventing the communication of fluid flow through the annular interface formed between the outer surface 366 of bearing housing 362 and the inner surface 306 of housing 302. Additionally, a plurality of annular seals 370 are positioned on an inner surface defining passage 364 of bearing housing 362 to seal the annular interface between bearing housing 362 and seal housing 390.

[0047] Bearing assembly 380 of seal assembly 360 is received within passage 364 of bearing housing 362 and comprises one or more bearings and allows for relative rotation between seal housing 390 and bearing housing 362 of seal assembly 360. Seal housing 390 of seal assembly 360 is rotatably disposed in bearing housing 362 and includes a first or upper end 390A, a second or lower end 390B opposite upper end 390A, and a generally cylindrical outer surface 392 extending between ends 390 A, 390B. Seal housing 390 is coupled to a first or upper seal member 400 A proximal upper end 390 A and a second or lower seal member 400B at lower end 390B. Seal members 400A and 400B are configured to sealingly engage a tubular member (e.g., drillstring 18) rotatably disposed in the housing 302 of RCD 300. In this embodiment, the outer surface 392 of seal housing 390 includes an annular locking groove 394 positioned adjacent upper end 390 A, where locking groove 394 is configured to interface with lower latches 200 of running tool 100.

[0048] In this embodiment, following the removal of protective sleeve 340 from housing 302 and retrieved to drilling vessel 12, sleeve 340 may be decoupled from upper latch 130 of running tool 100 by actuating piston body 162 into the upper position, thereby permitting engagement members 138 of the collet fingers 136 to flex inwardly such that protective sleeve 340 is unlocked from running tool 100. With protective sleeve 340 removed from running tool 100, stabbing guide 120 and mandrel 102 is stabbed through a central passage of the seal housing 390 of seal assembly 360 until the upper end 390A of seal housing 390 is disposed adjacent pivotal connectors 112 of mandrel 102. In this position, piston body 162 may be actuated from the upper position into the lower position, thereby forcing engagement members 202 of lower latches 200 into respective radially inner positions received at least partially in the locking groove 394 of seal housing 390. In the lower position of piston body 162, the lower end 162B of piston body 162 is axially aligned over or covers engagement members 202 of lower latches 200, locking engagement members 202 into the radially inner position and thereby locking seal assembly 360 with running tool 100.

[0049] Once running tool 100 is locked to seal assembly 360 with piston body 162 disposed in the lower position, run into riser system 30 (with locking dogs 320 of housing 302 disposed in the radially outer position) until the landing profile 368 of the bearing housing 362 of seal assembly 360 lands against the landing profile 312 of housing 302, preventing further downward travel of running tool 100 through riser system 30 (diverter bowl 32 is hidden in Figures 10, 11). Following the landing of seal assembly 360 within housing 302 of RCD 300, locking dogs 320 are actuated into the radially inner position from drilling vessel 12 to axially lock seal assembly 360 to housing 302, as shown in Figure 10.

[0050] Following a pull test on seal assembly 360 to ensure a positive locking of seal assembly 360 with housing 302, piston body 162 is actuated from the lower position to the upper position via fluid conduits 178A, 178B (hidden in Figures 10, 11). With piston body 162 disposed in the upper position, the lower end 162B of piston body 162 is axially spaced from, and thus does not cover, engagement members 202 of lower latches 200, permitting lower latches 200 to pivot radially outwards and thereby unlocking running tool 100 from seal assembly 360. Once running tool 100 has been unlocked from seal assembly 360 with piston body 162 disposed in the upper position, running tool 100 may be retrieved towards drilling vessel 12 with seal assembly 360 successfully installed in housing 302 of RCD 300, as shown in Figure 11.

[0051] Referring to Figures 1, 12, and 13, another embodiment of a running tool 500 for installing components in and/or removing components from RCD 300 of the drilling system 10 of Figure 1 is shown in Figures 12, 13. Running tool 500 of Figures 12, 13 includes features in common with the running tool 100 shown in Figures 2-11, and shared features are labeled similarly. In the embodiment of Figures 12, 13, running tool 500 has a central or longitudinal axis 505 and generally includes a mandrel 502, stabbing nose 120, upper latch 130', a piston assembly 520, and lower latches 200. Upper latch 130' of running tool 500 is similar to the upper latch 130 of running tool 100 except that the hub 132 of upper latch 130' does not include first passage 142A, and thus, only includes second passage 142B.

[0052] In this embodiment, mandrel 502 of running tool 500 is generally cylindrical and has a first or upper end 502A, a second or lower end 502B opposite upper end 502A, a central bore or passage 504 defined by a generally cylindrical inner surface 506 extending from upper end 502 A to a terminal end 510 that is spaced from lower end 502B, and a generally cylindrical outer surface 508 extending between ends 502A and 502B. Thus, unlike the passage 104 of the mandrel 102 of running tool 100, the passage 504 of mandrel 502 does not extend entirely through mandrel 502, and instead, terminates at the terminal end 510. Additionally, mandrel 502 includes a plurality of circumferentially spaced ports 512 located proximal terminal end 510, where each port 512 extends radially between inner surface 506 and outer surface 508. In other embodiments, passage 506 may extend entirely through mandrel 502 and a ball or dart receivable in a seat formed in passage 506 may be used to force fluid in passage 506 through ports 512.

[0053] In this embodiment, piston assembly 520 of running tool 500 includes piston body 162', flange 190, and a biasing member 522 disposed about mandrel 502. Piston body 162' of running tool 500 is similar to the piston body 162 of running tool 100 except that piston body 162' does not include first fluid passage 176A, and thus, only includes second fluid passage 176B with second conduit 178B coupled thereto. Further, in other embodiments, piston body 162' of running tool 500 may also not include second fluid passage 176B and upper latch 130' may not include second passage 142B. Biasing member 522 is positioned in upper chamber 172 and extends between a first or upper end 522A that contacts a lower end of the connector 134 of hub 132 and a second or lower end 522B that contacts the upper side 168A of the flange 168 of piston body 162'. In this embodiment, biasing member 522 comprises a coil spring; however, in other embodiments, biasing member 522 may comprise other springs or mechanisms configured to apply a biasing force.

[0054] Biasing member 522, via contact between lower end 522A and the upper side 168A of flange 168, biases piston body 162' towards the lower position shown in Figure 13. Thus, unlike the piston body 162 of running tool 100, which is actuated into the lower position via pressurizing upper chamber 172, piston body 162' of running tool 500 is actuated into the lower position via the biasing force provided by biasing member 522. Further, although piston body 162' may be actuated into the upper position by pressurizing second fluid passage 176B and second conduit 178B (thereby pressurizing lower chamber 174), piston body 162' may alternatively be actuated into the upper position by pressurizing passage 504 of mandrel 502, where pressure in passage 504 is communicated to lower chamber 174 via port 512 of mandrel 502. Thus, instead of supplying fluid pressure to second conduit 178B from drilling vessel 12 (e.g., via a hose extending between vessel 12 and second conduit 178B), fluid pressure may be supplied to passage 506 of mandrel 502 via a passage formed in the conveyance member (e.g., drillstring 18) from which mandrel 502 is suspended.

[0055] In this embodiment, it may not be necessary to run additional hoses or fluid conduits between drilling vessel 12 and running tool 500 to allow for the actuation of piston body 162' between the upper and lower positions. In this configuration, running tool 500 may be operated similarly as the running tool 100 shown in Figures 7-11 to uninstall protective sleeve 340 from the housing 302 of RCD 300 and install seal assembly 360 in housing 302, except that biasing member 522 is used to actuate piston body 162' into the lower position and fluid pressure from passage 506 of mandrel 502 may be used to actuate piston body 162' into the upper position. Particularly, fluid pressure in passage 506 of mandrel 502 (e.g., from drilling fluid supplied by drillstring 18) is balanced against the biasing force applied by biasing member 522 to control the actuation of piston body 162' between the upper and lower positions.

[0056] Referring to Figures 1, 14, another embodiment of a running tool 550 for installing components in and/or removing components from RCD 300 of the drilling system 10 of Figure 1 is shown in Figure 14. Running tool 550 of Figure 14 includes features in common with the running tool 100 shown in Figures 2-11 and the running tool 500 shown in Figures 12, 13, and shared features are labeled similarly. In the embodiment of Figure 14, running tool 550 has a central or longitudinal axis 555 and generally includes a mandrel 552, upper latch 130', piston assembly 520, and lower latches 200. In this embodiment, mandrel 552 of running tool 550 is generally cylindrical and has a central bore or passage 554 defined by a generally cylindrical inner surface 556 extending between upper and lower ends of mandrel 552, and a generally cylindrical outer surface 558 extending between the upper and lower ends of mandrel 552.

[0057] Like passage 104 of the mandrel 102 of running tool 100, passage 554 extends entirely through mandrel 552. However, unlike passage 104 of the mandrel 102 of running tool 100, the inner surface 556 defining passage 554 includes an annular seat 560 formed therein. In this embodiment, fluid may be circulated through passage 554 of mandrel 552 as running tool 550 is lowered into and through the riser system 30 of drilling system 10. For instance, the lower end of the mandrel 552 of running tool 550 may be coupled to a bottom hole assembly (BHA) (via drill pipe joints of drillstring 18) including one or more tools operated by the circulation of drilling fluid therethrough. When it is desired to retrieve protective sleeve 340 or install seal assembly 360 in the housing 302 of RCD 300, an obturating member or ball 570 may be released from the drilling vessel 12 into the drillstring 18 from which running tool 550 is suspended. The ball 570 is circulated into and through passage 554 of mandrel 552 until it lands against the seat 560 formed therein. Upon landing against seat 560 of mandrel 552, ball 570 seals passage 554 such that fluid circulated into passage 554 of mandrel 552 from drilling vessel 12 is forced into lower chamber 174 via ports 512 formed in mandrel 552. Thus, once ball 570 has landed against seat 560 of mandrel 552, piston body 162' may be actuated into the upper position by pressurizing passage 554 of mandrel 552, thereby permitting running tool 550 to retrieve protective sleeve 340 or install seal assembly 360 in the housing 302 of RCD 300.

[0058] While disclosed embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.