SIDE SADDLE RIG DESIGN WITH INTEGRATED MPD

Abstract

A drilling rig includes an integrated MPD system. The drilling rig includes a drill rig floor and a substructure. The drilling rig includes a managed pressure drilling (MPD) manifold positioned on the drill rig floor or coupled to the substructure. The drilling rig includes a rotating control device (RCD) coupled to a blowout preventer (BOP), the BOP coupled to a wellbore. The drilling rig includes a flowline coupled to the RCD. The drilling rig includes an MPD line coupled to the BOP, the MPD line fluidly coupled between the annulus of the wellbore and the MPD manifold. The drilling rig includes an MPD outlet line, the MPD outlet line fluidly coupled between the MPD manifold and the flowline.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a nonprovisional application which claims priority from U.S. provisional application No. 63/161,671, filed Mar. 16, 2021, which is incorporated by reference herein in its entirety.

TECHNICAL FIELD/FIELD OF THE DISCLOSURE

The present disclosure relates to the drilling of wells, and specifically to a drilling rig system for use in a wellsite.

BACKGROUND OF THE DISCLOSURE

Drilling rigs may be configured to be traveled from location to location to drill multiple wells within the same area known as a wellsite. In certain situations, it may be desirable to travel across an already drilled well for which there is a well-head in place. Further, mast placement on land-drilling rigs may have an effect on drilling activity. For example, depending on mast placement on the drilling rig, an existing well-head may interfere with the location of land-situated equipment such as, for instance, existing wellheads, and may also interfere with raising and lowering of equipment needed for operations. Managed pressure drilling involves the regulation of the annulus pressure of a wellbore being drilled to reduce unwanted flow of fluid into and out of the wellbore from the formation.

SUMMARY

The present disclosure provides for a drilling rig. The drilling rig may include a drill rig floor and a substructure. The drilling rig may include a managed pressure drilling (MPD) manifold positioned on the drill rig floor or coupled to the substructure. The drilling rig may include a rotating control device (RCD) coupled to a blowout preventer (BOP), the BOP coupled to a wellbore. The drilling rig may include a flowline coupled to the RCD. The drilling rig may include an MPD line coupled to the BOP, the MPD line fluidly coupled between the annulus of the wellbore and the MPD manifold. The drilling rig may include an MPD outlet line, the MPD outlet line fluidly coupled between the MPD manifold and the flowline.

The present disclosure also provides for a method. The method may include positioning a drilling rig in a wellsite at a first location aligned with a first wellbore. The drilling rig may include a drill rig floor and a substructure. The drilling rig may include a managed pressure drilling (MPD) manifold positioned on the drill rig floor or coupled to the substructure. The drilling rig may include a rotating control device (RCD) coupled to a blowout preventer (BOP), the BOP coupled to a wellbore. The drilling rig may include a flowline coupled to the RCD. The drilling rig may include an MPD line coupled to the BOP, the MPD line fluidly coupled between the annulus of the wellbore and the MPD manifold. The drilling rig may include an MPD outlet line, the MPD outlet line fluidly coupled between the MPD manifold and the flowline. The method may include disconnecting the BOP from the first wellbore; traveling the drilling rig to a second location in the wellsite aligned with a second wellbore; and coupling the BOP to the second wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 depicts a side elevation view of a drilling rig consistent with at least one embodiment of the present disclosure.

FIG. 2 depicts a side elevation view of the drilling rig of FIG. 1 from the other side of the drilling rig.

FIG. 3 depicts a partial side elevation view of the drilling rig of FIG. 1.

FIG. 4 depicts a top view of the drilling rig of FIG. 1.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.

FIGS. 1-4 depict drilling rig 10 consistent with at least one embodiment of the present disclosure. Drilling rig 10 may include drill rig floor 20, right substructure 30, and left substructure 40. Right and left substructures 30, 40 may support drill rig floor 20. Mast 50 may be mechanically coupled to one or both of right and left substructures 30, 40 or drill rig floor 20. As would be understood by one having ordinary skill in the art with the benefit of this disclosure, the terms “right” and “left” as used herein are used only to refer to each separate substructure to simplify discussion and are not intended to limit this disclosure in any way. In some embodiments, drill rig floor 20 may include V-door 23, defining a V-door side of drill rig floor 20 and V-door side 22 of drilling rig 10. In some embodiments, drill rig 10 may be a side-saddle drilling rig such that V-door 23 and V-door side 22 may be located over right substructure 30. V-door side 52 of mast 50 may correspondingly face right substructure 30. By facing V-door side 22 of drilling rig 10 toward one of the substructures 30, 40, equipment and structures that pass through the V-door 23 or to drill rig floor 20 from V-door side 22 of drilling rig 10 may, for example, be less likely to interfere with additional wells in the well field. In other embodiments, V-door side 22 and mast V-door side may face left substructure 40. In some embodiments, as depicted in FIG. 1, drilling rig 10 may be centered over wellbore 12.

In some embodiments, drilling rig 10 may include integrated managed pressure drilling (MPD) system 100. Integrated MPD system 100 may be used, for example and without limitation, to allow wellbore 12 to be drilled using managed pressure techniques such that integrated MPD system 100 controls annulus pressure of wellbore 12. In some embodiments, integrated MPD system 100 may be used to maintain the pressure within wellbore 12 during make up or break-out operations when employed with, for example and without limitation, a check valve at a drill bit of a drill string used with drilling rig 10. Components of integrated MPD system 100 may be coupled to or positioned on drilling rig 10 such that integrated MPD system 100 may travel with drilling rig 10 during a travel operation such as a skidding operation or a walking operation to move drilling rig 10 from a first location in a wellsite aligned with a first wellbore to a second location in a wellsite aligned with a second wellbore or during a transport operation.

With reference to FIG. 1, in some embodiments, integrated MPD system 100 may include rotating control device (RCD) 101. RCD 101 may be operatively coupled to blowout preventer (BOP) 103. BOP 103 may be mechanically and fluidly coupled to wellbore 12. RCD 101 may operate to allow a drill string to pass through BOP 103 while maintaining a sealed fluid connection with the annulus of wellbore 12 and a drill string positioned within wellbore 12. RCD 101 may include output port 105 fluidly coupled to flowline 107. Flowline 107 may be used to return drilling fluid within the annulus of wellbore 12 to mud handling equipment when wellbore 12 is drilled outside of a managed pressure drilling operation. In some embodiments, flowline 107 may be coupled to RCD 101 via flowline valve 109. Flowline valve 109 may be closed during MPD operations and opened during non-MPD operations. Flowline valve 109 may, in some embodiments, be a gate valve, ball valve, or orbit valve.

In some embodiments, integrated MPD system 100 may include MPD line 111. MPD line 111 is fluidly coupled to the annulus of wellbore 12 through MPD port 113 formed in RCD 101 or other component of BOP 103. In some embodiments, MPD port 113 may be formed in spool 115 of BOP 103. MPD port 113 may allow for fluid returning through the annulus of wellbore 12 to be diverted from flowline 107 to integrated MPD system 100 via MPD line 111 as discussed below when flowline valve 109 is closed and subsequent valve 110 is opened. Subsequent valve 110 may be, in some embodiments, a gate valve, ball valve, or orbit valve.

MPD line 111 may be coupled to subsequent valve 110 to provide a fluid conduit for fluid to pass from wellbore 12 to MPD manifold 117. MPD manifold 117 may be a choke manifold used to manage the pressure of the annulus of wellbore 12 through the use of one or more valves 119 as shown in FIGS. 3, 4. In some embodiments, MPD manifold 117 may be positioned on drill rig floor 20 such that MPD manifold 117 travels with drilling rig 10.

In some embodiments, as shown in FIG. 3, MPD manifold 117 may fluidly couple to

Coriolis meter 123. Coriolis meter 123 may be used to measure the mass flow rate and density of the drilling fluid flowing through integrated MPD system 100 to, for example and without limitation, identify kicks and to provide feedback for the control of integrated MPD system 100. In some embodiments, one or more valves may be positioned to allow fluid flowing through MPD manifold 117 to bypass Coriolis meter 123.

In some embodiments, as shown in FIG. 1, MPD manifold 117 may be fluidly coupled to mud gas separator 121. Mud gas separator 121 may be mechanically coupled to drilling rig 10 such that mud gas separator 121 travels with drilling rig 10. Mud gas separator 121 may be used to separate drilling fluid from gases entrained with the drilling fluid returning from wellbore 12. In some embodiments, one or more valves may be positioned to allow fluid flowing through MPD manifold 117 to bypass mud gas separator 121.

Once the drilling fluid flows through MPD manifold 117 and, if desired, Coriolis meter 123 or mud gas separator 121, the drilling fluid may flow through MPD outlet line 125, which may be fluidly coupled to flowline 107 to allow the drilling fluid to pass to other mud handling equipment which may be positioned on drilling rig 10 or at a location proximate drilling rig 10.

In some embodiments, the components of integrated MPD system 100 may remain coupled to drilling rig 10 throughout any traveling operations such as skidding or walking operations and, in some embodiments, transport operations. In such embodiments, the fluid connections of integrated MPD system 100 including, for example and without limitation, the connection of MPD line 111 to BOP 103 or RCD 101, the connection of MPD line 111 to MPD manifold 117, the connection of MPD manifold 117 to Coriolis meter 123, the connection of MPD manifold 117 to mud gas separator 121, the connection of MPD manifold 117 and Coriolis meter 123 to MPD outlet line 125, and the fluid connections between flowline 107 and MPD outlet line 125 and RCD 101, may be maintained throughout such traveling or transport operations. In such embodiments, such connections need not be rigged down and up for each travel and transport operation, reducing the time required to prepare for transport of drilling rig 10 and reducing delays in beginning operations after the move.

In some embodiments, integrated MPD system 100 may include MPD controller 127. MPD controller 127 may be positioned on drill rig floor 20 and may be used to control operation of integrated MPD system 100. MPD controller 127 may, in some embodiments, control the pressure of the annulus of wellbore 12 based at least in part on measurements of Coriolis meter 123 and other sensors by manipulating one or more valves 119 of integrated MPD system 100.

The foregoing outlines features of several embodiments so that a person of ordinary skill in the art may better understand the aspects of the present disclosure. Such features may be replaced by any one of numerous equivalent alternatives, only some of which are disclosed herein. One of ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. One of ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure.

Claims

1. A drilling rig comprising:

a drill rig floor and a substructure;

a managed pressure drilling (MPD) manifold positioned on the drill rig floor or coupled to the substructure;

a rotating control device (RCD) coupled to a blowout preventer (BOP), the BOP coupled to a wellbore;

a flowline coupled to the RCD;

an MPD line coupled to the BOP, the MPD line fluidly coupled between the annulus of the wellbore and the MPD manifold; and

an MPD outlet line, the MPD outlet line fluidly coupled between the MPD manifold and the flowline.

2. The drilling rig of claim 1, wherein the MPD manifold further comprises one or more valves adapted to manage the pressure of the annulus of the wellbore.

3. The drilling rig of claim 1, wherein the MPD manifold further comprises a Coriolis meter.

4. The drilling rig of claim 1, further comprising a mud gas separator, the mud gas separator mechanically coupled to the drilling rig.

5. The drilling rig of claim 3, wherein the MPD manifold is fluidly coupled to the mud gas separator.

6. The drilling rig of claim 1, further comprising a flowline valve positioned between the RCD and the flowline.

7. The drilling rig of claim 6, wherein the flowline valve is a gate valve, ball valve, or orbit valve.

8. The drilling rig of claim 1, further comprising an MPD controller, the MPD controller positioned on the drill rig floor.

9. A method comprising:

positioning a drilling rig in a wellsite at a first location aligned with a first wellbore, the drilling rig including: a drill rig floor and a substructure; a managed pressure drilling (MPD) manifold positioned on the drill rig floor or coupled to the substructure; a rotating control device (RCD) coupled to a blowout preventer (BOP), the BOP coupled to the first wellbore; a flowline coupled to the RCD; an MPD line coupled to the BOP, the MPD line fluidly coupled between the annulus of the wellbore and the MPD manifold; and an MPD outlet line, the MPD outlet line fluidly coupled between the MPD manifold and the flowline;

disconnecting the BOP from the first wellbore;

traveling the drilling rig to a second location in the wellsite aligned with a second wellbore; and

coupling the BOP to the second wellbore.