WO2016054610A1

WO2016054610A1 - Drilling rig system with movable wellcenter assembly

Info

Publication number: WO2016054610A1
Application number: PCT/US2015/053888
Authority: WO
Inventors: Frank B. Springett; Frode JENSEN
Original assignee: National Oilwell Varco, L.P.
Priority date: 2014-10-03
Filing date: 2015-10-03
Publication date: 2016-04-07

Abstract

A drilling system includes a plurality of laterally adjacent drilling packages (112, 114) and a movable wellcenter assembly that includes a riser and a riser tensioner assembly coupled to a first end of the riser, wherein a second end of the riser is adapted to be operatively coupled to a wellhead. The drilling system further includes wellcenter moving means that is adapted to laterally move the movable wellcenter assembly from a position proximate a first one of the plurality of laterally adjacent drilling packages (112, 114) to a position proximate a second one of the plurality of laterally adjacent drilling packages (112, 114) while the second end of the riser is operatively coupled to the wellhead.

Description

DRILLING RIG SYSTEM WITH MOVABLE WELLCENTER ASSEMBLY

BACKGROUND

1. FIELD OF THE DISCLOSURE

The present subject matter is generally directed to systems and methods for drilling wellbores into the earth, and in particular, to systems and methods for using a movable wellcenter assembly to perform drilling, completion, and/or workover operations on a single wellbore with a plurality of drilling packages.

2. DESCRIPTION OF THE RELATED ART

Performing drilling operations in deep water locations quite commonly comes with significantly higher drilling costs and greater engineering and logistical challenges than what might otherwise be associated with operations that are performed in shallower near-coastal water depths. For example, the cost of leasing highly engineered and complex offshore drilling units that are capable of operating in deeper offshore waters (e.g., up to 10,000 feet (3,000 meters) and the like) can often be in the range of hundreds of thousands of dollars per day or more. When coupled with the unique environmental conditions and other engineering challenges associated with offshore drilling operations in general, reducing drilling times by a few days over even hours can ultimately have a significant economic impact on the overall costs associated with drilling a completing an offshore well.

Drilling offshore oil and gas wells typically includes three operational phases. In the first phase, sometime referred to as the top hole drilling phase, the structural/anchoring portions of the wellbore are set in the shallow formation strata immediately below the seabed, or sea floor. Typically, the upper portion of the wellbore is initially formed by setting a section of conductor casing down to a depth of approximately 300 to 400 feet (90-120 meters) below the seabed. The conductor casing, which often has a diameter of approximately 30 inches (660 mm), may be jetted in place, or an oversized hole may be drilled, after which the conductor casing is set in the drilled hole and cemented in place. Thereafter, structural casing is jetted, or drilled and cemented, in place inside of the conductor casing, extending down to a depth below the seabed of approximately 2000 to 4000 feet (600-1200 meters), depending on the specific application and formation. The structural casing may include one or more casing strings, each having a decreased diameter relative to the previous string as the depth of the wellbore increases below the seabed. For example, when the conductor casing has a nominal diameter of 30 inches (660 mm), a first string of structural casing may have a diameter of approximately 24 inches (600 mm), and a second casing string below the first casing string may have a diameter of approximately 20 inch (440 mm).

The first structural casing string, that is, the first casing string inside of the conductor casing, will typically have a wellhead positioned at its uppermost end. The wellhead is used for supporting and sealing subsequently installed casing and production strings inside of the wellbore, and for mounting a blowout preventer (BOP) to control formation pressures during the subsequent drilling operations. Additionally, after drilling operations have been completed, the wellhead is used for mounting a Christmas tree that will control future production operations. Accordingly, the top hole drilling operations are generally performed as "riserless" operations, that is, before a marine riser has been used lower and set the BOP in place on the wellhead.

The second phase of offshore drilling operations, often referred to as the primary or bottomhole drilling phase, is performed after the BOP is installed. Once the top hole section is completed with a conductor and a wellhead, the BOP is conveyed from the offshore drilling unit down through the water on the marine riser, and is landed on and latched to the wellhead. Marine risers, sometimes referred to herein simply as "risers," typically include a large diameter tubular string, such as a 20-22 inch (500-550 mm) diameter pipe, that acts as a conduit from the wellbore to the surface of the water at or near where the offshore drilling unit is positioned. Once the BOP has been set on and latched to the wellhead, the bottomhole drilling phase is performed in a controlled manner through the riser. For example, a drill string including a bottomhole assembly ("BHA") is typically made-up on the offshore drilling unit and run into the wellbore through the riser, so that the drilled wellbore can be further into the earth. During such drilling activities, the riser is also used to circulate the spent drilling fluid (e.g., drilling mud) back out of the wellbore, along with drilled solids material, and up to the offshore drilling unit for treatment and separation. The riser often includes one or more auxiliary conduits, such as high pressure choke and kill lines for circulating fluids to the BOP, as well as power and control lines for the BOP. Once a section of the wellbore has been drilled (or a tool failure occurs), the drill string is pulled out of the wellbore and through the riser to the offshore drilling unit. Other rig operations that are generally performed through the riser include, for example, running casing, cementing casing, well logging and/or testing, well stimulations, formation fracturing, and the like, as are well known by those skilled in the art.

Once the wellbore has been drilled and the bottomhole portion has been completed to the desired depth, a third phase of post-drilling operations is performed. During the third phase of operations, the BOP is unlatched from the wellhead and retrieved to the surface by the riser. In some cases, the well may be capped for later completion activities. In other cases, a downhole production assembly and a tubing string may be installed in the wellbore, and a Christmas tree installed at the wellhead.

Historically, offshore wells have been drilled and/or completed along a single load path (e.g., derrick, rig, drilling assembly, etc.), which essentially means that substantially all of the operations on a given wellbore are performed by a single drilling assembly. However, in order to address the high operating costs that are often associated with deep water offshore drilling, various approaches have been developed in an effort to try and improve drilling efficiency by allowing some drilling operations to be performed simultaneously, i.e., in parallel, in an effort to reduce the overall amount of time required to drill and complete a wellbore.

For example, some offshore drilling units may utilize multi-activity drilling systems that include dual drilling assemblies (e.g., separate load paths and/or derricks) for performing so-called "dual activity" drilling operations. With a typical offshore multi-activity drilling system, a secondary drilling station is used to perform the top hole drilling operations, i.e., jetting/drilling and setting the near-surface wellbore casing sections and wellhead as described above, while a primary drilling station is concurrently used to run the marine riser and blowout preventer (BOP) down to the wellhead. However, once the BOP has been landed on the wellhead and latched in place using the primary drilling station, any true dual activity operations on the wellbore are effectively ended, as the primary or bottomhole drilling phase is thereafter performed using a single load path - i.e., through the primary drilling station. As such, of all the remaining well construction work - e.g., drilling, casing, cementing, etc. - is performed through the riser and BOP using the primary drilling center, whereas the secondary drilling station is relegated to performing only ancillary or auxiliary operations, such as making up drill-pipe and/or casing stands and the like.

It is generally well understood that the greatest amount of rig time spent during the overall drilling operations occurs during the bottomhole drilling phase of operations, when trips into and out of the wellbore require more joints of pipe and take increasingly longer periods of time as the depth of the wellbore is increased. Therefore, while the presently available multi-activity drilling systems can provide some degree of dual activity efficiencies during the top hole or early phase of drilling operations, the benefit of the secondary (auxiliary) drilling station is diminished once the riser is in place and the bottomhole drilling activities are being performed through the BOP.

In view of the foregoing, there is a need to develop new systems that would permit true dual activity drilling operations to be performed throughout substantially all phases of the offshore wellbore drilling process. The following disclosure is directed to various drilling systems, apparatuses, and methods that are intended address, or at least mitigate, some of the above-described shortcomings of existing multi -activity drilling systems.

SUMMARY OF THE DISCLOSURE

The following presents a simplified summary of the present disclosure in order to provide a basic understanding of some aspects disclosed herein. This summary is not an exhaustive overview of the disclosure, nor is it intended to identify key or critical elements of the subject matter disclosed here. Its sole purpose is to present some concepts in a simplified form as a prelude to the more detailed description that is discussed later.

Generally, the subject matter disclosed herein is directed to systems and methods for using a movable wellcenter assembly to perform drilling, completion, and/or workover operations on a single wellbore with a plurality of drilling packages. One illustrative embodiment of the present disclosure is a drilling system that includes, among other things, a plurality of laterally adjacent drilling packages and a movable wellcenter assembly that includes a riser and a riser tensioner assembly coupled to a first end of the riser, wherein a second end of the riser is adapted to be operatively coupled to a wellhead. The disclosed drilling system further includes wellcenter moving means that is adapted to laterally move the movable wellcenter assembly from a position proximate a first one of the plurality of laterally adjacent drilling packages to a position proximate a second one of the plurality of laterally adjacent drilling packages while the second end of the riser is operatively coupled to the wellhead.

In another exemplary embodiment, a method for drilling a wellbore is disclosed that includes positioning a movable wellcenter assembly in a first position proximate a first drilling package of an offshore drilling unit, and while the movable wellcenter assembly is positioned in the first position, performing a first drilling operation through the movable wellcenter assembly with the first drilling package. The exemplary disclosed method also includes laterally moving the movable wellcenter assembly from the first position to a second position proximate a second drilling package of the offshore drilling unit after performing the drilling operation, and while the movable wellcenter assembly is positioned in the second position, performing a second drilling operation through the movable wellcenter assembly with the second drilling package.

Yet another illustrative method disclosed herein includes, among other things, operatively coupling wellcenter moving means to a drill floor of an offshore drilling unit, operatively coupling a movable wellcenter assembly to the wellcenter moving means, and laterally moving the movable wellcenter assembly with the wellcenter moving means between positions proximate laterally adjacent drilling packages.

BRIEF DESCRIPTION OF THE DRAWINGS

The disclosure may be understood by reference to the following description taken in conjunction with the accompanying drawings, in which like reference numerals identify like elements, and in which: Figure 1 is a plan view of an exemplary mobile offshore drilling unit that utilizes an illustrative movable wellcenter assembly in accordance with an embodiment of the present disclosure;

Figure 2 is a side sectional elevation view of the exemplary mobile offshore drilling unit shown in Fig. 1 when viewed along the section line "2-2";

Figure 3 is an end sectional elevation view of the exemplary mobile offshore drilling unit shown in Fig. 1 when viewed along the section line "3-3";

Figure 4 is a close-up elevation view of an illustrative derrick that includes a plurality of drilling packages for performing drilling operations through an exemplary movable wellcenter assembly in accordance with one illustrative embodiment disclosed herein;

Figure 5 is a close-up elevation view of the exemplary movable wellcenter assembly depicted in Fig. 4;

Figure 6 is a close-up plan section view of the illustrative derrick and movable wellcenter assembly shown in Fig. 4 when viewed along the section line "6-6" of Fig. 4;

Figures 7A-7L schematically illustrate an exemplary sequence of various dual activity drilling operations that may be performed using the movable wellcenter assembly and plurality of drilling packages disclosed herein; and

Figures 8A-8C are close-up elevation views of another illustrative embodiment of a movable wellcenter assembly in accordance with further exemplary embodiments disclosed herein.

While the subject matter disclosed herein is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION

Various illustrative embodiments of the present subject matter are described below. In the interest of clarity, not all features of an actual implementation are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business- related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

The present subject matter will now be described with reference to the attached figures. Various systems, structures and devices are schematically depicted in the drawings for purposes of explanation only and so as to not obscure the present disclosure with details that are well known to those skilled in the art. Nevertheless, the attached drawings are included to describe and explain illustrative examples of the present disclosure. The words and phrases used herein should be understood and interpreted to have a meaning consistent with the understanding of those words and phrases by those skilled in the relevant art. No special definition of a term or phrase, i.e., a definition that is different from the ordinary and customary meaning as understood by those skilled in the art, is intended to be implied by consistent usage of the term or phrase herein. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than that understood by skilled artisans, such a special definition will be expressly set forth in the specification in a definitional manner that directly and unequivocally provides the special definition for the term or phrase.

Generally, the subject matter disclosed herein is directed to systems and methods for using a movable wellcenter assembly to perform drilling, completion, and/or workover operations on a single wellbore with a plurality of drilling packages. As will be readily apparent to those skilled in the art upon a complete reading of the present disclosure, the various concepts and systems described herein may be utilized for substantially any type of offshore drilling application using substantially any type of offshore drilling unit known in the art, and is not necessarily limited only to deep water drilling operations and/or the type of mobile offshore drilling units described herein that may be specifically adapted for deep water operations. Accordingly, it should be understood that the subject matter of the present disclosure may be readily adapted for use by offshore drilling units that are typically used to perform such drilling operations in near -coastal and/or continental shelf shallow-to-medium water depths, e.g., less than 2,000 feet (600 meters). With reference to the attached figures, various illustrative embodiments of the systems and methods disclosed herein will now be described in more detail.

Figures 1-3 depict various views of an exemplary mobile offshore drilling unit (MODU) 100 that is positioned on and above a body of water 101. In particular, Fig. 1 is a pian view of the mobile offshore drilling unit

100 wherein the derrick structure 110 and ancillary equipment support structure 133 (see, Fig. 3) have been removed for clarity. Additionally, Fig. 2 is a side sectional elevation view of the mobile offshore drilling unit 100 when viewed along the section line "2-2" shown in Fig. 1, and Fig. 3 is an end sectional elevation view when viewed along the section line "3-3" shown in Fig. 1 The mobile offshore drilling unit 100 may be any type of suitable floating mobile drilling unit known in the art, such as a drillship or semi-submersible vessel and the like.

For example, the mobile offshore drilling unit 100 is depicted in Figs. 1-3 as a drillship, and will henceforth be referred to as a drillship 100 for convenience and simplicity of description. In certain exemplary embodiments, the drillship 100 may include a plurality of bow and stern thrusters (not shown) that are adapted to maintain the drillship 100 at a required drilling position above the body of water 101 using dynamic positioning techniques known to those skilled in the art, and which will not be further discussed herein.

The drillship 100 of Figs. 1-3 includes a hull 102 that is constructed with a moon pool 108 positioned roughly amidships between the bow 106 and the stern 104. As shown in Figs. 2 and 3, a derrick structure 110 is mounted above the drill floor 125 of the drillship 100 and includes a plurality of laterally adjacent drilling packages 112, 114 that may be used for performing various drilling and/or completion operations on one or more subsea wells (not shown). The derrick structure 110 may be positioned above the moon pool 108 for access by the drilling packages 112, 114 to the body of water 101 and the subsea wells positioned on and in the seabed therebelow (see, e.g., Figs. 7A-7L, described below). Additionally, each drilling package 112, 114 has a respective operational centerline 112c, 114c, and may include, among other things, a hoisting system 116 that is driven by a hoist or drawworks 117 (see, Fig. 6), a top drive assembly 118, and other drilling rig equipment that is typically associated with drilling activities. For example, ancillary drilling activity support equipment, such as a tubular handling system 132 (see, Fig. 3) and the like, may be disposed adjacent each of the drilling packages 112, 114. Furthermore, in at least some embodiments, at least some of the ancillary drilling activity support equipment, e.g., the tubular handling system 132, may be positioned in and/or supported by an ancillary equipment support structure 133, as is shown in Fig. 3. While two laterally adjacent drilling packages 112, 114 are depicted in the illustrative embodiment shown in Figs. 2, the plurality of drilling packages included on the derrick 110 may include more than two laterally adjacent drilling packages, e.g., three, four, or even more laterally adjacent drilling packages, as will be readily appreciated by those of ordinary skill after a complete reading of the present disclosure, and in particular the descriptions set forth below with respect to the operational sequences illustrated Figs. 7A-7L. Similarly, while only a single derrick 110 is shown in Fig. 2, it should also be understood that each individual drilling package 112, 114 may have its own separate derrick structure 110, e.g., two derricks 110. Therefore, it should be understood that any reference in the descriptions set forth herein to the plurality of laterally adjacent drilling packages 112, 114 encompasses a reference to two drilling packages as well as a reference to three or more drilling packages. Furthermore, any references herein to the derrick 110 encompasses a reference to a single derrick structure that includes each one of the plurality of laterally adjacent drilling packages as well a reference to separate individual derrick structures for each individual drilling package.

The drillship 100 may also include one or more cranes 124 (five shown in the embodiment depicted in Fig. 1) for loading or unloading equipment and/or materials, or handling equipment and/or materials during drilling operations. Crane lift capacities may range from 25-200 tons (25-200 mT) with a working radius of 25-150 feet (8-

45 meters), although it should be understood that other crane sizes/capacities may also be used, depending on the various design and operational parameters of the drillship 100. As shown in Figs. 1 and 2, a plurality of pipe racks 126 may be appropriately positioned on the drillship 100, e.g., aft of the derrick 110, for storing the various tubular products that may be used during drilling operations, such drill pipe, wellbore casing, and the like. In some embodiments, the drillship 100 may also include an appropriately located marine riser storage bay 128, e.g., below decks and fore of the moon pool 108, where a plurality of riser sections 122x may be stored during transit of the drillship 100 to an offshore drilling site and/or when not in use for primary drilling operations. Furthermore, a riser handling system 130 may be used to retrieve the risers sections 122x from the storage bay 128 to the drill floor 125 for assembly and attachment to a blowout preventer (BOP) in preparation for lowering the BOP to a subsea wellhead, as previously described. In certain embodiments, the drillship 100 may further include one or more remote operations control center modules 140 positioned on the drill floor 125, from which operators may monitor and control the various drilling and completion activities being performed by the drilling packages 112, 114.

Returning now to Figs. 2 and 3, a movable wellcenter assembly 120 may be positioned below the drill floor 125 and extending partially down into the moon pool 108. In certain embodiments, the movable wellcenter assembly 120 may include, among other things, a rotary table 119, a riser diverter 127 that is positioned below rotary table 119, an assembled riser 122, and a riser tensioner system 121 that is coupled to an upper end of the riser 122. In certain embodiments, a lower end of the riser 122 is coupled to a BOP (not shown), which is in turn latched or coupled to a subsea wellhead (not shown). The riser diverter 127 is adapted to close the vertical flow path of any materials returning up the riser 122 from the subsea wellbore (not shown; see, e.g., Figs. 7B-7L), such as drilling mud and cuttings during drilling operations, and direct the flow of materials away from the drill floor 125 and the drilling packages 112, 114 and derrick 110. The riser tensioner system 121 is adapted to provide a substantially constant tension, i.e., upward, force on the riser 122 after the BOP has been latched to the subsea wellhead, irrespective of the movement of the floating drillship 100 due to wind, wave, and/or swell actions on the drillship 100. As shown in Figs. 2 and 3, the movable wellcenter assembly 120 has a nominal operational centerline 122c running from the rotary table 119, through the riser 122, and down to the BOP, and substantially defines the conduit through which drilling operations may be performed by either of the drilling package 112, 114 on the subsea wellbore.

In at least some exemplary embodiments of the present disclosure, the movable wellcenter assembly 120 is adapted to be moved laterally, e.g., back and forth, between each of the plurality of laterally adjacent drilling packages 112, 114. In this way, various different drilling operations may be independently performed by each of the drilling packages 112, 114 through the movable wellcenter assembly 120, as will be discussed in further detail with respect to Figs. 7A-7L below. To that end, the drillship 100 may include wellcenter moving means 123 that may be operatively couple to the drill floor 125 and is adapted to laterally move the movable wellcenter assembly 120 along the drill floor 125 between positions proximate each of the plurality of laterally adjacent drilling packages 112, 114. In certain embodiments, the wellcenter moving means 123 may be positioned below the drill floor 125 and operatively coupled to the movable wellcenter assembly 120 in such a manner as to affect the lateral movement of the movable wellcenter assembly 120 between the drilling packages 112, 114 after completing each of the various drilling operations, as will be briefly discussed with respect to Figs. 4-5 below.

In at least one embodiment, the wellcenter moving means 123 may include, for example, a rail and trolley system (not shown), wherein the movable wellcenter assembly 120 is coupled to a plurality of wheeled trolleys that are adapted to be moved along spaced apart rails. Furthermore, the wellcenter moving means 123 may be driven by any one of several known mechanical systems, examples of which may include hydraulic systems, screw systems, rack and pinion systems, chain drive systems, jacking cylinders, and the like.

Figures 4-6 depict various close-up views of the derrick 110, drilling packages 112, 114, and movable wellcenter assembly 120 described above and generally shown in Figs. 1-3. More specifically, Fig. 4 is a close-up elevation view of an exemplary derrick 110 that includes a plurality of drilling packages 112, 114 and a movable wellcenter assembly 120 that is positioned substantially midway between the drilling packages 112, 114, and Fig. 5 is a close-up elevation view of the exemplary movable wellcenter assembly 120 shown in Fig. 4 after the assembly 120 has been moved (indicated by arrow 120m) toward the drilling , and Fig. 6 is a close-up plan section view of the illustrative derrick 110 and movable wellcenter assembly 120 when viewed along the section line "6-6" of

Fig. 4.

The following description provides additional details which illustrate the movement of the movable wellcenter assembly 120 in the exemplary embodiment depicted in Figs. 4-6, that is, wherein the derrick 110 includes first and second drilling packages 112, 114 and the movable wellcenter assembly 120 includes a rotary table 119, a riser diverter 127, a riser 122, and a riser tensioner system 121. For example, when a first drilling operation is being performed by the first drilling package 112 on a given subsea wellbore (not shown; see, e.g., Figs. 7B-7L), the movable wellcenter assembly 120 may be moved (indicated by arrows 120m) to a position proximate the first drilling package 112 using the wellcenter moving means 123 such that the operational centerline 122c of the movable wellcenter assembly 120 is substantially aligned/coincident with the operational centerline 112c of the first drilling package 112c. As used in the present description and the appended claims, the term

"substantially aligned/coincident with" means that the respective operational centerlines are aligned within normal drilling rig tolerances such that drilling operations may be performed substantially without undue interference and/or interaction with attached and/or surrounding equipment and/or structures. In this manner, the first drilling operation (e.g., drilling a bottomhole section) may thereby be performed through the movable wellcenter assembly 120 by the first drilling package 112. Simultaneously, the various set-up activities that are required to prepare the second drilling package 114 for performing the next drilling operation (e.g., running casing into the bottomhole section drilled by the first drilling package 112) may commence and continue while the first drilling package 112 is performing the first drilling operation on the subsea wellbore through the movable wellcenter assembly 120.

Once the first drilling operation has been completed by the first drilling package 112, any tools that may have been used during the first drilling operation (e.g., drill string and bottomhole assembly, running tools, etc.) may then be retrieved from the movable wellcenter assembly 120 and/or the wellbore so that the moveable wellcenter assembly 120 can be laterally moved along the drill floor 125 from a position proximate the first drilling package 112 and over to a position proximate the second drilling package 114. Once the tools have been removed from the movable wellcenter assembly 120, the wellcenter moving means 123 may then be actuated so as to move (indicated by arrows 120m) the movable wellcenter assembly 120 until the operational centerline 122c of the movable wellcenter assembly 120 is substantially aligned/coincident with the operational centerline 114c of the second drilling package 114, which by this time has been fully set up and prepared to perform the next drilling operation. Thereafter, the next drilling operation (e.g., running casing into the previously drilled bottomhole section) may be performed by the second drilling package 114 through the movable wellcenter assembly 120.

As may be appreciated by those of ordinary skill after a complete reading of the present application, use of the movable wellcenter assembly 120 in conjunction with the plurality of laterally adjacent drilling packages 112, 114 disclosed herein enables each of the drilling packages 112, 114 to be able to perform primary bottomhole drilling operations on a subsea wellbore (not shown; see, e.g., Figs. 7B-7L), that is, through the riser 122 after the BOP has been latched to a subsea wellhead, thereby resulting in a two load path drilling system - i.e., true dual activity operations. The prior art dual activity drilling systems, on the other hand, only provide dual activity operations up until the riser and BOP have been latched to the subsea wellhead. Furthermore, as indicated above, the set-up activities for preparing the second drilling package 114 for the second drilling operation can be performed "off-line" while the first drilling package 112 is performing the first drilling operation "on-line." In setting up the second drilling package 114 "off-line," a significant time savings, which can be as great as tens of hours or even multiple days, can potentially be realized for each drilling operation over the prior art dual activity drilling systems, in which all set-up activities after the BOP and riser system have been latched to the wellhead are performed "on-line."

As noted previously, Fig. 6 is a close-up plan section view of the derrick 110 and movable wellcenter assembly 120 when viewed along the section line "6-6" of Fig. 4. As shown in Fig. 6, the moveable wellcenter assembly 120 is being moved (indicated by arrow 120m) toward the second drilling package 114, wherein the movable wellcenter assembly 120 will eventually be positioned so that its operational centerline 122c is substantially aligned/coincident with the operational centerline 114c of the second drilling package 114. In certain exemplary embodiments, in order to facilitate the lateral movement of the movable wellcenter assembly 120 between the first and second drilling packages 112 and 114, the drill floor 125 may include removable floor panel sections 125r that are positioned along the path that is traveled by the movable wellcenter assembly 120. Once the movable wellcenter assembly 120 has been positioned proximate either the first drilling package 112 or the second drilling package 114, the rotary table 119 may then take up the position of one removable floor panel section 125r and all other removable floor panel sections 125r may be replaced as required.

Figures 7A-7L schematically illustrate an exemplary sequence of various dual activity drilling operations that may be performed using the movable wellcenter assembly 120 and the first and second drilling packages 112, 114 described above. In particular, Figs. 7A-7D depict various operations that are performed by both the first and second drilling packages 112, 114 during the first phase of wellbore operations when the top hole drilling operations are being performed. For example, as shown in Fig. 7A, a jetting operation, and/or a drilling and cementing operation, is being performed with the first drilling package 112. As noted previously, the jetting/drilling and cementing operation is performed so as to set the upper wellbore conductor casing and structural casing string(s), hereinafter collectively referred to generally as the conduit 150, in the formation 151 below the seabed or seafloor 10 If A jetting tool or drill string 154 is used to run the conduit 150 through the body of water 101 and down to sea floor lOlf. Generally, these initial operations of jetting and setting the conduit 150 are performed "riserless," that is, without a marine riser tying the operation back to the drillship 100, and the drilling fluid used for the operations is typically water or seawater, which returns the drill cuttings and/or jetted material of the formation 151 to the sea floor 101 f.

As the jetting operation is being performed and the conduit 150 is being set, the drill floor 125 at the second drilling package 114 is being set up and prepared to run and test the blowout preventer 156 (see, Fig. 7B) and riser 122, an activity that may require as long as 1-2 days to accomplish. As shown in Fig. 7A, a riser spider 129, which is adapted to support the partially completed riser 122 as additional riser sections are attached, is positioned above the drill floor 125 in preparation for running the BOP 156 and riser 122 down to the subsea wellhead, an operation which can sometimes take up to a week to complete.

Figure 7B schematically depicts a further sequence wherein the first drilling package 112 has finished setting the wellhead 152 proximate the sea floor 10 If, thus completing the top hole portion of the subsea wellbore 175. Additionally, the BOP 156 has been attached to the lower end of the riser 122 and a function test performed prior to using the second drilling package 114 to lower the BOP 156 and riser 122 through the moon pool 108 and down into the body of water 101. Next, as shown in Fig. 7C, the BOP 156 has been lowered down to the sea floor lOlf to a position proximate the wellhead 152, after which the rotary table 119 may be positioned below the drill floor 125 at the second drilling package 114, and the overall riser system has been set up by installing the riser diverter 127 and the tensioner system 121. Accordingly, the movable wellcenter assembly 120, which now includes the rotary table 119, the riser diverter 127, the riser 122, and the riser tensioner assembly 121, is then in position at the second drilling package 114. While these activities, i.e., assembling the movable wellcenter assembly 120, are being performed at the second drilling package 114, the drill floor 125 at the first drilling package 112 is being set up and prepared for drilling the first bottomhole section of the wellbore through the riser 122 and BOP 156.

Figure 7D shows a further step in the sequence of drilling activities, wherein the BOP 156 has been landed and latched in place on the subsea wellhead 152 by the second drilling package 114 and the riser tensioner system 210 has been actuated so that a substantially constant upward (tension) force is imposed on the riser 122 during the subsequent bottomhole drilling operations. During this activity, the operational centerline 122c of the movable wellcenter assembly 120 will typically be substantially aligned/coincident with the operational centerline 114c of the second drilling package 114, as shown in Fig. 7D. Additionally, set up activities may continue on a substantially simultaneous basis so as to prepare the drill floor 125 at the first drilling package 112 for the first bottomhole section drilling activities, e.g., by, among other things, attaching a bottomhole assembly 160 (drill bit, drilling motor, drill collars, stabilizers, etc.) to a drill string 158, etc.

Figures 7E-7L schematically depict various exemplary steps in the sequence of performing drilling operations on the subsea wellbore 175 that involve moving the movable wellcenter assembly 120 laterally, i.e., back-and- forth, between the first and second drilling packages 112 and 114. For example, Fig. 7E illustrates the movable wellcenter assembly 120 as it is being moved (indicated by arrow 120m) using the wellcenter moving means 123 from the second drilling package 114 over to the first drilling package 112 after the BOP 156 has been latched in place on the wellhead 152 and the riser tensioner assembly 121 actuated, as previously described with respect to Fig. 7D. As shown in Fig. 7F, the movable wellcenter assembly 120 has been moved (indicated by arrow

120m) into position below the drill floor 125 proximate the first drilling package 112 so that the operational centerline 122c of the movable wellcenter assembly 120 is substantially aligned/coincident with the operational centerline 112c of the first drilling package 112. In this position, the first drilling package 112 may then commence a drilling operation to drill the first bottomhole section of the subsea wellbore 175 by lowering the bottomhole assembly 160 down through the movable wellcenter assembly 120, BOP 156, and conduit 150. Additionally, offline activities may commence and continue substantially simultaneously to break down the riser-running set-up at the second drilling package 114, e.g., by removing the riser spider 129, etc., and to prepare the drill floor 125 at the second drilling package 114 for the next on-line drilling operation, as will be further described below.

Figure 7G schematically illustrates a subsequent operational step wherein the first bottomhole on-line drilling operation is being performed by the first drilling package 112 using the bottomhole assembly 160 and drill string 158 to extend the subsea wellbore 175 into the formation 151. Meanwhile, off-line set up activities continue on the drill floor 125 at the second drilling package 114 in preparation for the next on-line operation, e.g., running the casing 161 into the first bottomhole section that is currently being drilled by the bottomhole assembly 160 at the first drilling package 112.

Turning now to Fig. 7H, the first bottomhole drilling operation has been completed at the first drilling package 112 and the drill string 158 and bottomhole assembly 160 have been retrieved from the wellbore 175 through the BOP 156 and riser 122. Thereafter, the wellcenter moving means 123 is operated so as to laterally move (indicated by arrow 120m) the movable wellcenter assembly 120 along the drill floor 125 from its position proximate the first drilling package 112 over to a position proximate the second drilling package 114 such that the operational centerline 122c of the movable wellcenter assembly 120 may be substantially aligned/coincident with the operational centerline 114c of the second drilling package 114. As shown in Fig. 7H, the next on-line operation is then performed by the second drilling package 114, which is used to run the casing string 161 down through the movable wellcenter assembly 120 and BOP 156 and into the newly drilled bottomhole section of the subsea wellbore 175.

Additionally, while the movable wellcenter assembly 120 is being moved over to the second drilling package 114 and the second drilling package 114 is performing the on-line casing operation on the wellbore 175, off-line break-down and set-up activities may commence and continue at the first drilling package 112 in preparation for the next on-line drilling operation. For example, after the previously used drilling set-up (e.g., the drill string 158 and bottomhole assembly 160) has been broken down at the first drilling package 112, operations for setting up a cementing apparatus 162 may be started so that the cementing apparatus 162 is prepared and ready to perform an on-line cementing operation on the casing string 161 that is presently being run into the wellbore 175 by the second drilling package 114, thus more fully realizing the dual activity efficiencies associated with the drilling systems disclosed herein.

Figure 71 schematically depicts an exemplary next step in the dual activity operating sequence, wherein the movable wellcenter assembly 120 has been moved (indicated by arrow 120m) into position below the drill floor 125 at the first drilling package 112 by the wellcenter moving means 123 for the next on-line (i.e., cementing) operation on the subsea wellbore 175. As with the various other bottomhole drilling operations described above, the wellcenter moving means 123 may be used to appropriately position the movable wellcenter assembly 120 such that the operational centerline 122c of the movable wellcenter assembly 120 is substantially aligned/coincident with the operational centerline 112c of the first drilling package 112. Furthermore, while the on-line cementing operation is being performed by the cementing apparatus 162 at the first drilling package 112, off-line break-down and set-up activities may commence and continue at the second drilling package 114 in preparation for the next on-line operation.

In certain embodiments, the set-up used to run the casing string 161 into the wellbore 175 may first be broken down at second drilling package 114, after which off-line operations may begin so as to prepare the drill floor 125 for the next operation. For example, a new drilling package, including, e.g., a new bottomhole assembly 166 attached to a drill string 164, may be set up so that drilling operations on the next bottomhole section of the wellbore 175 can commence almost immediately after the on-going cementing operation at the first drilling package 112 is completed.

Turning now to Fig. 7 J, a subsequent operational step is schematically illustrated wherein the next bottomhole on-line drilling operation is being performed by the second drilling package 114 using the bottomhole assembly 166 and drill string 164 to further extend the subsea wellbore 175 into the formation 151. Meanwhile, off-line set up activities may be performed on the drill floor 125 at the first drilling package 112 in preparation for the next on-line operation, which in the illustrated embodiment may include running a second smaller sized casing 168 into the bottomhole section that is currently being drilled by the bottomhole assembly 166 at the second drilling package 114.

Figure 7 schematically depicts the drilling system of Fig. 7L after the wellcenter moving means 123 has once again been used to once again swap the position of the movable wellcenter assembly 120 from the second drilling package 114 to the first drilling package 112 by laterally moving (indicated by arrow 120m) the movable wellcenter assembly 120 so that the operational centerline 122c is substantially aligned/coincident with the operational centerline 112c of the first drilling package 112. Thereafter, as shown in Fig. 7 the next on-line operation is performed by the first drilling package 112, which is used to run the second bottomhole casing string 168 down through the movable wellcenter assembly 120 and BOP 156 and into the newly drilled bottomhole section of the subsea wellbore 175.

As with the previous bottomhole casing operation (see, e.g., Fig. 7H), while the movable wellcenter assembly 120 is being moved over to the first drilling package 112, and while the first drilling package 112 is performing the on-line casing operation on the second bottomhole section of the wellbore 175, off-line break-down and set-up activities may be performed at the second drilling package 114 in preparation for the subsequent on-line operation, e.g., cementing in the casing string 168. For example, after the previously used drilling set-up (e.g., the drill string 164 and bottomhole assembly 166) has been broken down at the second drilling package 114, operations for once again setting up the cementing apparatus 162 may be started so that the cementing apparatus 162 is ready to perform the on-line cementing operation on the casing string 168 that is currently being run into the wellbore 175 by the first drilling package 112. Thereafter, as is schematically shown in Fig. 7L, the movable wellcenter assembly 120 may be moved back to the second drilling package 114 using the wellcenter moving means 123, after which an on-line cementing operation may be performed on the previously run drill string 168. During the wellcenter assembly movement and on-line cementing operations, off-line operations may be performed at the first drilling package 112 by breaking down the casing running set-up and preparing the drill floor 125 at the first drilling package 112 for a subsequent on-line operation. For example, as shown in Fig. 7L, the first drilling package 112 may be prepared for drilling a further bottomhole interval by, among other things, attaching a new bottomhole assembly 172 to a drill string 170, etc.

As would be understood by those of ordinary skill in the art after a complete reading of the present disclosure, dual activity operations in accordance with the sequence illustrated in Figs. 7G-7L and described above may be repeated until the bottomhole section of the subsea wellbore 175 has been drilled and cased down to the target well depth. Once the wellbore 175 has been drilled and the bottomhole portion has been completed to the desired depth, the BOP 156 is then unlatched from the wellhead 152, and the BOP 156 and riser 122 may be retrieved to surface of the body of water 101. Thereafter, in certain embodiments the wellbore 175 may be capped for later completion activities, whereas in at least some embodiments, completion activities, such as installing a downhole production assembly and tubing string (not shown), may be performed and a Christmas tree installed at the wellhead 152 using both the first and second drilling packages 112, 114 in similar fashion to that described with respect to Figs. 7A-7L above.

Figures 8A-8C are close-up elevation views that are similar to the close-up elevation view depicted in Fig. 5 and described above, wherein however the illustrated system includes a further exemplary embodiment of a movable wellcenter assembly 120x in accordance with the present disclosure that may also be used to facilitate dual activity operations such as are described and illustrated with respect to Figs. 7A-7L above. More particularly, while the movable wellcenter assembly 120 shown in Fig. 4 includes the rotary table 119, the riser diverter 127, the riser

122, and the riser tensioner assembly 121 Figs. 8A-8C illustrate a system wherein the first and second drilling packages 112 and 114 may include separate rotary tables and separate riser diverters that are not moved together with the movable wellcenter assembly 120x between the two drilling packages 112, 114 during dual activity operations.

For example, as shown in Figs. 8A-8C, the movable wellcenter assembly 120x may include the riser 122 and riser tensioner assembly 121, which together are laterally moved back and forth along the drill floor 125 and between positions proximate the first and second drilling packages using the wellcenter moving means 123. On the other hand, the first drilling package 112 may have its own first rotary table 119a and first riser diverter 127a, both of which may remain in place proximate first drilling package 112, i.e., substantially aligned/co-centric with the operational centerline 112c, while the movable wellcenter assembly 120x is laterally moved along the drill floor

125 by the wellcenter moving means 123. Similarly, the second drilling package may have its own second rotary table 119b and second riser diverter 127b, both of which may also remain in place proximate second drilling package 114, i.e., substantially aligned/co-centric with the operational centerline 114c, while the movable wellcenter assembly 120x is laterally moved along the drill floor 125.

While the first rotary table 119a and the first riser diverter 127b may both be adapted to remain in a substantially fixed position relative to the first drilling package 112 during at least some, or even all, dual activity drilling operations (see, e.g., Figs. 7A-7L), the first rotary table 119a and the first riser diverter 127b may be adapted to be laterally moved into and/or out of position proximate the first drilling package 112. Moreover, in some embodiments the first rotary table 119a and the first riser diverter 127b may be adapted to be moved individually or separately, whereas in other embodiments they may be adapted to be moved jointly, i.e., as a single unit. Furthermore, the second rotary table 119b and the second riser diverter 127b may be similarly configured, i.e., such that they are adapted to remain in a substantially fixed position relative to the second drilling package 114, or to be laterally moved, individually or jointly, into and/or out of a position proximate the second drilling package 114.

Figures 8A-8C illustrate a sequential sequence of steps that substantially conform to the sequence depicted in Figs. 7D-7F above, respectively, except that Figs. 8A-8C show that the rotary tables 119a/b and riser diverters 127a/b remain in place proximate their respective drilling packages are not laterally moved along the drill floor 125 by the wellcenter moving means 123 together with the movable wellcenter assembly 120x. For example, Fig. 8A shows the movable wellcenter assembly 120x proximate the second drilling package 114 with the operational centerline 122c of the movable wellcenter assembly 120x substantially aligned/coincident with the operational centerline 114c of the second drilling package 114. See, e.g., Fig. 7D, wherein the BOP 156 has been landed on and latched to the subsea wellhead 152. Furthermore, Fig. 8B shows the movable wellcenter assembly 120x after it has been moved (indicated by arrow 120m) by the wellcenter moving means 123 approximately halfway from the second drilling package 114 to the first drilling package 112. See, e.g., Fig. 7E. Finally, Fig. 8C shows the movable wellcenter assembly 120x after it has been moved (indicated by arrow 120m) into position below the drill floor 125 at the first drilling package 112, such that the operational centerline 122c of the movable wellcenter assembly 120x is substantially aligned/coincident with the operational centerline 112c of the first drilling package 112. See, e.g., Fig. 7F.

As a result of the subject matter set forth above, the present disclosure discloses new and unique systems and methods that may facilitate performing dual activity drilling operations through a single riser using a plurality of laterally adjacent drilling packages. For example, in some illustrative embodiments, a movable wellcenter assembly that includes at least a marine riser coupled to a blowout preventer and riser tensioner assembly may be laterally moved, i.e., back and forth, along the drill floor between operational centerlines of adjacent drilling packages while alternatingly performing on-line drilling operations with each individual drilling package through the same riser.

The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. For example, the method steps set forth above may be performed in a different order. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the invention. Accordingly, the protection sought herein is as set forth in the claims below.

Claims

CLAIMS WHAT IS CLAIMED:

1. A drilling system, comprising:

a plurality of laterally adjacent drilling packages (112, 114);

a movable wellcenter assembly (120) comprising a riser (122) and a riser tensioner assembly (121) coupled to a first end of said riser (122), wherein a second end of said riser (122) is adapted to be operatively coupled to a wellhead (152); and

wellcenter moving means (123) that is adapted to laterally move said movable wellcenter assembly (120) from a position proximate a first one of said plurality of laterally adjacent drilling packages (112, 114) to a position proximate a second one of said plurality of laterally adjacent drilling packages

(112, 114) while said second end of said riser (122) is operatively coupled to said wellhead (152).

2. The drilling system of claim 1, wherein said movable wellcenter assembly (120) further comprises a rotary table (119).

3. The drilling system of claim 1, wherein said movable wellcenter assembly (120) further comprises a riser diverter (127).

4. The drilling system of claim 1, further comprising at least two rotary tables (119), wherein a first one of said at least two rotary tables (119) is positioned below a first one of said plurality of laterally adjacent drilling packages (112, 114) and a second one of at least two rotary tables (119) is positioned below a second one of said plurality of laterally adjacent drilling packages (112, 114).

5. The drilling system of claim 4, further comprising at least two riser diverters (127), each one of said at least two riser diverters (127) being operatively coupled to a respective one of said at least two rotary tables

(119).

6. The drilling system of claim 4, wherein at least one of said at least two rotary tables (119) is adapted to be laterally moved relative to said movable wellcenter assembly (120) and to each of said plurality of laterally adjacent drilling packages (112, 114).

7. The drilling system of claim 1, wherein said movable wellcenter assembly (120) has a wellcenter operational centerline (122c) and each of said plurality of laterally adjacent drilling packages (112, 114) has a drilling package operational centerline (112c, 114c).

8. The drilling system of claim 7, wherein said wellcenter moving means (123) is adapted to position said movable wellcenter assembly (120) proximate each respective one of said plurality of laterally adjacent drilling packages (112, 114) so that said wellcenter operational centerline (122c) is substantially coincident with said drilling package operational centerline (112c, 114c) of said respective one of said plurality of laterally adjacent drilling packages (112, 114).

9. The drilling system of claim 1, wherein said plurality of laterally adjacent drilling packages (112, 114) are positioned above a drill floor of a mobile offshore drilling unit (100).

10. The drilling system of claim 1, wherein each of said plurality of laterally adjacent drilling packages (112, 114) is adapted to perform each one of a drilling operation, a casing running operation, and a cementing operation through said movable wellcenter assembly (120).

11. The drilling system of claim 1, wherein a first one of said plurality of laterally adjacent drilling packages (112, 114) is adapted to perform a drilling operation through said movable wellcenter assembly (120) and a second one of said plurality of laterally adjacent drilling packages (112, 114) is adapted to perform a casing running operation through said movable wellcenter assembly (120) after said wellcenter moving means (123) has laterally moved said movable wellcenter assembly (120) from said position proximate said first one of said plurality of laterally adjacent drilling packages (112, 114) to said position proximate said second one of said plurality of laterally adjacent drilling packages (112, 114).

12. A method for drilling a wellbore, the method comprising:

positioning a movable wellcenter assembly (120) in a first position proximate a first drilling package (112) of an offshore drilling unit (100);

while said movable wellcenter assembly (120) is positioned in said first position, performing a first drilling operation through said movable wellcenter assembly (120) with said first drilling package (112); after performing said drilling operation, laterally moving said movable wellcenter assembly (120) from said first position to a second position proximate a second drilling package (114) of said offshore drilling unit (100); and

while said movable wellcenter assembly (120) is positioned in said second position, performing a second drilling operation through said movable wellcenter assembly (120) with said second drilling package (114).

13. The method of claim 12, further comprising, after performing said second drilling operation, laterally moving said movable wellcenter assembly (120) from said second position to said first position, and thereafter performing a third drilling operation through said movable wellcenter assembly (120) with said first drilling package (112) while said movable wellcenter assembly (120) is in said first position.

14. The method of claim 12, wherein positioning said movable wellcenter assembly (120) in said first position proximate said first drilling package (112) comprises positioning said movable wellcenter assembly (120) so that an operational centerline (122c) of said movable wellcenter assembly (120) is substantially coincident with an operational centerline (112c) of said first drilling package (112), and wherein positioning said movable wellcenter assembly (120) in said second position proximate said second drilling package (114) comprises positioning said movable wellcenter assembly (120) so that said operational centerline (122c) of said movable wellcenter assembly (120) is substantially coincident with an operational centerline (114c) of said second drilling package (114).

15. The method of claim 12, wherein said movable wellcenter assembly (120) comprises a riser (122) and a riser tensioner assembly (121) operatively coupled to an upper end of said riser (122), the method further comprising, prior to positioning said movable wellcenter assembly (120) in said first position, operatively coupling a lower end of said riser (122) to a subsea wellhead (152).

16. A method, comprising :

operatively coupling wellcenter moving means (123) to a drill floor of an offshore drilling unit (100); operatively coupling a movable wellcenter assembly (120) to said wellcenter moving means (123); and laterally moving said movable wellcenter assembly (120) with said wellcenter moving means (123) between positions proximate laterally adjacent drilling packages (112, 114).

17. The method of claim 16, wherein said movable wellcenter assembly (120) comprises a riser (122), the method further comprising operatively coupling a lower end of said riser (122) to a wellhead (152) prior to laterally moving said movable wellcenter assembly (120) with said wellcenter moving means (123).