WO2016054610A1 - Système d'installation de forage comprenant un ensemble centre de puits mobile - Google Patents

Système d'installation de forage comprenant un ensemble centre de puits mobile Download PDF

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Publication number
WO2016054610A1
WO2016054610A1 PCT/US2015/053888 US2015053888W WO2016054610A1 WO 2016054610 A1 WO2016054610 A1 WO 2016054610A1 US 2015053888 W US2015053888 W US 2015053888W WO 2016054610 A1 WO2016054610 A1 WO 2016054610A1
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WO
WIPO (PCT)
Prior art keywords
drilling
wellcenter
assembly
movable
riser
Prior art date
Application number
PCT/US2015/053888
Other languages
English (en)
Inventor
Frank B. Springett
Frode JENSEN
Original Assignee
National Oilwell Varco, L.P.
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Filing date
Publication date
Application filed by National Oilwell Varco, L.P. filed Critical National Oilwell Varco, L.P.
Publication of WO2016054610A1 publication Critical patent/WO2016054610A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
    • E21B19/002—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B15/00—Supports for the drilling machine, e.g. derricks or masts
    • E21B15/02—Supports for the drilling machine, e.g. derricks or masts specially adapted for underwater drilling

Definitions

  • 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.
  • Drilling offshore oil and gas wells typically includes three operational phases.
  • 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.
  • 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.
  • the 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.
  • a first string of structural casing may have a diameter of approximately 24 inches (600 mm)
  • 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.
  • BOP blowout preventer
  • 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 is performed after the BOP is installed.
  • 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.
  • the bottomhole drilling phase is performed in a controlled manner through the riser.
  • a drill string including a bottomhole assembly 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.
  • 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.
  • 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.
  • a third phase of post-drilling operations is performed.
  • the BOP is unlatched from the wellhead and retrieved to the surface by the riser.
  • the well may be capped for later completion activities.
  • a downhole production assembly and a tubing string may be installed in the wellbore, and a Christmas tree installed at the wellhead.
  • 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.
  • a single load path e.g., derrick, rig, drilling assembly, etc.
  • 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.
  • 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.
  • dual drilling assemblies e.g., separate load paths and/or derricks
  • 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.
  • BOP blowout preventer
  • 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.
  • the primary or bottomhole drilling phase is thereafter performed using a single load path - i.e., through the primary drilling station.
  • 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.
  • 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.
  • 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.
  • a method for drilling a wellbore 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.
  • 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;
  • 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.
  • 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.
  • 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.
  • FIGS 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.
  • Fig. 1 is a pian view of the mobile offshore drilling unit
  • 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
  • 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.
  • 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.
  • 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.
  • 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).
  • 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.
  • 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.
  • At least some of the ancillary drilling activity support equipment 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.
  • 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-
  • 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.
  • 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.
  • 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.
  • 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.
  • a movable wellcenter assembly 120 may be positioned below the drill floor 125 and extending partially down into the moon pool 108.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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
  • 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.
  • 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.
  • a first drilling operation is being performed by the first drilling package 112 on a given subsea wellbore (not shown; see, e.g., Figs.
  • 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.
  • 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.
  • the first drilling operation e.g., drilling a bottomhole section
  • the various set-up activities that are required to prepare the second drilling package 114 for performing the next drilling operation 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.
  • any tools that may have been used during the first drilling operation 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.
  • 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.
  • the next drilling operation e.g., running casing into the previously drilled bottomhole section
  • 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 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.”
  • 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.
  • 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.
  • 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.
  • 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.
  • FIGs 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.
  • 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.
  • a jetting operation, and/or a drilling and cementing operation is being performed with the first drilling package 112.
  • 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
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • a bottomhole assembly 160 drill bit, drilling motor, drill collars, stabilizers, 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.
  • 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.
  • the movable wellcenter assembly 120 has been 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
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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
  • 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.
  • 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.
  • 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
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Mechanical Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)

Abstract

La présente invention concerne un système de forage comprenant une pluralité d'ensembles de forage adjacents latéralement (112, 114) et un ensemble centre de puits mobile qui comprend une colonne montante et un ensemble tendeur de colonne montante accouplé à une première extrémité de la colonne montante, une seconde extrémité de la colonne montante étant conçue pour être accouplée fonctionnellement à une tête de puits. Le système de forage comprend en outre un moyen de déplacement de centre de puits qui est conçu pour déplacer latéralement l'ensemble centre de puits mobile à partir d'une position à proximité d'un premier ensemble de la pluralité d'ensembles de forage adjacents latéralement (112, 114) dans une position à proximité d'un second ensemble de la pluralité d'ensembles de forage latéralement adjacents (112, 114) pendant que la seconde extrémité de la colonne montante est accouplée fonctionnellement à la tête de puits.
PCT/US2015/053888 2014-10-03 2015-10-03 Système d'installation de forage comprenant un ensemble centre de puits mobile WO2016054610A1 (fr)

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US201462059539P 2014-10-03 2014-10-03
US62/059,539 2014-10-03
US201462062415P 2014-10-10 2014-10-10
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Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2018048658A1 (fr) 2016-09-07 2018-03-15 Frontier Deepwater Appraisal Solutions LLC Installation de pétrole et de gaz flottante dotée d'un ensemble de baie de puits mobile
WO2018096160A1 (fr) * 2016-11-27 2018-05-31 Maersk Drilling A/S Forage en haute mer et structure de support configurable associée
WO2018233783A1 (fr) * 2017-06-19 2018-12-27 Maersk Drilling A/S Procédé et appareil pour déployer/récupérer une colonne tubulaire à partir d'une plateforme de forage en mer
WO2021037361A1 (fr) * 2019-08-28 2021-03-04 Rigtec As Agencement pour système de forage, système et procédé de forage
US11225844B2 (en) 2017-02-17 2022-01-18 Japan Agency For Marine-Earth Science And Technology Submarine drilling support system

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US20040134661A1 (en) * 2002-12-06 2004-07-15 Von Der Ohe Christian B. Riser-tensioning device balanced by horizontal force
CA2654901A1 (fr) * 2006-06-30 2008-10-01 Stena Drilling Ltd. Bateau de forage a triple activite
WO2011011505A2 (fr) * 2009-07-23 2011-01-27 Bp Corporation North America Inc. Système de forage au large
WO2014140369A2 (fr) * 2013-03-15 2014-09-18 A.P. Møller-Mærsk A/S Plateforme de forage en mer et son procédé de fonctionnement

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Publication number Priority date Publication date Assignee Title
US20040134661A1 (en) * 2002-12-06 2004-07-15 Von Der Ohe Christian B. Riser-tensioning device balanced by horizontal force
CA2654901A1 (fr) * 2006-06-30 2008-10-01 Stena Drilling Ltd. Bateau de forage a triple activite
WO2011011505A2 (fr) * 2009-07-23 2011-01-27 Bp Corporation North America Inc. Système de forage au large
WO2014140369A2 (fr) * 2013-03-15 2014-09-18 A.P. Møller-Mærsk A/S Plateforme de forage en mer et son procédé de fonctionnement

Cited By (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2018048658A1 (fr) 2016-09-07 2018-03-15 Frontier Deepwater Appraisal Solutions LLC Installation de pétrole et de gaz flottante dotée d'un ensemble de baie de puits mobile
US9976364B2 (en) * 2016-09-07 2018-05-22 Frontier Deepwater Appraisal Solutions LLC Floating oil and gas facility with a movable wellbay assembly
US10428599B2 (en) 2016-09-07 2019-10-01 Frontier Deepwater Appraisal Solutions, Llc Floating oil and gas facility with a movable wellbay assembly
US10865608B2 (en) 2016-09-07 2020-12-15 Frontier Deepwater Appraisal Solutions LLC Movable wellbay assembly
WO2018096160A1 (fr) * 2016-11-27 2018-05-31 Maersk Drilling A/S Forage en haute mer et structure de support configurable associée
US11225844B2 (en) 2017-02-17 2022-01-18 Japan Agency For Marine-Earth Science And Technology Submarine drilling support system
WO2018233783A1 (fr) * 2017-06-19 2018-12-27 Maersk Drilling A/S Procédé et appareil pour déployer/récupérer une colonne tubulaire à partir d'une plateforme de forage en mer
GB2577424A (en) * 2017-06-19 2020-03-25 Maersk Drilling As Method and apparatus for deploying / retrieving tubing string from offshore rig
GB2577424B (en) * 2017-06-19 2022-01-12 Maersk Drilling As Method and apparatus for deploying / retrieving tubing string from offshore rig
WO2021037361A1 (fr) * 2019-08-28 2021-03-04 Rigtec As Agencement pour système de forage, système et procédé de forage

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