EP3187681B1 - Schneidsequenz für eine preventergarnitur - Google Patents

Schneidsequenz für eine preventergarnitur Download PDF

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Publication number
EP3187681B1
EP3187681B1 EP15307172.5A EP15307172A EP3187681B1 EP 3187681 B1 EP3187681 B1 EP 3187681B1 EP 15307172 A EP15307172 A EP 15307172A EP 3187681 B1 EP3187681 B1 EP 3187681B1
Authority
EP
European Patent Office
Prior art keywords
ram
actuator
tubular string
bore
hydraulic fluid
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Not-in-force
Application number
EP15307172.5A
Other languages
English (en)
French (fr)
Other versions
EP3187681A1 (de
Inventor
Regis REY
Florent Vargas
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Cameron Technologies Ltd
Original Assignee
Cameron Technologies Ltd
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Cameron Technologies Ltd filed Critical Cameron Technologies Ltd
Priority to EP15307172.5A priority Critical patent/EP3187681B1/de
Priority to US15/392,992 priority patent/US20170191337A1/en
Publication of EP3187681A1 publication Critical patent/EP3187681A1/de
Application granted granted Critical
Publication of EP3187681B1 publication Critical patent/EP3187681B1/de
Not-in-force legal-status Critical Current
Anticipated expiration legal-status Critical

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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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
    • E21B33/061—Ram-type blow-out preventers, e.g. with pivoting rams
    • E21B33/062—Ram-type blow-out preventers, e.g. with pivoting rams with sliding rams
    • E21B33/063—Ram-type blow-out preventers, e.g. with pivoting rams with sliding rams for shearing drill pipes
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
    • E21B33/061—Ram-type blow-out preventers, e.g. with pivoting rams
    • 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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
    • E21B33/064—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers specially adapted for underwater well heads
    • 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
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/16—Control means therefor being outside the borehole
    • 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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • 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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/01—Risers

Definitions

  • US 2010/155086 discloses a blowout preventer system.
  • US 6006647 describes an actuator with a free-floating piston for a blowout preventer and ensures that the actuator locking mechanism remains in a locked position if no hydraulic pressure is applied to the hydraulic fluid of the actuator.
  • US9022104 describes a blowout preventer with a blade assembly including a ram block movable between a non-engagement position and an engagement position about the tubular, a blade carried by the ram block for cuttingly engaging the tubular, and a retractable guide carried by the ram block for urging the tubular into a desired location in the blowout preventer as the ram block moves to the engagement position.
  • the present invention resides in d a blowout preventer system as defined in claim 1, a method as defined in claim 9 and a system as defined in claimed 12.
  • a blowout preventer (BOP) stack may be installed on a wellhead to seal and control an oil and gas well during drilling operations.
  • a tubular string may be suspended inside a drilling riser and extend through the BOP stack into the wellhead.
  • a drilling fluid may be delivered through the tubular string and returned through a bore between the tubular string and a casing of the drilling riser.
  • the BOP stack may be actuated to seal the drilling riser from the wellhead and to control a fluid pressure in the bore, thereby protecting well equipment disposed above the BOP stack.
  • Embodiments of the present disclosure relate to a blowout preventer (“BOP") system that may completely shear (e.g., cut) a tubular string to enhance a seal of a wellbore when blowout conditions are detected.
  • BOP blowout preventer
  • a BOP may be included at a wellhead to block a fluid from inadvertently flowing from the wellhead to a drilling platform (e.g., through a drilling riser). For example, pressures may fluctuate within a natural reservoir, which may lead to a surge in fluid flow from the wellhead toward the drilling platform when the pressure reaches a threshold value.
  • the BOP may be actuated to cut the tubular string and seal the drilling riser from the wellhead (e.g., by covering a bore in the BOP coupling the wellhead to the drilling riser).
  • at least one BOP of a BOP stack may include shearing rams that may be configured to cut the tubular string and enhance a seal of the bore extending through the BOP.
  • a BOP system may be operated utilizing an enhanced shearing sequence to enhance a seal between the wellhead and the drilling riser during blowout.
  • the BOP system may be configured to actuate a first ram of the BOP from an open position toward the tubular string and into the bore of the BOP.
  • the first ram may contact the tubular string and align the tubular string with a shearing portion of a second ram of the BOP before the second ram is actuated.
  • the second ram may then be actuated such that shearing portions of both the first and second rams fully contact the tubular string and perform a cut (e.g., a complete cut) of the tubular string.
  • Completely cutting or shearing the tubular string may enable the first and second rams to completely cover the bore of the BOP, and thus, form an enhanced seal between the wellhead and the drilling riser.
  • FIG. 1 is a schematic of an embodiment of a mineral extraction system 10.
  • the mineral extraction system 10 includes a vessel or platform 12 at a surface 14.
  • a BOP stack assembly 16 is mounted to a wellhead 18 at a floor 20 (e.g., a sea floor for offshore operations).
  • a tubular drilling riser 22 extends from the platform 12 to the BOP stack assembly 16.
  • the riser 22 may return drilling fluid or mud to the platform 12 during drilling operations.
  • Downhole operations are carried out by a tubular string 24 (e.g., drill string, production tubing string, or the like) that extends from the platform 12, through the riser 22, through a bore 25 of the BOP stack assembly 16, and into a well bore 26.
  • a tubular string 24 e.g., drill string, production tubing string, or the like
  • the BOP stack assembly 16 and its components may be described with reference to an axial axis or direction 30, a longitudinal axis or direction 32, and a lateral axis or direction 34.
  • the BOP stack assembly 16 includes a BOP stack 38 having multiple BOPs 40 (e.g., ram BOPs) axially stacked (e.g., along the axial axis 30) relative to one another.
  • each BOP 40 includes a pair of longitudinally opposed rams and corresponding actuators 42 that actuate and drive the rams toward and away from one another along the longitudinal axis 32.
  • the BOP stack 38 may include any suitable number of BOPs (e.g., 1, 2, 3, 4, 5, 6, 7, 8, 9, 10 or more). Additionally, the BOP stack 38 may include any of a variety of different types of rams. For example, in certain embodiments, the BOP stack 38 may include one or more BOPs 40 having opposed shear rams or blades configured to sever the tubular string 24 and seal off the wellbore 26 from the riser 22 and/or one or more BOPs 40 having opposed pipe rams configured to engage the tubular string 24 and to seal the bore 25 (e.g., an annulus around the tubular string 24).
  • the BOP stack 38 may include one or more BOPs 40 having opposed shear rams or blades configured to sever the tubular string 24 and seal off the wellbore 26 from the riser 22 and/or one or more BOPs 40 having opposed pipe rams configured to engage the tubular string 24 and to seal the bore 25 (e.g., an annulus around the tubular string 24).
  • FIG. 2 is a perspective view of an embodiment of the BOP stack assembly 16.
  • the BOP stack 38 includes multiple BOPs 40 axially stacked (e.g., along the axial axis 30) relative to one another.
  • the BOP stack 38 also includes one or more hydraulic accumulators 45.
  • the hydraulic accumulators 45 may store and/or supply (e.g., via one or more pumps) hydraulic pressure to the actuators 42 that are configured to drive the rams of the BOPs 40.
  • the hydraulic accumulators 45 and/or the actuators 42 may be communicatively coupled to a controller 46.
  • the controller 46 may be configured to send signals to the hydraulic accumulators 45, the actuators 42, and/or one or more pumps to drive the rams of the BOPs 40 when blowout conditions exist.
  • the controller 46 may receive feedback from one or more sensors 47 (e.g., pressure sensors and/or flow sensors) that may monitor conditions of the wellbore 26 (e.g., a pressure of the fluid in the wellbore 26).
  • the controller 46 may include memory 48 that stores threshold values indicative of blowout conditions. Accordingly, a processor 49 of the controller 46 may send a signal instructing the hydraulic accumulators 45, the actuators 42, and/or the one or more pumps to drive and/or actuate the rams when measured feedback received from the controller 46 meets or exceeds such threshold values.
  • FIG. 3 is a cross-sectional top view of a portion of one BOP 40 with a first ram 50 and a second ram 52 in an open position 54.
  • the first ram 50 and the second ram 52 are withdrawn or retracted from the bore 25, do not contact the tubular string 24, and/or do not contact the corresponding opposing ram 50, 52.
  • the BOP 40 includes a body 56 (e.g., housing) surrounding the bore 25.
  • the body 56 is generally rectangular in the illustrated embodiment, although the body 56 may have any cross-sectional shape, including any polygonal shape or an annular shape.
  • a bonnet assembly 60 is mounted to the body 56 (e.g., via threaded fasteners).
  • the bonnet assembly 60 may support the actuators 42, which each include a piston 62 and a connecting rod 63. As shown in the illustrated embodiment, when in the open position 54, the first ram 50 is generally adjacent to a first end 64 of the body 56 and the second ram 52 is generally adjacent to a second end 65 opposite the first end 64 of the body 56.
  • the actuators 42 may drive the first and second rams 50, 52 toward and away from one another along the longitudinal axis 32 and through the bore 25 to shear the tubular string 24 and/or to seal the bore 25 (e.g., the annulus about the tubular string 24).
  • the first ram 50 may include a first shearing portion 66
  • the second ram 52 may include a second shearing portion 68.
  • the first shearing portion 66 may include a first width 70 that is greater than a diameter 72 of the tubular string 24, such that the first shearing portion 66 may cut through the entire tubular string 24.
  • the second shearing portion 68 may include a second width 74 that is greater than the diameter 72 of the tubular string 24. Accordingly, when the first and second shearing portions 66, 68 are aligned with the tubular string 24 and are directed toward one another, the tubular string 24 may be completely cut to seal the bore 25.
  • the first and second shearing portions 66, 68 may not extend across an entire diameter 76 of the bore 25.
  • the bore 25 may include an annular opening 78 that surrounds the tubular string 24.
  • the first and second rams 50, 52 may include non-shearing portions 80, 82, respectively, that are configured to cover portions of the bore 25 that may be left uncovered by the shearing portions 66, 68. Accordingly, during blowout conditions, the first and second rams 50, 52 may be moved along the longitudinal axis 32 toward one another to seal the bore 25. To completely seal the bore 25, the first and second rams 50, 52 may cut through the tubular string 24.
  • the shearing portions 66, 68 may include different geometries.
  • the first shearing portion 66 may include a substantially linear (e.g., a generally straight line) geometry.
  • the second shearing portion 68 may include an indented (e.g., two lines forming an obtuse angle with respect to a joint 83) geometry.
  • the first and second shearing portions 66, 68 may include any suitable geometry for cutting the tubular string 24 and sealing the bore 25.
  • the first shearing portion 66 and the second shearing portion 68 may be offset with respect to the axial axis 30 (see FIG. 5 ).
  • first shearing portion 66 may be at a first position along the axial axis 30 such that the second shearing portion 68 may be configured to be positioned above or below (e.g., with respect to the axial axis 30) the first shearing portion 66 (e.g., the first and second shearing portions 66, 68 may not directly contact one another) when both the first and second shearing portions 66, 68 are in a second position (see FIG. 6 ).
  • Such a configuration may enable both the first and second shearing portions 66, 68 to completely pass through the tubular string 24 when blowout conditions exist.
  • the tubular string 24 may not be positioned in a center of the bore 25 with respect to the rams 50, 52.
  • the tubular string 24 may not be aligned with the first shearing portion 66 of the first ram 50 and/or the second shearing portion 68 of the second ram 52. Accordingly, driving the first and second rams 50, 52 toward one another along the longitudinal axis 32 simultaneously may not enable both the first shearing portion 66 and the second shearing portion 68 to contact a complete circumference 84 (e.g., outer surface) of the tubular string 24.
  • a complete circumference 84 e.g., outer surface
  • the first ram 50 may apply a first force to the tubular string 24 in a first direction 86
  • the second ram 52 may apply a second force to the tubular string 24 in a second direction 88 opposite the first direction 86.
  • the first force and the second force applied in opposing directions 86, 88 may be substantially equal, such that the tubular string 24 may remain substantially stationary when the first and second rams 50, 52 are simultaneously driven toward the tubular string 24 and contact the tubular string 24 at approximately the same time.
  • the tubular string 24 may be cut as the first and second shearing portions 66, 68 contact the circumference 84 of the tubular string 24. However, because the first shearing portion 66 and/or the second shearing portion 68 may not be aligned with the entire circumference 84 of the tubular string 24, a portion 90 of the tubular string 24 may not be cut by the rams 50, 52. The portion 90 of the tubular string 24 left uncut may block the rams 50, 52 (e.g., the non-shearing portions 80, 82) from completely contacting one another, such that the bore 25 includes a gap or opening that may enable fluid to flow from the wellbore 26 (e.g., wellhead) and into the drilling riser 22 when blowout conditions occur.
  • the rams 50, 52 e.g., the non-shearing portions 80, 82
  • the bore 25 may not be completely sealed by the BOP 40 as a result of the uncut portion 90 of the tubular string 24. Therefore, it is now recognized that an enhanced sequence of actuating the rams 50, 52 is desired to enhance the seal of the bore 25.
  • FIG. 4 is a cross-sectional top view of a portion of the BOP 40 of the BOP stack 38, illustrating the first ram 50 in a second position 100 and the second ram 52 in the open position 54. Accordingly, FIG. 4 illustrates the BOP 40 operating with an enhanced sequence that includes driving the first ram 50 into the second position 100 before driving the second ram 52 toward the tubular string 24 (and the first ram 50). It should be noted that in other embodiments, the second ram 52 may be actuated before the first ram 50 to align the tubular string 24, and then the first ram 50 may be actuated to cut the tubular string 24.
  • the first ram 50 aligns the tubular string 24, the first shearing portion 66, and the second shearing portion 68 of the second ram 52 along an axis 101.
  • the first ram 50 may align the tubular string 24 by contacting the tubular string 24 and directing the tubular string 24 in the first direction 86. As the tubular string 24 moves in the direction 86, it may be guided along an inner diameter 102 of the bore 25 (e.g., in a direction 104 about the axial axis 30).
  • the tubular string 24 may contact a portion 106 of the inner diameter 102 closest to the second shearing portion 68 of the second ram 52, and thus be substantially aligned with the second shearing portion 68 along the axis 101.
  • the position of the tubular string 24 within the bore 25 may be adjusted by the first ram 50 and/or the second ram 52 (e.g., the tubular string 24 is not substantially fixed with respect to the bore 25). Therefore, actuating the first ram 50 before the second ram 52 (or vice versa) enables the tubular string 24 to be guided along the inner diameter 102 of the bore 25 to a position that substantially aligns the entire diameter 72 of the tubular string 24 with the first shearing portion 66 and the second shearing portion 68 along the axis 101.
  • FIG. 5 is a schematic of the of a portion of the BOP 40, illustrating the first ram 50 in the second position 100 and the second ram 52 in the open position 54.
  • the illustrated embodiment of FIG. 5 shows a hydraulic circuit 122 that may direct hydraulic fluid 124 from one or more of the hydraulic accumulators 45 to the actuators 42 via a first pump 125.
  • the actuators 42 may be pneumatic such that the BOP 40 includes a pneumatic circuit (e.g., that includes a compressor) instead of the hydraulic circuit 122.
  • the hydraulic circuit 122 may include the sequencing valve 120 to perform the enhanced shearing sequence.
  • the sequencing valve 120 may be configured to direct the hydraulic fluid 124 toward a first hydraulic chamber 126 of a first actuator 127 that drives the first ram 50 along the longitudinal axis 32 (e.g., the hydraulic fluid 124 directs the first actuator 127 along the longitudinal axis 32 by increasing the pressure in the first hydraulic chamber 126 to drive the first actuator in the direction 86).
  • the sequencing valve 120 may be configured to block the hydraulic fluid 124 from flowing toward a first hydraulic chamber 128 of a second actuator 129 configured to drive the second ram 52 along the longitudinal axis 32. Therefore, the sequencing valve 120 enables the first ram 50 to be actuated along the longitudinal axis 32, while generally maintaining the second ram 52 in the open position 54.
  • a second hydraulic fluid 130 may flow from a second hydraulic chamber 131 of the first actuator 127 toward one or more of the hydraulic accumulators 45.
  • pressure may increase in the second hydraulic chamber 131 as the first actuator 127 moves in the direction 86 (e.g., as a result of a reduction of a volume of the second hydraulic chamber 131 caused by the piston 62). Accordingly, the pressure within the second hydraulic chamber 131 may urge the second hydraulic fluid 130 through an outlet 132 of the second hydraulic chamber 131 and toward one or more of the hydraulic accumulators 45.
  • the sequencing valve 120 may include a mechanism (e.g., a spring or other biasing member) that blocks an outlet 134 of the sequencing valve 120 coupled to the second actuator 129 until a threshold pressure of the hydraulic fluid 124 is reached. Accordingly, the sequencing valve 120 may direct hydraulic fluid 124 toward the first actuator 127 and block the hydraulic fluid 124 from flowing toward the second actuator 129 until the first ram 50 is in the second position 100.
  • the threshold pressure of the sequencing valve 120 may be set (e.g., manually or electronically via the controller 46) at a pressure corresponding to the hydraulic fluid 124 when the first ram 50 is in second position 100. When the threshold pressure is met and/or exceeded, the outlet 134 of the sequencing valve 120 may be configured to open such that the hydraulic fluid 124 is directed toward the second actuator 129.
  • FIG. 6 is a cross-sectional top view of the BOP 40, illustrating the first ram 50 in the second position 100 and the second ram 52 in a second position 140.
  • the second ram 52 contacts the tubular string 24 as it moves toward the second position 140 and applies a force in the direction 88 such that the tubular string 24 is cut.
  • the first ram 50 remains substantially stationary in the second position 100 and may apply an opposing force (e.g., reactive force) to the tubular string 24 in the direction 86 to keep the tubular string 24 substantially stationary with respect to the bore 25 as the second ram 52 moves toward the second position 140. Accordingly, as the second ram 52 moves toward the second position 140, the second shearing portion 68 and/or the first shearing portion 66 of the first ram 50 may cut through the tubular string 24, thereby sealing the bore 25.
  • an opposing force e.g., reactive force
  • FIG. 7 is a schematic of the portion of the BOP 40, illustrating the first ram 50 in the second position 100 and the second ram 52 in the second position 140.
  • the hydraulic fluid 124 flows toward the second actuator 129, thereby driving the second ram 52 in the second direction 88 toward the tubular string 24 and the first ram 50.
  • the second shearing portion 68 may contact the tubular string 24 and cut the tubular string 24, thereby sealing the bore 25.
  • the first shearing portion 66 and the second shearing portion 68 may be offset from one another with respect to the axial axis 30.
  • the first shearing portion 66 may form a ledge 160 at a first distance 162 from a bottom surface 164 of the BOP 40.
  • the second shearing portion 68 may include a surface 166 that is a second distance 168 from the bottom surface 164 of the BOP 40.
  • the second distance 168 is slightly larger than the first distance 162 such that a gap 170 is formed between the surface 166 of the second shearing portion 68 and the ledge 160 of the first shearing portion 66. Accordingly, the first ram 50 and the second ram 52 may each extend through the tubular string 24 to completely cut the tubular string 24, and thus seal the bore 25.
  • the second hydraulic fluid 130 may flow from a second hydraulic chamber 142 of the second actuator 129 toward one or more of the hydraulic accumulators 45.
  • a pressure may increase in the second hydraulic chamber 142 as the second actuator 129 moves in the direction 88 (e.g., as a result of a reduction in volume of the second hydraulic chamber 142 caused by the piston 62). Accordingly, the pressure within the second hydraulic chamber 142 may urge the second hydraulic fluid 130 through an outlet 144 of the second hydraulic chamber 142 and toward one or more of the hydraulic accumulators 45.
  • the hydraulic fluid 124 flows toward the first hydraulic chamber 128 of the second actuator 129 through a piloted check valve 172.
  • the piloted check valve 172 may include a default position 174 configured to enable the hydraulic fluid 124 to flow in a first direction 176 toward the second actuator 129.
  • the piloted check valve 172 may additionally block flow of the hydraulic fluid 124 in a second direction 178 (e.g., from the second actuator 129 toward the piloted check valve 172 and/or the sequencing valve 120).
  • the piloted check valve 172 may be fluidly coupled to the second hydraulic chamber 142 of the second actuator 129.
  • the piloted check valve 172 may be configured to trigger, thereby enabling flow of the hydraulic fluid 124 in the second direction 178 and blocking flow of the hydraulic fluid in the first direction 176.
  • the second ram 52 may be driven toward the open position 54 by the second actuator 129 (e.g., via the second hydraulic fluid 130 being pumped into the second hydraulic chamber 142 via a second pump 180).
  • FIG. 8 is a schematic of a portion of the BOP 40, illustrating the hydraulic circuit 122 directing the hydraulic fluid 124 such that the rams 50, 52 are driven to the open position 54.
  • the piloted check valve 172 is triggered, thereby enabling flow of the hydraulic fluid 124 in the second direction 178 (e.g., from the second actuator 129 toward the sequencing valve 120).
  • the hydraulic fluid 124 may drain from both the first hydraulic chamber 126 of the first actuator 127 and the first hydraulic chamber 128 of the second actuator 129 toward a hydraulic fluid reservoir (e.g., one or more of the hydraulic accumulators 45).
  • the second pump 180 may direct the second hydraulic fluid 130 from one or more of the hydraulic accumulators 45 toward the second hydraulic chamber 131 of the first actuator 127 and toward the second hydraulic chamber 142 of the second actuator 129. Therefore, pressures within the second hydraulic chambers 131, 142 may increase, thereby driving the first and second actuators 127, 129 toward the open position 54 (e.g., the first actuator 127 is driven in the direction 88 and the second actuator is driven in the direction 86).
  • the first pump 125 and/or the second pump 180 may be coupled to the controller 46, which may be configured to adjust a speed of the first and second pumps 125, 180 to control movement of the actuators 127, 129.
  • the controller 46 may be communicatively coupled to motors of the first and second pumps 125, 180 such that the controller 46 may adjust the speed of the motors, and thus, the amount of the hydraulic fluid 124, 139 directed toward the actuators 127, 129.
  • Moving the rams 50, 52 to the second positions 100, 140, respectively, may be performed in the sequence described above (e.g., driving the first ram 50 to the second position 100 before driving the second ram 52 into the second position 140).
  • directing the rams 50, 52 to the open position 54 e.g., from the second positions 100, 140
  • the bore 25 may be opened in a single step, whereas sealing the bore 25 may occur utilizing the multi-step, enhanced shearing sequence.
  • valves and conduits may be utilized to direct the first ram 50 to the second position 100, while leaving the second ram 52 substantially stationary as a first step, and then directing the second ram 52 to the second position 140 after the first ram 50 reaches the second position 100 as a second step.
  • FIG. 9 is a block diagram 200 of a process for performing the enhanced shearing sequence to enhance a seal of the bore 25 when blowout conditions exist.
  • the controller 46 may be configured to actuate the first ram 50 toward the tubular string 24 disposed in the bore 25 of the riser 22.
  • the first ram 50 may be positioned adjacent to the first end 64 of the body 56 of the BOP 40 (e.g., on a first side of the bore 25).
  • the first ram may be actuated toward the tubular string 24 by directing the hydraulic fluid 124 through the sequencing valve 120 toward the first hydraulic chamber 126 of the first actuator 127.
  • the hydraulic fluid 124 may be blocked from flowing toward the second actuator 129 by the sequencing valve 120 when the pressure of the hydraulic fluid 120 is below the threshold pressure, thereby maintaining the second ram 52 in the open position 54.
  • the first ram 50 may guide the tubular string 24 along the inner diameter 102 of the bore 25 such that the tubular string 24 is generally aligned with the first shearing portion 66 and the second shearing portion 68 of the first and second rams 50, 52 along the axis 101.
  • the second ram 50 may be positioned adjacent to the second end 65 of the body 56 of the BOP 40 (e.g., on a second side of the bore 25 opposite the first side).
  • the controller 46 may be configured to actuate the second ram 52 toward the tubular string 24 and toward the first ram 52.
  • the sequencing valve 120 may trigger when the pressure of the hydraulic fluid 124 meets or exceeds the threshold pressure, thereby opening the outlet 134 coupled to the second actuator 129. Therefore, the second ram 52 may be directed toward the tubular string 24 and the first ram 50 as the hydraulic fluid 124 flows toward the first hydraulic chamber 128 of the second actuator 129. Additionally, the first ram 52 may remain substantially stationary such that opposing forces are applied to the tubular string 24 by the first ram 50 and the second ram 52. Accordingly, the first ram 50 and the second ram 52 may cut through the entire tubular string 24 such that the bore 25 may be sealed when blowout conditions are experienced at the wellhead.

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

Claims (12)

  1. Blowout-Preventer-System (40), mit:
    einem Körper (56), der eine Bohrung (25) umgibt, die dazu ausgelegt ist, einen Fluidfluss zwischen einem Bohrlochkopf und einem Bohr-Riser zu ermöglichen;
    einer ersten Backe (50), die an ein erstes Ende (64) des Körpers (56) angrenzend angeordnet ist, wobei die erste Backe (50) mit einem ersten Aktor (127) gekoppelt ist;
    einer zweiten Backe (52), die an ein dem ersten Ende (64) des Körpers (56) gegenüberliegendes zweites Ende (65) angrenzend angeordnet ist, wobei die zweite Backe (52) mit einem zweiten Aktor (129) gekoppelt ist;
    einer Steuerung (46), die kommunikativ mit dem ersten Aktor (127) und dem zweiten Aktor (129) gekoppelt ist,
    wobei die Steuerung (46) ausgelegt ist, den ersten Aktor (127) dahingehend zu betätigen, die erste Backe (50) zu einem in der Bohrung (25) angeordneten Rohrstrang (24) hin zu lenken, so dass die erste Backe (50) den Rohrstrang (24) mit einem ersten Scherabschnitt (68) der zweiten Backe ausrichtet, wenn die erste Backe (50) sich in einer betätigten Stellung befindet, und wobei die Steuerung (46) ausgelegt ist, den zweiten Aktor (129), nach dem Betätigen des ersten Aktors (127), dahingehend zu betätigen, die zweite Backe (52) zum Rohrstrang hin (24) zu lenken, so dass die erste Backe (50) und die zweite Backe (52) den Rohrstrang (24) komplett durchtrennen, um die Bohrung (25) zu verschließen;
    und gekennzeichnet durch
    ein Folgeventil (120), das dazu ausgelegt ist, Hydraulikfluid (124) zum ersten Aktor (127) hin zu lenken, und dazu ausgelegt ist, einen Fluss von Hydraulikfluid (124) zum zweiten Aktor (129) hin zu blockieren, wenn ein erster Druck des Hydraulikfluids im ersten Aktor unter einem ersten Schwellendruck liegt.
  2. Blowout-Prevention-System (40) nach Anspruch 1, wobei der erste Schwellendruck einem zweiten Druck des Hydraulikfluids (124) im ersten Aktor (127) entspricht, wenn der erste Aktor (127) sich in der betätigten Stellung befindet.
  3. Blowout-Prevention-System (40) nach Anspruch 1, mit einem entsperrbaren Rückschlagventil (172), das dazu ausgelegt ist, das Hydraulikfluid (124) aus dem Folgeventil (120) zum zweiten Aktor (129) hin zu lenken, und dazu ausgelegt ist, das Hydraulikfluid daran zu hindern, vom zweiten Aktor (129) zum Folgeventil (120) hin zu strömen, wenn ein dritter Druck des Hydraulikfluids (124) im ersten Aktor (127) dem ersten Schwellendruck entspricht oder diesen überschreitet.
  4. Blowout-Prevention-System (40) nach Anspruch 3, wobei das entsperrbare Rückschlagventil (172) dazu ausgelegt ist, das Hydraulikfluid (124) vom zweiten Aktor (129) zum Folgeventil (120) hin zu lenken, wenn ein vierter Druck des Hydraulikfluids (124) im zweiten Aktor (129) einen zweiten Schwellendruck erreicht.
  5. Blowout-Prevention-System (40) nach Anspruch 1, mit einer Pumpe (125), die dazu ausgelegt ist, das Hydraulikfluid (124) durch das Folgeventil (120) zu treiben.
  6. Blowout-Prevention-System (40) nach Anspruch 1, mit einem Sensor (47), der dazu ausgelegt ist, eine einen Druck eines Fluids am Bohrlochkopf betreffende Rückmeldung an die Steuerung (46) zu senden, wobei die Steuerung (46) dazu ausgelegt ist, die Rückmeldung mit einem Schwellenwert zu vergleichen.
  7. Blowout-Prevention-System (40) nach Anspruch 6, wobei die Steuerung (46) dazu ausgelegt ist, einen oder beide des ersten und zweiten Aktors (127, 129) nur dann zu betätigen, wenn die Rückmeldung dem Schwellenwert entspricht oder diesen überschreitet.
  8. Blowout-Prevention-System (40) nach Anspruch 1, wobei die erste Backe (50) einen zweiten Scherabschnitt (66) mit linearer Geometrie umfasst, und der erste Scherabschnitt (68) der zweiten Backe (52) eine gezackte Geometrie umfasst.
  9. Verfahren, das umfasst:
    Betätigen einer ersten Backe eines Blowout-Preventers (40) zu einem in einer Bohrung (25) des Blowout-Preventers angeordneten Rohrstrang (24) hin, wobei die erste Backe (50) an einer ersten Seite der Bohrung angeordnet ist;
    Ausrichten des Rohrstrangs (24) mit einem ersten Scherabschnitt (68) einer an einer der ersten Seite gegenüberliegenden zweiten Seite der Bohrung (25) angeordneten zweiten Backe (52); und
    Betätigen der zweiten Backe zum Rohrstrang (24) und zur ersten Backe (50) hin, so dass die erste Backe (50) und die zweite Backe (52) den Rohrstrang (24) durchtrennen, um die Bohrung (25) zu verschließen, und
    dadurch gekennzeichnet, dass
    das Betätigen der ersten Backe (50) des Blowout-Preventers (40) zu einem in der Bohrung (25) des Bohr-Risers angeordneten Rohrstrang (24) hin umfasst, Hydraulikfluid (124) durch ein Folgeventil (120) hindurch und zu einem mit der ersten Backe (50) gekoppelten ersten Aktor (127) hin zu lenken, und umfasst, das Hydraulikfluid (124) daran zu hindern, zu einem mit der zweiten Backe (52) gekoppelten zweiten Aktor (129) hin zu strömen, wenn ein Druck des Hydraulikfluids (124) im ersten Aktor (127) unter einem Schwellendruck liegt.
  10. Verfahren nach Anspruch 9, wobei das Betätigen der zweiten Backe (52) zum Rohrstrang (24) und zur ersten Backe (50) hin, so dass die erste Backe (50) und die zweite Backe (52) den Rohrstrang (24) komplett durchtrennen, um die Bohrung (25) zu verschließen, umfasst, das Hydraulikfluid (124) durch das Folgeventil (120) hindurch zum mit der zweiten Backe (52) gekoppelten zweiten Aktor (129) hin zu lenken, wenn der Druck des Hydraulikfluids (124) im ersten Aktor (127) dem Schwellendruck entspricht oder diesen überschreitet.
  11. Verfahren nach Anspruch 9, wobei das Ausrichten des Rohrstrangs (24) mit dem ersten Scherabschnitt (68) der an der der ersten Seite gegenüberliegenden zweiten Seite der Bohrung (25) angeordneten zweiten Backe (52) umfasst, den Rohrstrang (24) entlang eines Innendurchmessers (76) der Bohrung (25) zu führen, so dass der Rohrstrang (24) in Bezug auf eine Längsachse mit dem ersten Scherabschnitt (68) und einem zweiten Scherabschnitt (66) der ersten Backe (50) ausgerichtet ist.
  12. System, mit:
    einer sich zwischen einem Bohrlochkopf (18) und einem Bohr-Riser (22) erstreckenden Bohrung (25);
    einem in der Bohrung (25) angeordneten Rohrstrang (24), der dazu ausgelegt ist, ein Fluid zwischen dem Bohrlochkopf (18) und dem Bohr-Riser (22) zu lenken; und
    einem Blowout-Prevention-System (40) gemäß einem der Ansprüche 1 bis 8.
EP15307172.5A 2015-12-30 2015-12-30 Schneidsequenz für eine preventergarnitur Not-in-force EP3187681B1 (de)

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EP15307172.5A EP3187681B1 (de) 2015-12-30 2015-12-30 Schneidsequenz für eine preventergarnitur
US15/392,992 US20170191337A1 (en) 2015-12-30 2016-12-28 Shearing sequence for a blowout preventer

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EP15307172.5A EP3187681B1 (de) 2015-12-30 2015-12-30 Schneidsequenz für eine preventergarnitur

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