EP2834442A1 - Appareil à pivot rotatif et animé d'un mouvement de va-et-vient et procédé - Google Patents

Appareil à pivot rotatif et animé d'un mouvement de va-et-vient et procédé

Info

Publication number
EP2834442A1
EP2834442A1 EP13772186.6A EP13772186A EP2834442A1 EP 2834442 A1 EP2834442 A1 EP 2834442A1 EP 13772186 A EP13772186 A EP 13772186A EP 2834442 A1 EP2834442 A1 EP 2834442A1
Authority
EP
European Patent Office
Prior art keywords
mandrel
sleeve
seal
sealing
annular
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.)
Withdrawn
Application number
EP13772186.6A
Other languages
German (de)
English (en)
Other versions
EP2834442A4 (fr
Inventor
Kip Robichaux
Terry Robichaux
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.)
Mako Rentals Inc
Original Assignee
Mako Rentals Inc
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 Mako Rentals Inc filed Critical Mako Rentals Inc
Publication of EP2834442A1 publication Critical patent/EP2834442A1/fr
Publication of EP2834442A4 publication Critical patent/EP2834442A4/fr
Withdrawn legal-status Critical Current

Links

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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/02—Couplings; joints
    • E21B17/04—Couplings; joints between rod or the like and bit or between rod and rod or the like
    • E21B17/05—Swivel joints
    • 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
    • E21B17/02—Couplings; joints
    • E21B17/04—Couplings; joints between rod or the like and bit or between rod and rod or the like
    • E21B17/042—Threaded
    • 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
    • E21B17/10—Wear protectors; Centralising devices, e.g. stabilisers
    • E21B17/1057—Centralising devices with rollers or with a relatively rotating sleeve
    • E21B17/1064—Pipes or rods with a relatively rotating sleeve
    • 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
    • E21B19/16—Connecting or disconnecting pipe couplings or joints
    • 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
    • E21B33/035—Well heads; Setting-up thereof specially adapted for underwater installations
    • E21B33/038—Connectors used on well heads, e.g. for connecting blow-out preventer and riser
    • 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
    • E21B33/08—Wipers; Oil savers
    • E21B33/085—Rotatable packing means, e.g. rotating blow-out preventers

Definitions

  • the sealing system between the sleeve or housing and the mandrel has a substantially equal pressure ratings for pressures tending to push fluid from the exterior of the sleeve or housing to the interior space between the sleeve or housing and the mandrel and pressures tending to push fluid from the interior space between the sleeve or housing and the mandrel to the exterior of the sleeve or housing.
  • a swivel having a sleeve or housing and mandrel having at least one flange, catch, or upset to restrict longitudinal movement of the sleeve or housing relative to the annular blow out preventer.
  • a plurality of flanges, catches, or upsets are used.
  • the plurality of flanges, catches, or upsets are longitudinally spaced apart with respect to the sleeve or housing.
  • the swivel tool can be closed on by the annular blowout preventer ("annular BOP").
  • annular BOP is located immediately above the ram BOP which ram BOP is located immediately above the sea floor and mounted on the well head.
  • the mandrel of the rotating and reciprocating tool supports the full weight, torque, and pressures of the entire string located below the mandrel.
  • the drill or well string is intermittently stroked longitudinally during downhole operations, such as in a hydraulic fracturing job.
  • the rotational speed is reduced during the time periods that reciprocation is not being performed. In one embodiment the rotational speed is reduced from about 60 revolutions per minute to about 30 revolutions per minute when reciprocation is not being performed.
  • one or more brushes and/or scrapers are used in the method and apparatus.
  • the outer sealing diameter of the tool sleeve can be 9 3/4 inches (24.77 centimeters) and the outer diameter of the tool mandrel can be 7 inches (17.78 centimeters) providing an annular cross sectional area of 9 3/4 inches (24.77 centimeters) OD and 7 inches ID (17.78 centimeters).
  • Any differential pressure will act on this annular area producing a net force in the direction of the pressure gradient equal to the pressure differential times the effective cross sectional area.
  • This net force produces an upward force which can overcome the frictional force applied by the annular BOP closed on the tool's sleeve causing the sleeve to be pushed in the direction of the net force (or slide through the sealing element of the annular BOP).
  • catches can be placed on the sleeve which prevent the sleeve from being pushed through the annular BOP seal.
  • the following differential pressures e.g., difference between the pressures above and below the annular BOP seal
  • the catches can be used to prevent the sleeve from being axially pushed out of the annular BOP (even when the annular BOP seal has been closed) - - in pounds per square inch: 500, 750, 1000, 1250, 1500, 1750, 2000, 2250, 2500, 2750, 3000, 3250, 3,500, 3750, 4,000, 4,250, 4,500, 4,750, 5,000, 10,000 or greater (3,450, 5,170, 6,900, 8,620, 10,340, 12,070, 13,790, 15,510, 17,240, 18,960, 20,690, 22,410, 24,130, 25,860, 27,700, 29,550, 31,400, 33,240, 35,090, 36,940, 73,880 kilopascals).
  • ranges between any two of the above specified pressures are contemplated. Additionally, ranges above any one of the above specified pressures are contemplated. Additionally, ranges below any one of the above specified pressures are contemplated. These differential pressures can be higher below the annular BOP seal or above the annular BOP seal.
  • a downhole/underwater locking/unlocking system is needed to lock the sleeve in a longitudinal position relative to the mandrel (or at least restricting the available relative longitudinal movement of the sleeve and mandrel to a satisfactory amount compared to the longitudinal length of the sleeve's effective sealing area).
  • an underwater locking/unlocking system is needed which can lock and/or unlock the sleeve and mandrel a plurality of times while the sleeve and mandrel are underwater.
  • a system wherein the underwater position of the longitudinal length of the sleeve's sealing area (e.g., the nominal length between the catches) can be determined with enough accuracy to allow positioning of the sleeve's effective sealing area in the annular BOP for closing on the sleeve's sealing area.
  • the underwater position of the sleeve can be determined even where the sleeve has been moved outside of the annular BOP.
  • a quick lock/quick unlock system can detachably connect the sleeve and mandrel.
  • a quick lock/quick unlock system on the rotating and reciprocating tool can be provided allowing the operator to lock the sleeve relative to the mandrel when the rotating and reciprocating tool is downhole/underwater. Because of the relatively large amount of possible stroke of the sleeve relative to the mandrel (i.e., different possible relative longitudinal positions), knowing the relative position of the sleeve with respect to the mandrel can be important. This is especially true at the time the annular BOP is closed on the sleeve.
  • the locking position is important for determining relative longitudinal position of the sleeve along the mandrel (and therefore the true underwater depth of the sleeve) so that the sleeve can be easily located in the annular BOP and the annular BOP closed /sealed on the sleeve.
  • the sleeve can be locked relative to the mandrel by a quick lock/quick unlock system.
  • the quick lock/quick unlock system can, relative to the mandrel, lock the sleeve in a longitudinal direction.
  • the sleeve can be locked in a longitudinal direction with the quick lock/quick unlock system, but the sleeve can rotate relative to the mandrel during the time it is locked in a longitudinal direction.
  • the quick lock/quick unlock system can simultaneously lock the sleeve relative to the mandrel, in both a longitudinal direction and rotationally.
  • the quick lock/quick unlock system can, relative to the mandrel, lock the sleeve rotationally, but at the same time allow the sleeve to move longitudinally.
  • the mandrel is comprised of a plurality of joints of piping/tubing which are threadably connected to each other.
  • the sleeve/housing can remain stationary while a portion of the mandrel is moved longitudinally or stroked relative to the sleeve.
  • a mandrel formed by such combination of joints of box/female by box/female end joints alternatively connected by pin/male by pin/male end joints of tubular can have spaced apart thin walled portions that are easily shearable by ram type blow out preventers.
  • the spacing apart of the thin walled portions can be on opposing sides of the pin/male by pin/male joints of mandrel.
  • the alternative box/female by box/female with pin/male by pin/male can have length spacings such that at any one point at least one ram of the plurality of stacked ram blow out preventers would attempt to shear a thin walled portion of the mandrel thereby ensuring continuous shearability of the mandrel.
  • the mandrel can be comprised of a plurality of double box/female by box/female end joints connected by double pin/male by pin/male end joints, wherein the double pin end joints are spaced apart at least 4, 5, 6, 7, 8, 9, 10, 12, 14, 16, 18, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 84, 85, 90, 95, and 100 feet.
  • the double pin end joints can be spaced between any two of the above specified lengths.
  • first seal unit moves across recessed area of mandrel but second seal unit maintains seal between sleeve and mandrel;
  • the longitudinal length of one or more recessed areas in the mandrel can be between 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 14, 16, 18, 20, 22, 24, 26, 28, 30, 32, 34, 36, 40, 45, 50 inches; and the spacing between the spaced apart seal units in the sleeve/housing.
  • One embodiment includes the insert with an annular recess for at least partially containing an internal sealing unit.
  • step "(2)" causing relative longitudinal movement between the sleeve and the mandrel.
  • step "c) after step "b", causing relative longitudinal movement between the sleeve and the mandrel;
  • step "a" the sleeve is longitudinally locked relative to the mandrel.
  • step "c” operations are performed in the wellbore. In one embodiment, during step “(3)” operations are performed in the wellbore. In one embodiment, during step “c” the tool is fluidly connected to a string having a bore and fluid is pumped through the choke and/or kill of the BOP to the wellbore and returned through at least part of the string' s bore up to the rig through a right angle swivel fluid diverter.
  • step "(3)" the tool is fluidly connected to a string having a bore and fluid is pumped through the choke and/or kill of the BOP to the wellbore and returned through at least part of the string's bore up to the rig through a right angle swivel fluid diverter.
  • the mandrel can freely rotate relative to the sleeve.
  • the mandrel can freely rotate relative to the sleeve.
  • Figure 1 is a schematic diagram showing a deep water drilling rig with riser and annular blowout preventer.
  • Figure 2 is another schematic diagram of a deep water drilling rig showing a rotating and reciprocating swivel detachably connected to an annular blowout preventer, along with a ram blow out preventer mounted in the Christmas tree below the annular blowout preventer.
  • Figure 3 is a perspective view of a conventionally available annular blowout preventer.
  • Figure 5 is a schematic view of one embodiment of a mandrel which includes a plurality of double box end joints connected by a plurality of mandrel subs.
  • Figure 6 is a perspective view of one embodiment of a rotating and reciprocal swivel with sectional mandrel having joints incorporating pin end tip sealing configuration.
  • Figure 7 is a side view of the rotating and reciprocal swivel of Figure 6 where the sleeve is located in its lowermost position, and the center of gravity of the swivel is identified.
  • Figures 8A, 8B, and 8C are perspective views of the rotating and reciprocal swivel of Figure 6 where respectively the sleeve is located in its lowermost, mid stroke, and upper most positions.
  • Figure 9 is a side view of the sectional mandrel having joints incorporating pin end tip sealing configuration of Figure 6.
  • Figure 10 is a sectional view of the sectional mandrel having joints incorporating pin end tip sealing configuration of Figure 6.
  • Figure 11A is a sectional view of the mandrel of Figure 6 showing one of the connection joints incorporating pin end tip sealing configuration.
  • Figure 11B is an enlarged sectional view of the joint of Figure 11 A.
  • Figure 17 is a sectional view of the mandrel of Figure 6 showing the lowermost connection joint incorporating pin end tip sealing configuration.
  • Figure 19 is an enlarged view of a circumferential reces s for receiving the pin end tip sealing configuration of one embodiment.
  • Figure 20 is an enlarged view of an end shoulder for limiting movement of the slidable sealing block of one embodiment.
  • Figure 22 is an end view of the double female end connection joint of Figure 21.
  • Figure 28 is an enlarged view of one of the pin ends of the mandrel joint of Figure
  • Figure 30 is a left end view of the mandrel joint of Figure.
  • Figure 34 is an enlarged view of one of the pin ends of the mandrel joint of Figure 33, having the seal of one embodiment.
  • Figure 38 shows a pin/male by pin/male mandrel joint with recess in its exterior sealing surface being connecting to two female tubulars.
  • Figure 43 is a side view of a sleeve of the mandrel shown in Figure 6.
  • Figure 45 is an enlarged sectional view of an end for the sleeve shown in Figures
  • the diverter D can use a diverter line DL to communicate drilling fluid or mud from the riser R to a choke manifold CM, shale shaker SS or other drilling fluid or drilling mud receiving device.
  • a diverter line DL can be used above the diverter D to communicate with a mud pit MP.
  • a conventional flexible choke line CL can be configured to communicate with choke manifold CM.
  • the drilling fluid or mud can flow from the choke manifold CM to a mud-gas buster or separator MB and a flare line (not shown). The drilling fluid or mud can then be discharged to a shale shaker SS, and mud pits MP.
  • a booster line BL can be used in addition to a choke line CL and kill line KL.
  • Annular blowout preventer 70 is positioned at the bottom of riser 80 and above stack 75.
  • a well bore 40 extends downwardly from wellhead 88 and into seabed 87. Although shown in Figure 2, in many of the figures the lower completion or drill string 85 has been omitted for purposes of clarity.
  • mandrel 110 may be limited to the height of the derrick of the rig because the mandrel 110 will preferably be made up at the shop, as making it up in the field will likely scratch/damage the sealing areas of mandrel 110.
  • Figure 9 is a side view of made up mandrel 110 having joints incorporating pin end tip sealing configuration of Figure 6.
  • Figure 10 is a sectional view of mandrel 110 having joints incorporating an inner diameter sealing as will be described below.
  • Mandrel 110 can be comprised of joints 500, 600, 700, 800, 900, 1000, and 1100. Depending on the desired stroke length of mandrel 110, additional joints of mandrel can be used.
  • Figure 12 is a sectional view of mandrel 110 showing a joints 600,700,800 of mandrel 110 having two pin ends (joint 700) and two connecting joints (600,800) incorporating box/male by box/male connections, and including sealing insert 1500 having an annular recess 1540 for seal 750.
  • Figure 11A is a sectional view of a joint of mandrel 110 which incorporates the inner diameter sealing configuration using seal 750 which is contained in mating annular recesses 728 (of joint 700) and 1540 (of joint 600).
  • Figure 11B is an enlarged sectional view of the joint of Figure 11 A.
  • Figure 13 is an end view of a seal 750 or 760 which can be used mating annular recesses 728 (of mandrel joint 700) and 1540 (of mandrel joint 600).
  • Figure 14 is a sectional view of the seal 750.
  • Figure 15 is an enlarged sectional view of the seal 750.
  • First seal 750 can comprise first end 752, widened area of first seal 753, second end of first seal 755, tapered area of first seal 756, and vertical area of first seal 757. Tapered areas 756,756' can be used to assist second end 755 of seal 750 to enter recess 1540 of insert 1500 when joint 700 is being threaded into joint 600.
  • Seal 750 can have inner sealing diameter 770 and outer sealing diameter 774 (which are defined by vertical walls
  • Figure 16 is a sectional view of mandrel 110 showing the uppermost connection joint (joint 600 threaded onto joint 500) incorporating pin end tip sealing configuration.
  • Seal 550 can be of similar construction to seal 750 shown in Figure 13.
  • Shoulder 570 can limit stroke length of mandrel 110 relative to sleeve 300 when catch 326 contacts shoulder 570.
  • Figure 18 is a sectional view of one box/female by box/female type joint 600 of mandrel 100 showing a double female end connection joint for receiving the pin end tip sealing configuration of one embodiment.
  • Figure 19 is an enlarged view of a circumferential recess 1540' for receiving the seal (e.g., seal 750 shown in Figures 11 and 12).
  • Figure 20 is an enlarged view (Detail A) of an end shoulder 660 for limiting movement of the slidable sealing block 1500 of one embodiment.
  • FIG 23 is a sectional side view of a slidable sealing block 1500.
  • Figure 24 is an end view of the slidable sealing block 1500.
  • sealing block 1500 can include annular recess 1540, which itself can include tapered walls 1546, and vertical section 1544. Tapered walls 1546 can be constructed to match/cooperate with the tapered areas of the seal (such as tapered area 756 of seal 750).
  • Annular recess 1540 can have nominal diameter 1550, with outer diameter 1552 and inner diameter 1554 created by vertical walls 1544.
  • Insert 1500 can include an axial passage 1510 having at least one transitional portion 1534 to transition from the larger diameter axial passages of the box/female by box/female joints (e.g., 600, 800, 1000 etc.) to the smaller diameter axial passes of the pin/male by pin/male joints (e.g., 700, 900, etc.).
  • box/female joints e.g. 600, 800, 1000 etc.
  • pin/male joints e.g., 700, 900, etc.
  • Figure 25 is a sectional view of a joint 700 of mandrel 110 having two male/pin ends 720,730 and two connecting joints incorporating pin end tip sealing configuration (annular recesses 728 and 738 respectively holding first seal 750 and second seal 760).
  • Figure 26 is an enlarged view of the threads 722 of one end 720 of double male end mandrel joint 700.
  • Figure 27 is a sectional view of the uppermost mandrel joint 500 of mandrel 110, with joint 500 having a pin/male end 530 incorporating seal 550 (which can be of the same configuration as seal 750 described above).
  • Joint 500 can include shoulder 533 for limiting longitudinal movement between sleeve 300 and mandrel 110.
  • Figure 28 is an enlarged view of one of the pin end 530.
  • Annular recess 538 can include enlarged area 539 for holding in place seal 550.
  • Second end 520 can include a box/female connection which can attach to additional non-mandrel string joints.
  • Figure 29 is a sectional view of the lowermost mandrel joint 1100 of mandrel 110, with the joint having a pin end (at end 1120) sealing configuration (seal 1150 which can be of the same construction as seal 750 described above).
  • Figure 30 is left end view of joint 1100.
  • Figure 31 is a right end view of joint 1100.
  • Figure 32 is an enlarged view of the area showing a pressure relief area 1400, for relaxing/relieving pressure between the interstitial space of the interior of the sleeve 300 and the exterior of the mandrel 110 (when sleeve 300 is in its lowermost and quick locked condition).
  • Figure 33 is a sectional view of the lowermost mandrel joint 1100.
  • Seal 1150 on end 1120 and placed in recess 1128 can be used to seal between joint 1100 and the connecting box/female by box/female joint 1000.
  • Figure 34 is an enlarged view of one of ends 1120 of joint 1100.
  • Figures 35 through 37 show three sequence steps making a connection between a box/female end (end 630 of mandrel joint 600 being made up to end 720 of mandrel joint 700).
  • the mating shoulders can have a tapered portion with a taper at about 1, 2, 3, 4, 5, 6, 6.25, 7, 8, 9, 10, 12, 13, 14, 15, and 20 degrees from a line perpendicular to the longitudinal centerline of a joint.
  • the tapers can be within a range of between about any two of the specified degrees. Mating tapers can have equal magnitude but opposite tapers or slopes.
  • Figure 38 shows joints 600, 700, and 800 attached with exterior sealing surfaces
  • Recess 706 can include upper transition area 740 and lower transition area 746.
  • Transition areas can include softer transition inserts 742 and 748 as described below.
  • inserts 1500, 1500', 1500", and 1500" ' are shown interior seals 750 and 760 have been omitted for clarity (but are intended to be used as shown in other embodiments for with interior sealing).
  • Figure 45 is an enlarged sectional view (Detail A) of an end of sleeve 300.
  • the wall thickness 604, 804, 1004, etc. of box end joints 600, 800, 1000, etc. will be such that the walls can be sheared by one of the rams 2010, 2020, 2030, and/or 2040 of plurality of stacked ram blow out preventers 2000.
  • Figure 4 is a sectional view cut through the annular 70 and ram 2040 blow out preventers with the annular seal 71 closed on the sleeve 300 of the rotating and reciprocating swivel 100.
  • Mandrel 110 which comprises mandrel joints 600, 800, 1000 connected together by double pin subs 700, 900 are also schematically shown in Figure 4.
  • FIG. 4 Schematically shown in Figure 4 is the spacing L 2 between subs 700 and 800 is such that at any one point in time only one of subs 700 or 900 can be aligned with a ram of a ram blow out preventer 2000.
  • Plurality of stacked ram blow out preventers 2000 can include rams 2010, 2020, 2030, and 2040.
  • Distance 2050 is between rams 2010 and 2020.
  • Distance 2052 is between rams 2010 and 2030.
  • Distance 2054 is between rams 2030 and 2040.
  • Distance 2056 is between rams 2020 and 2040.
  • Distance 2058 is between rams 2020 and 2030.
  • none of the distances 2050, 2052, 2054, 2056, and/or 2058 can fall within the range of:
  • any double box end joint 600, 800, 1000 etc. is greater than at least about 4 feet. In other embodiments the length is at least greater than about 5, 6, 7, 8, 9, 10, 12, 14, 15, 16, 18, 20, 25, 30, 35, and 40 feet. In other embodiments the length is between any two of the above specified lengths.
  • the wall thickness 604, 804, 1004, etc. of double box end joints 600, 800, 100, etc. will be such that the walls can be sheared by one of the rams 2010, 2020, 2030, and/or 2040 of ram blow out preventer 2000.
  • Swivel 100 can be comprised of mandrel 110 and sleeve or housing 300.
  • Sleeve or housing 300 can be rotatably, strokably/reciprocably, and/or sealably connected to mandrel 110. Accordingly, when mandrel 110 is rotated and/or reciprocated sleeve or housing 300 can remain stationary to an observer insofar as rotation and/or reciprocation is concerned.
  • Sleeve or housing 300 can fit over mandrel 110 and can be rotatably, reciprocably, and sealably connected to mandrel 110.
  • Sleeve or housing 300 can be sealingly connected to mandrel 110 by a one or more seals (e.g., packing units 370 and 380), preferably spaced apart and located on opposed longitudinal ends of sleeve or housing 300.
  • the seals can seal the gap 315 between the interior 310 of sleeve or housing 300 and the exterior of mandrel 110.
  • Sleeve or housing 300 can be reciprocally connected to mandrel 110 through the geometry of mandrel 110 which can allow sleeve or housing 300 to slide relative to mandrel 110 in a longitudinal direction (such as by having a longitudinally extending distance H T of the exterior surface of mandrel 110 a substantially constant diameter).
  • annular seal unit 71 can close around sleeve or housing 300 forming a seal between sleeve or housing 300 and annular seal unit 71.
  • the stroke of swivel 100 can be the difference between height H T of mandrel 110 and length 350 of sleeve or housing 300.
  • Figures 7 and 8 show a sectional view through the sleeve 300 and mandrel 110.
  • sealing units 370 and 380 can be two way seals.
  • One advantage of using two sets of sealing units 370 and 380 which each seal in opposite longitudinal directions is that the sleeve 300 and mandrel 110, even where one or more of the double pin subs (e.g., 700, 900, etc.) with its recessed portion (e.g., 706, 906, etc.) is passing through the sealing unit, the spaced apart sealing unit can still seal against fluid flow.
  • This backup sealing ability assists in maintaining sealing during vertical movement of mandrel 110 relative to sleeve 300.
  • sleeve 300 includes spaced apart sealing units 370,380 located respectively under catches 326,328.
  • arrows 3000,3001,3002,3003, 3004, and 3005 schematically indicate downward movement of mandrel 110 relative to sleeve 300. Additionally, arrows 3010,3011,3012,3013, 3014, and 3015 schematically indicate upward movement of mandrel 110 relative to sleeve 300.
  • the height L m of mandrel 110 compared to the overall length L s 350 of sleeve or housing 300 can be configured to allow sleeve or housing 300 to stroke/reciprocate (e.g., slide up and down) relative to mandrel 110.
  • Figures 46 through 51 are schematic diagrams illustrating stroking/reciprocation and/or rotation between sleeve or housing 300 along mandrel 110 (allowing reciprocation and/or rotation between drill or work string 85 when annular seal 71 of annular blow out preventer 70 is closed and sealed on sleeve 300, and drill or work string 85, thereby sealing the bore hole from above - with the sleeve being closed in annular blow out preventer being shown in Figure 2).
  • 3004 and 3005 schematically indicate a downward stroke of mandrel 110 relative to sleeve 300 in the direction of arrow 3000.
  • Figures 46 through 51 in reverse order of Figure 51 down to Figure 46
  • arrows 3010, 3011, 3012, 3013, 3014, and 3015 schematically indicate an upward stroke of mandrel 110 relative to sleeve 300.
  • packing units 370 and 380 maintain a seal between sleeve 300 and mandrel 110, while annular seal 71 maintains a seal on sleeve 300 thereby sealing wellbore 40.
  • arrows 3000,3001 schematically indicate that mandrel 110 is moving downward relative to sleeve or housing 300, where a double pin end sub 900 is located above the level of upper catch 326 (and upper packing unit 370) of sleeve 300.
  • upper packing unit 370 may not maintain a seal when double pin end sub 900 passes through (e.g., recessed area 906 causing a break in the sealing between packing unit 370 and sub 900 as shown in Figure 52B)
  • lower packing unit 380 in lower catch 328 maintains a seal between sleeve 300 and mandrel 110 (as shown in Figure 53A)
  • annular seal 71 of annular blow out preventer 70 maintains a seal on sleeve 300 thereby sealing wellbore 40.
  • arrow 3002 schematically indicates that mandrel 110 continues to stroke downwardly relative to sleeve or housing 300, where a double pin end sub 900 (and recess 906) is located between upper catch 321 (and upper packing unit 370) and lower catch 328 (and lower packing unit 380).
  • both packing units 370 and 380 maintain a seal between sleeve 300 and mandrel 110 (as shown in Figures 52A and 53A), while annular seal 71 maintains a seal on sleeve 300 thereby sealing wellbore 40.
  • arrow 3003 schematically indicates that mandrel 110 continues to stroke downwardly relative to sleeve or housing 300, where now a double pin end sub 900 is located at the level of lower catch 328 (and lower packing 380 unit) of sleeve 300.
  • packing unit 380 may not maintain a seal when recess 906 of double pin end sub 900 passes through (e.g., recessed area 906 causing a break in the sealing as shown in Figure 53B)
  • upper packing unit 370 maintains a seal between sleeve 300 and mandrel 110 (as shown in Figure 52A), while annular seal 71 maintains a seal on sleeve 300 thereby sealing wellbore 40.
  • both packing units 370 and 380 maintain a seal between sleeve 300 and mandrel 110 (as shown in Figures 52A and 53A), while annular seal 71 maintains a seal on sleeve 300 thereby sealing wellbore 40.
  • packing unit 370 may not maintain a seal when double pin end sub 700 passes through (e.g., recessed area 706 causing a break in the sealing as shown in Figure 52B)
  • packing unit 380 maintains a seal between sleeve 300 and mandrel 110 (as shown in Figure 53A), while annular seal 71 maintains a seal on sleeve 300 thereby sealing wellbore 40.
  • Figure 5 shows is a swivel tool 100 with mandrel 110 and sleeve 300.
  • Figure 5 is a schematic view of one embodiment of a mandrel 110 which includes a plurality of double box end joints (600, 800, 1000) connected by a plurality of double pin end subs (700, 900).
  • the overall stroking height H T of double box mandrel 110 can be equal to the sum of the lengths of the joints and subs making it up.
  • the overall height H T of mandrel 110 is equal to L j + L 2 + L 3 + L 4 + L 6 .
  • To change the overall height H T (to be either more or less) different numbers of mandrel joints 600, 800, 1000 can be used to make up mandrel 110.
  • Another way to change the overall height H T of mandrel 110 is to use mandrel joints 600, 800, 1000 of different lengths.
  • Double box end joint 600 can be of a length L l5 and can include longitudinal passage with a box connection at its upper end 620 along with box connection at its lower end 630.
  • Double box end joint 800 can be of a length L 2 , and can include longitudinal passage with a box connection at its upper end 820 along with box connection 850 at its lower end 830.
  • Double pin sub 700 can comprise upper end 720, lower end 730 along with longitudinal passage 710. Sub 700 can also include upper shoulder 723, lower shoulder
  • Recessed area 706 can be used for supporting mandrel 110 after joints 600, 800,
  • mandrel 110 has been connected to each other forming mandrel 110.
  • Supporting mandrel 110 using one of the recessed areas of the mandrel without gripping the sealing surfaces of joints 600,800,1000, etc. for supports prevents such surfaces from being scratched and/or damaged thus causing problems or failure of a seal between mandrel 110 and sleeve 300 (i.e., sealing with seal units 370 and/or 380).
  • supporting mandrel 110 using one of the recessed areas in the double pin subs, where such subs are damaged allows replacement of the subs 700, 900, etc., while protecting (and preventing the requirement to replace) the more expensive double box end mandrel joint pieces 600, 800, 1000, etc.
  • Box connection of lower end 630 for joint 600 can be threadably connected to upper end 710 of double pin sub 700.
  • Box connection of the upper end 820 of mandrel joint 800 can be threadably connected to lower end 730 of double pin sub 700.
  • Double pin sub 900 can comprise upper end 920, lower end 930 along with longitudinal passage 910. Sub 900 can also include upper shoulder 923, lower shoulder 933, and recessed area 906.
  • Box connection as the lower end 630 of joint 600 can be threadably connected to upper end 720 of double pin sub 700.
  • Box connection at the upper end 820 of mandrel joint 800 can be threadably connected to lower end 730 of double pin sub 700.
  • recessed areas 706, or 906 can be used for supporting made up mandrel 110 after joints 600, 800, 1000, etc. have been connected to each other forming mandrel 110.
  • Supporting mandrel 110 in the recessed areas 706,906 i.e., non-sealing areas
  • prevents such surfaces from being scratched and/or damaged thus causing problems or failure of a seal between mandrel 110 and sleeve 300 (i.e., sealing with seal units 370 and/or 380).
  • mandrel 110 of swivel tool 100 can be at least partially lengthened while being tripped downhole.
  • a method of determining the stroking length of a rotating and reciprocable swivel tool 100 at a drilling rig or platform having a floor comprising the steps of:
  • the steps "c” and “d” can be repeated until the final stroking length can be greater than about 100, 150, 200, 250, 300, 350, 400, 450, 500, 550, 600, 700, 800, 900, 1000, 1200, 1400, 1500, 1600, 1800, and 2000 feet, or any stroke lengths between any two of the specified stroke lengths.
  • a plurality of the mandrel joints include a recessed areas (e.g., 706, 906, etc.) in the exterior sealing surface, and during step "c" the one of these recessed areas are used to support the swivel tool in a substantially vertical direction.
  • the plurality of recessed areas can include soft material transition sections.
  • the upper portions of the recessed areas can be frustoconical.
  • the upper portions of the recessed areas can be tapered.
  • One embodiment comprises a method of making up the mandrel while on rig or platform.
  • swivel tool 100 can be used in well bore fracturing process.
  • "Hydraulic fracturing,” sometimes simply referred to as “fracturing,” is acommon stimulation treatment.
  • a treatment fluid for this purpose is sometimes referred to as a "fracturing fluid.”
  • the fracturing fluid is pumped at a high flow rate and high pressure down into the wellbore and out into the formation.
  • the pumping of the fracturing fluid is at a high flow rate and pressure that is much faster and higher than the fluid can escape through the permeability of the formation.
  • the high flow rate and pressure creates or enhances a fracture in the subterranean formation.
  • Creating a fracture means making a new fracture in the formation.
  • Enhancing a fracture means enlarging a pre-existing fracture in the formation.
  • frac pump For pumping in hydraulic fracturing, a "frac pump” is used, which is a high-pressure, high-volume pump.
  • a frac pump is a positive-displacement reciprocating pump.
  • These pumps generally are capable of pumping a wide range of fluid types, including corrosive fluids, abrasive fluids and slurries containing relatively large particulates, such as sand.
  • the fracturing fluid may be pumped down into the wellbore at high rates and pressures, for example, at a flow rate in excess of 100 barrels per minute (3,100 US gallons per minute) at a pressure in excess of 5,000 pounds per square inch (“psi").
  • the pump rate and pressure of the fracturing fluid may be even higher, for example, pressures in excess of 10,000 psi are not uncommon.
  • the fracturing fluid suddenly has a fluid flow path through the crack to flow more rapidly away from the wellbore.
  • the sudden increase in flow of fluid away from the well reduces the pressure in the well.
  • the creation or enhancement of a fracture in the formation is indicated by a sudden drop in fluid pressure, which can be observed at the well head.
  • the newly-created fracture will tend to close after the pumping of the fracturing fluid is stopped.
  • a material must be placed in the fracture to keep the fracture propped open.
  • This material is usually in the form of an insoluble particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture.
  • the particulate material holds the fracture open while still allowing fluid flow through the permeability of the particulate.
  • a particulate material used for this purpose is often referred to as a "proppant.”
  • the proppant When deposited in the fracture, the proppant forms a "proppant pack," and, while holding the fracture apart, provides conductive channels through which fluids may flow to the wellbore.
  • the particulate is typically selected based on two characteristics: size range and strength.
  • swivel tool 100 can be used in string 85 where the annular blow out 70 preventer is closed on sleeve 300.
  • the length of the mandrel 110 required to achieve the required stroke length for overall traversing of formation zones between mandrel 110 and sleeve 300 can be calculated.
  • a swivel tool 100 including a mandrel 110 that can be made up to a desired length while at the rig 10 to accommodate fracturing operations.
  • mandrel 110 can be configured to a predetermined length off site from the well 10 to be fractured to the length required to achieve the calculated stroke length required, and then mandrel 110 is transported to rig 10.
  • the mandrel 110 can be made up onsite at rig 10, during the tripping in process, to a predetermined selected stroke length for the well to be fractured to achieve the calculated required stroke length.
  • the actual stroke length of the mandrel 110 can include a 50% factor of safety for stroke length making the nominal stroke length of 1,500 feet. This factor of safety can be used to account for possible miscalculations while spacing out.
  • the swivel tool 100 with stroking mandrel 110 can be partially made up at a site remote from rig 10.
  • swivel tool 100 partially being made up includes the bottom latch sub 1100 and at least one stroking mandrel joint 1000 with the sleeve/housing 300 being slidably connected to this mandrel 110 and placed in a quick lock condition for transport.
  • mandrel 110 On the top of the mandrel 110 will be a pin by box elevator sub 160. In addition a plurality of mandrel joints are included (both box by box and pin by pin).
  • Below the swivel can be the bottom hole assembly for performing downhole fracturing operations.
  • the rotating and reciprocating swivel tool 100 can be lowered from the rig floor F into the riser 80.
  • the sleeve/housing 300 is lowered in a quick locked condition relative to mandrel 110.
  • the stroke length of the swivel tool 100 can be increased to a desired stroke length.
  • additional joints of mandrel 110 can be added to the mandrel 110 to obtain the desired stroke length between the sleeve/housing 300 and the mandrel 110.
  • the makeup of the swivel tool 100 is completed by attaching the limiting sub 500 (with limiting shoulder 570) to the top of made up mandrel 110 thereby creating the desired stroke length.
  • the swivel tool 100 is continued to be lowered by now adding joints of pipe (e.g., drill pipe) while lowering the entire string 85.
  • joints of pipe e.g., drill pipe
  • joints of piping/tubing/drill string can be added while the swivel tool 100 is being lowered to where the annular blow out preventer 70 (i.e., annular seal) is closed on the sleeve 300.
  • the swivel tool 100 is lowered until the sleeve/housing 300 has passed below the annular blow out preventer 70, and then the sealing element 71 of the annular blow out preventer 70 is at least partially closed on mandrel 110 before the swivel tool 100 is raised slowly until the top of the sleeve/housing 300 contacts the bottom of the sealing element 71 of the annular blow out preventer 70.
  • the string 85 (including mandrel 110) is lowered relative to the sleeve/housing 300 to longitudinally unlock the sleeve/housing 300 relative to the mandrel 110.
  • the zones of the formation can be isolated relative to the fracturing tool (by conventional methods) and fracturing pumping can commence.
  • Benefits of the swivel tool 100 include but are not limited to:
  • mandrel 110 can be raised relative to the sleeve/housing 300 until the sleeve/housing 300 enters a latched state at the upper portion of the stroke length of the mandrel 110.
  • the sealing element 71 of the annular blow out preventer 70 can be opened and the swivel tool 100 with attached string 85 tripped out of the hole 40.
  • box/female by box/female joints e.g., 600, 800, 1000, etc.
  • mandrel 110 of tubular/piping which preferably are about 30 feet in overall length.
  • Pin/male by pin/male mandrel tubular/piping tool joints e.g., 700, 900, etc.
  • tubular/piping which preferably are about 30 inches in overall length, and include a recessed elevator groove e.g., 706, 906, etc.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (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)
  • Mechanical Engineering (AREA)
  • Earth Drilling (AREA)

Abstract

La présente invention concerne un procédé et un appareil dans lequel un pivot rotatif et animé d'un mouvement de va-et-vient présentant une course réglable et pouvant être cisaillé par des obturateurs à mâchoires peut être raccordé de manière amovible à un obturateur à mâchoires annulaire, séparant ainsi le trou de forage inférieur de la colonne montante. Dans un mode de réalisation, le mandrin du pivot est composé de joints polygonaux doubles et utilise des sous-ensembles à extrémité de tige doubles pour raccorder une pluralité de joints de mandrin les uns aux autres.
EP13772186.6A 2012-04-04 2013-04-04 Appareil à pivot rotatif et animé d'un mouvement de va-et-vient et procédé Withdrawn EP2834442A4 (fr)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US201261620207P 2012-04-04 2012-04-04
US13/793,260 US20130264065A1 (en) 2012-04-04 2013-03-11 Rotating and reciprocating swivel apparatus and method
PCT/US2013/035312 WO2013152219A1 (fr) 2012-04-04 2013-04-04 Appareil à pivot rotatif et animé d'un mouvement de va-et-vient et procédé

Publications (2)

Publication Number Publication Date
EP2834442A1 true EP2834442A1 (fr) 2015-02-11
EP2834442A4 EP2834442A4 (fr) 2016-06-15

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EP13772186.6A Withdrawn EP2834442A4 (fr) 2012-04-04 2013-04-04 Appareil à pivot rotatif et animé d'un mouvement de va-et-vient et procédé

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Country Link
US (1) US20130264065A1 (fr)
EP (1) EP2834442A4 (fr)
AU (1) AU2013243394A1 (fr)
BR (1) BR112014024626A2 (fr)
MX (1) MX2014012000A (fr)
WO (1) WO2013152219A1 (fr)

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US8579033B1 (en) * 2006-05-08 2013-11-12 Mako Rentals, Inc. Rotating and reciprocating swivel apparatus and method with threaded end caps
US9033052B2 (en) * 2010-09-20 2015-05-19 Mako Rentals, Inc. Rotating and reciprocating swivel apparatus and method
US20190040715A1 (en) * 2017-08-04 2019-02-07 Baker Hughes, A Ge Company, Llc Multi-stage Treatment System with Work String Mounted Operated Valves Electrically Supplied from a Wellhead
US12071828B2 (en) * 2019-08-12 2024-08-27 Pivotree Pty Ltd Subsea tree including a fluid swivel
CN110876606B (zh) * 2019-12-05 2022-04-12 重庆金山医疗技术研究院有限公司 一种可弯曲且转动灵活的挠性管及内窥镜
CN111894497B (zh) * 2020-07-27 2024-10-11 中国海洋石油集团有限公司 分流器壳体保护装置
CN118815397B (zh) * 2024-07-31 2025-03-04 中煤科工集团重庆研究院有限公司 一种动力头结构

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US8579033B1 (en) * 2006-05-08 2013-11-12 Mako Rentals, Inc. Rotating and reciprocating swivel apparatus and method with threaded end caps
US8567507B2 (en) * 2007-08-06 2013-10-29 Mako Rentals, Inc. Rotating and reciprocating swivel apparatus and method

Also Published As

Publication number Publication date
AU2013243394A1 (en) 2014-10-09
US20130264065A1 (en) 2013-10-10
WO2013152219A1 (fr) 2013-10-10
MX2014012000A (es) 2015-05-08
EP2834442A4 (fr) 2016-06-15
BR112014024626A2 (pt) 2017-08-08

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