US20140008078A1 - Slip joint for downhole tubing - Google Patents

Slip joint for downhole tubing Download PDF

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Publication number
US20140008078A1
US20140008078A1 US13/938,076 US201313938076A US2014008078A1 US 20140008078 A1 US20140008078 A1 US 20140008078A1 US 201313938076 A US201313938076 A US 201313938076A US 2014008078 A1 US2014008078 A1 US 2014008078A1
Authority
US
United States
Prior art keywords
movable
tubing string
downhole
tubing
stationary
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.)
Abandoned
Application number
US13/938,076
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English (en)
Inventor
Tokarek Wade
Schlekewy Dean
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.)
Individual
Original Assignee
Individual
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 Individual filed Critical Individual
Publication of US20140008078A1 publication Critical patent/US20140008078A1/en
Abandoned legal-status Critical Current

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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
    • 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
    • E21B17/07—Telescoping joints for varying drill string lengths; Shock absorbers
    • 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
    • E21B17/07—Telescoping joints for varying drill string lengths; Shock absorbers
    • E21B17/073—Telescoping joints for varying drill string lengths; Shock absorbers with axial rotation
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121—Lifting well fluids
    • E21B43/126—Adaptations of down-hole pump systems powered by drives outside the borehole, e.g. by a rotary or oscillating drive

Definitions

  • This disclosure relates to a slip joint for a downhole tubing string that allows the downhole tubing to be moved relative to a stationary tubing section.
  • the pump and its components As pumps are used downhole to produce wellbore fluids, the pump and its components, such as a sucker rod, move through repetitive, reciprocal, or rotary motions. This can cause wear in the tubing in which they are placed, and may result in a hole in the tubing. Tubing must be serviced regularly to repair or replace any sections of tubing that are damaged.
  • a movable downhole tubing string for a downhole well, the well having a wellhead and a downhole pump.
  • the movable downhole tubing string comprises a movable tubing string having a surface end adjacent to the wellhead and a pump end adjacent to the downhole pump, at least one of the surface end and the pump end being telescopically received within a stationary tubing section.
  • the stationary tubing section is stationary relative to the wellhead.
  • the movable downhole tubing string may further comprise a rotator that rotates the movable tubing string as it moves relative to the stationary tubing section.
  • the rotator may comprise a sleeve having a position that is fixed relative to the stationary tubing section, the sleeve having at least one groove that defines a spiral, each of the at least one groove being engaged by a pin that is carried by the movable tubing string, the pin travelling along the groove as the movable tubing string moves between the retracted position and the extended position.
  • the actuator may comprise a hydraulic actuator or a mechanical actuator.
  • the actuator may comprise a piston actuator formed by the movable tubing string and the stationary tubing section at at least one of the surface end and the pump end.
  • the stationary tubing section may be at the surface end of the movable tubing string.
  • the movable downhole tubing string may comprise a stationary tubing section at the surface end and at the downhole end of the movable tubing string.
  • the stationary tubing section at the downhole end of the movable tubing string may comprise flow apertures, the flow apertures being selectively opened by movement of the movable tubing string.
  • the downhole pump may be a progressive cavity pump comprising a rotor and a stator and the downhole end of the movable tubing string is attached to the rotor of the progressive cavity pump.
  • the movable tubing string may move the stator up or down relative to the rotor.
  • a wellhead in combination: a wellhead; a first stationary tubing section rigidly connected to the wellhead; a movable tubing string having a surface end and a pump end, the surface end being telescopically received within the first stationary tubing section; an actuator for telescopically moving the movable tubing string relative to the first stationary tubing section; a downhole pump adjacent to the pump end of the movable tubing string; and a pump drive string extending through the movable tubing string between the wellhead and the downhole pump.
  • a rotator that rotates the movable tubing string as it is moves telescopically relative to the first stationary tubing section.
  • the rotator may comprise a sleeve having a position that is fixed relative to the stationary tubing section, the sleeve having at least one groove that defines a spiral, each of the at least one groove being engaged by a pin that is carried by the movable tubing string, the pin travelling along the groove as the movable tubing string moves between the refracted position and the extended position.
  • the actuator may comprises a piston actuator formed by the movable tubing string and the first stationary tubing section.
  • the stationary tubing section at the downhole end of the movable tubing string may comprise flow apertures, the flow apertures being selectively opened by movement of the movable tubing string.
  • the downhole pump may be a progressive cavity pump comprising a rotor and a stator and the downhole end of the movable tubing string is attached to the rotor of the progressive cavity pump.
  • the movable tubing string may move the stator at least one of down relative to the rotor or up relative to the rotor.
  • the actuator may comprise a hydraulic actuator and the tubing string may further comprise a piston mounted at an upper end of the movable tubing string.
  • a method of operating a downhole pump comprising the steps of: providing a tubing string having a stationary tubing section and a movable tubing string telescopically received within the stationary tubing section; attaching a downhole pump to the stationary tubing section of the tubing string and attaching a pump drive string to the downhole pump; inserting the tubing string into a producing wellbore; driving the pump using the pump drive string; and telescopically moving the movable tubing string of the tubing string relative to the stationary tubing section to distribute the wear on the movable tubing string incurred by the pump drive string along the movable tubing string.
  • moving the movable tubing string may further comprise rotating the movable tubing string as it moves between the extended position and the refracted position.
  • FIG. 1 is a side elevation schematic view of a slip joint for downhole tubing
  • FIG. 2 is a side elevation view in section of a tubing string in a refracted position
  • FIG. 3 is a side elevation view in section of a tubing string in an extended position
  • FIG. 4 is a side elevation view in section of a rotator sleeve
  • FIG. 5 is a side elevation view in section of an alternative tubing string in a retracted position
  • FIG. 6 is a side elevation view in section of an alternative tubing string in an extended position
  • FIG. 7 is a detailed side elevation view in section of an alternative tubing string attached to a downhole pump
  • FIG. 8 is a detailed side elevation view in section of the alternative tubing string of FIG. 7 with the stator lowered.
  • FIG. 9 is a detailed side elevation view in section of the alternative tubing string of FIG. 7 with the stator raised.
  • a movable downhole tubing string which includes a stationary tubing section 12 and a movable tubing string 14 that is telescopically received within stationary tubing section 12 .
  • Stationary tubing section 12 may be positioned at a pump end 16 of movable tubing string 14 , at a surface end 18 of movable tubing string 14 or both.
  • Movable tubing string 14 extends between surface end 18 and pump end 16 .
  • the various sections of tubing that are described herein may be any length although 30 ft sections are commonly used in industry. It will be understood that the various components may not be the same length. However, it is preferred that the movement cover an entire length of a section of tubing, for reasons that will be apparent from the discussion below.
  • Stationary tubing section 12 is designed to be attached to a pump 20 . This attachment may be done in various ways, depending on the type of pump being used, as will be recognized by those skilled in the art.
  • Stationary tubing section 12 may be anchored to the wellbore directly, or pump 20 may be anchored downhole to ensure stationary tubing section 12 remains stationary.
  • a pump drive string 19 such as a sucker rod string, extends from surface down through movable tubing string 14 and stationary tubing section 12 to engage and drive pump 20 .
  • Pump 20 may be a rotary pump or a reciprocating pump.
  • FIG. 7 depicts rod string 19 connected to a progressive cavity pump 42 , which has a rotor 44 and a stator 46 .
  • movable tubing string 14 is preferably made up of sections of tubing string that are commonly used in the industry. The main differences between movable tubing string 14 and a traditional tubing string will be found at the pump end 16 and the surface end 18 , as will be described below.
  • FIG. 1 there is also an actuator 22 that telescopically moves movable tubing string 14 relative to stationary tubing section 12 .
  • the movement of movable tubing string 14 will be from a refracted position to an extended position relative to stationary tubing section 12 .
  • the movement could also be from an extended position to a refracted position, or from an intermediate position to either an extended or refracted position.
  • seals 21 are provided between movable tubing string 14 and stationary tubing section 12 , however these are intended primarily to prevent debris and unwanted material from entering the mechanism while movable tubing string 14 is kept stationary.
  • seals 21 it is necessary for any fluid between these seals to escape, or for fluid to be drawn in, as the components move, and either seals 21 must be designed accordingly or another egress must be provided.
  • the space between movable tubing string 14 and stationary tubing section 12 may be filled with hydraulic oil prior to installation. As movable tubing string 14 is moved upward relative to stationary tubing section 12 , the hydraulic oil is pushed out through seals 21 , which helps lubricate the movement.
  • actuator 22 may be a hydraulic actuator.
  • movable tubing string 14 includes a piston 24 that is received within a second stationary tubing section 26 , and sealed together by seals 28 .
  • a hydraulic line 32 communicates hydraulic fluid below piston 24 , causing it to move upward and lift movable tubing string 14 . It will be understood that, if movable tubing string 14 is designed to move downward instead, the hydraulic force must be adjusted accordingly. If the weight of movable tubing string 14 is sufficient, it may be sufficient to remove hydraulic fluid from below piston 24 and allow it to descend based on gravity alone. Otherwise, it may be necessary to push downward on piston 24 .
  • actuator 22 may be mechanically driven, such as by gears or cables as will be recognized by those skilled in the art.
  • it may be convenient to incorporate second stationary tubing section 26 into a wellhead.
  • tubing string 10 may be moved in order to distribute the wear and extend the life of tubing string 10 .
  • tubing string may also have a rotator 30 that causes movable tubing string 14 to rotate as it is being raised.
  • rotator 30 is a section of tubing that rotates the movable tubing string as it is moves between the extended position and the retracted position.
  • the depicted rotator 30 is made up of a sleeve 34 that is attached to second stationary tubing section 26 and is stationary as movable portion 14 is received within sleeve 34 .
  • the actual position of rotator sleeve 34 may be varied, provided that it is fixed relative to stationary tubing section 12 .
  • sleeve 34 has grooves 36 along an inner surface 38 that define a spiral. In one example, two grooves that are offset by 180 degrees may be used, although there may be one or more than two grooves.
  • pins 40 mounted to movable tubing string 14 engage grooves 36 . As movable tubing string 14 is moved up or down, pins 40 travel along grooves 36 and apply a rotary force to movable tubing string 14 , causing it to rotate. It will be understood that other types of rotators may also be used.
  • pump 20 is driven as is known in the art. Pump 20 is driven by either rotating or reciprocating drive string 19 . As this occurs, drive string 19 will create wear on the inside of tubing string 10 .
  • actuator 22 may be actuated to cause movable tubing string 14 to move relative to stationary tubing section 12 . As movable tubing string 14 moves telescopically and rotationally, the wear due to either a rotating string 19 , which is generally localized at one position along tubing string 10 , and a reciprocating string 19 , which is generally localized at one radial position of tubing string 10 , is distributed, thus increasing the useful life of tubing string 10 , or the time between servicing.
  • movable tubing string 14 may be moved in order to flush the downhole pump.
  • stationary tubing section 12 may have perforations 48 or other types of flow openings that are accessible by moving movable tubing string 14 . As shown, when movable tubing string 14 is raised, perforations 48 are exposed, allowing fluid to be circulated down through movable tubing string 14 in order to flush above the pump.
  • FIGS. 7 through 9 an example is shown in which there is no stationary tubing section 12 at the pump end of movable tubing string 14 . Instead, movable tubing string 14 is attached to stator 46 while rod string 19 is attached to rotor 44 . As movable tubing string 14 moves, rod string 19 remains at a fixed length, allowing stator 46 to either be lowered below rotor 44 as shown in FIG. 8 , for example to allow pump 42 to be flushed, or lifted above rotor 44 as shown in FIG. 9 , for example to tap the bottom of stator 46 in order to alleviate gas lock in pump 42 .

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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)
  • Structures Of Non-Positive Displacement Pumps (AREA)
  • Earth Drilling (AREA)
US13/938,076 2012-07-09 2013-07-09 Slip joint for downhole tubing Abandoned US20140008078A1 (en)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
CA2782957 2012-07-09
CA2782957A CA2782957A1 (fr) 2012-07-09 2012-07-09 Joint coulissant pour tubage de fond de trou

Publications (1)

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US20140008078A1 true US20140008078A1 (en) 2014-01-09

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US13/938,076 Abandoned US20140008078A1 (en) 2012-07-09 2013-07-09 Slip joint for downhole tubing

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US (1) US20140008078A1 (fr)
CA (2) CA2782957A1 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9670757B2 (en) 2015-02-10 2017-06-06 Warren WESSEL Downhole pump flushing system and method of use

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5667369A (en) * 1994-11-25 1997-09-16 Institut Francais Du Petrole Volumetric pump driven by a continuous tube
US6447021B1 (en) * 1999-11-24 2002-09-10 Michael Jonathon Haynes Locking telescoping joint for use in a conduit connected to a wellhead
US7647962B2 (en) * 2005-06-07 2010-01-19 Ypf Sociedad Anonima Assembly and method of alternative pumping using hollow rods without tubing
US20100236787A1 (en) * 2009-03-17 2010-09-23 Hall L D Well Release System and Method
US7950449B2 (en) * 2007-07-03 2011-05-31 Harbison-Fisher, Inc. Stress and torque reducing tool

Patent Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5667369A (en) * 1994-11-25 1997-09-16 Institut Francais Du Petrole Volumetric pump driven by a continuous tube
US6447021B1 (en) * 1999-11-24 2002-09-10 Michael Jonathon Haynes Locking telescoping joint for use in a conduit connected to a wellhead
US6820698B2 (en) * 1999-11-24 2004-11-23 Michael Jonathon Haynes Method of selectively locking a telescoping joint
US7647962B2 (en) * 2005-06-07 2010-01-19 Ypf Sociedad Anonima Assembly and method of alternative pumping using hollow rods without tubing
US7950449B2 (en) * 2007-07-03 2011-05-31 Harbison-Fisher, Inc. Stress and torque reducing tool
US8215383B2 (en) * 2007-07-03 2012-07-10 Harbison-Fischer, Inc. Stress and torque reducing tool
US20100236787A1 (en) * 2009-03-17 2010-09-23 Hall L D Well Release System and Method

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9670757B2 (en) 2015-02-10 2017-06-06 Warren WESSEL Downhole pump flushing system and method of use

Also Published As

Publication number Publication date
CA2782957A1 (fr) 2014-01-09
CA2820053A1 (fr) 2014-01-09

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STCB Information on status: application discontinuation

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