US20140102804A1 - Agitator sub - Google Patents

Agitator sub Download PDF

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Publication number
US20140102804A1
US20140102804A1 US13/829,655 US201313829655A US2014102804A1 US 20140102804 A1 US20140102804 A1 US 20140102804A1 US 201313829655 A US201313829655 A US 201313829655A US 2014102804 A1 US2014102804 A1 US 2014102804A1
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US
United States
Prior art keywords
mandrel
sealing part
string
tubular body
compressed position
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
US13/829,655
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English (en)
Inventor
Bradley R. Cote
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.)
BBJ Tools Inc
Original Assignee
BBJ Tools 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 BBJ Tools Inc filed Critical BBJ Tools Inc
Priority to US13/829,655 priority Critical patent/US20140102804A1/en
Assigned to BBJ TOOLS INC. reassignment BBJ TOOLS INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: COTE, BRADLEY R.
Publication of US20140102804A1 publication Critical patent/US20140102804A1/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
    • E21B17/076—Telescoping joints for varying drill string lengths; Shock absorbers between rod or pipe and drill bit
    • 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
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/24—Drilling using vibrating or oscillating means, e.g. out-of-balance masses

Definitions

  • the present invention relates to an apparatus and method for creating an agitation effect in a string.
  • Agitators are employed to facilitate wellbore drilling and installation of wellbore liners. Agitators create a regular movement of the string that enhances advancement of the drill bit and prevents slip stick in a well string such as a liner.
  • an apparatus comprising: a tubular body for connection within a string including a first mandrel and a second mandrel, and a central bore defining a longitudinal axis of the tubular body and creating a flow path permitting a flow of fluids between the two mandrels and through the tubular body, the second mandrel secured, at least partially, within an annular bore of the first mandrel so that the second mandrel is telescopically arranged with and axially moveable within the first mandrel between a telescopically extended position and a compressed position; and a first sealing part and a second sealing part, one of the first and the second sealing part being secured to the first mandrel and the other sealing part being secured to the second mandrel, both sealing parts being within the fluid flow path of the tubular body, the first sealing part and the second sealing part being positioned to come together when the first mandrel and the second mandrel are
  • a drill string comprising: a string of tubulars; a drill bit connected at a distal end of the string of tubulars; a drill collar; and a hydraulically driven agitator positioned between the drill bit and the drill collar.
  • a method for creating an agitation effect in a wellstring comprising: connecting an apparatus as above in-line with a wellbore string to position the second mandrel and the first mandrel in the compressed position when there is weight on bit in the wellbore string; applying weight on bit to position the first mandrel and the second mandrel in the fully compressed position; pumping fluids through the wellbore string to develop a fluid pressure overcoming the weight on bit holding the first mandrel and the second mandrel in compressed position and driving the first mandrel and the second mandrel apart; allowing the pressure to dissipate such that the first mandrel and the second mandrel return back to the compressed position; and continuing to pump fluids through the wellbore string to create an agitation effect as the first mandrel and the second mandrel continue to be pumped apart and then returned to the compressed position.
  • FIG. 1 is a schematic representation of a typical well bore drilling scenario with one embodiment of the apparatus connected in-line with a string.
  • FIG. 2A is a side elevation, sectional view of one embodiment of the apparatus in an extended position.
  • FIG. 2B is a side elevation, sectional view of one embodiment of the apparatus in a sealing position.
  • the terms “up”, “uphole”, “upper”, “above” generally refer to the direction within the wellbore towards the surface.
  • the terms “down”, “downhole”, “lower”, “below” make reference to the direction within the wellbore away from surface.
  • the terms “inner” and “inward” refer to the direction towards the center of a wellbore, whereas the terms “outer” and “outward” refer to the direction away from the center of a wellbore, for example towards the well bore wall.
  • these terms are similarly relevant to deviated and directionally drilled well bores and the tools used therein.
  • the apparatus is an agitator that can be employed to agitate a wellbore string.
  • the string can be a drill string, as shown, or another string that requires agitator, such as a liner string.
  • agitator such as a liner string.
  • a typical drilling rig 10 is shown on the surface 12 with a well bore 14 being drilled through subterranean formations 16 towards a target reservoir 18 , as shown in FIG. 1 .
  • a string 20 is depicted including a drill bit 22 and a tubular body 24 is shown incorporated with the string.
  • Drilling rig 10 or a downhole motor (not shown) or any other method known in the art may provide the torsional force on the drill bit.
  • the string may include any number and variety of downhole elements 27 such as tools, string subs including measurement-while-drilling tools, drill collars, sensors and the like.
  • the present invention provides an apparatus and method that allows the operator of a drilling operation to agitate the string in a regular way during pumping of fluid through the string and when there is weight on bit.
  • the apparatus may telescopically compress in response to weight on the string and the apparatus may be used to pump the parts apart until they are stopped or the pressure dissipates and weight urges them back together causing a hammering effect each time the apparatus recompressed after being pumped apart.
  • the agitator can lift a lot of weight. It can, therefore, be placed close to the bit to have a very direct hammering effect thereon.
  • the agitotaor can be placed between the bit 22 and the drill collars 27 b , such as the non-magnetic drill collars in a directional system. Drill collars, and in particular non-magnetic drill collars, are often called “monels”.
  • the present invention may provide an apparatus.
  • the apparatus may comprise a tubular body 24 for connection within a string 20 including a first mandrel 28 and a second mandrel 30 .
  • the first mandrel is depicted as positioned uphole from the second mandrel.
  • the tubular body may also include a central bore 26 a, 26 b defining the longitudinal axis of the body and permitting the flow of fluids, for example drilling mud, through the tubular body from its upper end to its lower end.
  • the body may include the first mandrel and the second mandrel with the central bore extending through both mandrels.
  • the first mandrel may include an outer wall 32 and an inner wall 34 .
  • Central bore 26 a, 26 b may provide a conduit so that, if the apparatus is connected into the string, the central bore becomes continuous with the bore of the string. This may be of interest for the pumping of drilling fluids from the surface through the string and the body to a drill bit.
  • the second mandrel may include an outer wall 54 and an inner wall 56 , the later which defines the central bore 26 b through the second mandrel.
  • first mandrel 28 may include an inner sleeve 42 that forms an extension through which extends portion 26 a of the central bore. Inner sleeve 42 extends generally coaxially with, and spaced from, inner wall 34 .
  • An annular hollow chamber 36 is formed between sleeve 42 and wall 34 .
  • Inner sleeve 42 defines an inner limit of chamber 36 , such that chamber 36 is defined as an annular space defined between wall 34 and sleeve 42 .
  • the upper end of annular chamber 36 is wall 48 and the lower end of the annular chamber is open
  • the second mandrel may be secured, at least partially, within an annular hollow chamber 36 also defined by inner wall 34 of the first mandrel.
  • Second mandrel 30 is telescopically arranged with, and axially moveable, within the first mandrel.
  • the first mandrel and the second mandrel are telescopically arranged and moveable between an axially compressed position FIG. 2B and an axially expanded position FIG. 2A . In these positions, the madrels remain connected.
  • a first sealing part 52 and a second sealing part 58 may form part of the apparatus with one sealing part secured to the first mandrel and the other sealing part secured to the second mandrel and both sealing parts are, at least partially, within the fluid flow of the tubular body.
  • the first sealing part and the second sealing part may be positioned to come together when the mandrels are compressed, as by applying weight on the string in which the apparatus is installed. When the sealing parts come together they may form a fluid seal in the central bore to substantially prevent the flow of fluids through the tubular body.
  • First mandrel 28 may include an inwardly directed ledge 50 on its lower end.
  • Ledge 50 is a return that reduces the inner diameter across chamber 36 .
  • the uphole end of the first mandrel may be connectable into the string through a tubular connection 41 a , for example a threaded box or pin arrangement or any other tubular connection.
  • the inner sleeve may include first sealing part 52 on its inner diameter such that first sealing part is positioned in the central bore.
  • first sealing part may form an annular surface or a seat with a central aperture 53 .
  • the first sealing part may extend into central bore to such an extent that fluid flow is substantially not restricted through the central aperture.
  • first sealing part may extend across central bore and have ports, rather than a central aperture, therethrough to permit the substantially unrestricted fluid flow past first sealing part.
  • the second mandrel may connect into the string, for example to the drill bit via a tubular connection 41 b such as box or pin threading, etc.
  • the second mandrel may insert into the first mandrel and have a limited range of telescopic movement therein.
  • the second mandrel may be inserted in annular chamber 36 with at least a portion of outer wall 54 axially slidable along wall 34 and inner wall 56 facing the outer surface of inner sleeve 42 .
  • the second sealing part may include a profile portion 60 , which can engage and create a fluidic seal with first sealing part 52 of the first mandrel.
  • the second sealing part may be a variety of relevant shapes such as a dart, a ball point, conical, frustoconical, pyramidal and the like that can plug the center aperture 53 of the first part.
  • the profile portion of second part 58 can seat into and seal against the edges of the center aperture exposed on first sealing part 52 .
  • the second sealing part may have adjacent thereto one or more flow ports 62 to permit the flow of drilling fluid to pass and access the central bore of the string downhole of the second mandrel (see flow direction represented by lines X in FIG. 2A ).
  • the flow ports can be any shape or size to permit such flow of drilling fluid.
  • the flow ports may be positioned so that if the matching profile portion engages the first sealing part drilling fluids cannot flow past the first sealing part to access the central bore there below.
  • the sealing parts are positioned on their respective mandrels such that the sealing parts come together when the mandrels are fully, telescopically compressed.
  • second sealing part 58 may also have one or more apertures 63 or the first sealing part may have apertures, to permit the communication of a small flow of fluids across the second sealing part even when the first sealing part and the second sealing part come together.
  • Apertures 63 may permit fluidic communication there across so that drilling fluids may have a restricted flow, arrows x1, past the second sealing part even if matching profile 60 is sealed in the first sealing part.
  • the uphole end of second mandrel 30 may include a flange 64 that extends outward therefrom.
  • the flange may, for example, be integral such as a lateral extension of the second mandrel or an additional component secured to the second mandrel such as a safety clip.
  • the flange may extend, at least partially, radially out beyond ledge 50 .
  • the engagement of flange 64 with ledge 50 may define the most axially extended position of the limited range of telescopic movement between the first mandrel and second mandrel 30 , as shown in FIG. 2A .
  • the apparatus may further include a biasing member 38 , if desired, that biases the two mandrels into a partially compressed position because the biasing member has a biasing strength.
  • the biasing member limits the extent to which the parts may be telescopically pulled apart and therefore determines the stroke length.
  • the biasing member may also act as a shock absorber. As will be appreciated, therefore, the biasing member may be omitted if neither stroke length determination or shock absorption are of interest.
  • Biasing member 38 may act between the first mandrel and second mandrel 30 to bias them into a partially compressed position. If the biasing member is disposed in the annular hollow chamber between the flange 64 and the ledge 50 , in the most axially extended position, biasing member 38 is fully compressed between the ledge and the flange, as shown in FIG. 2A .
  • Biasing member 38 may be any conventional biasing member such as, for example, a compression spring.
  • compression springs may be Belleville springs, coiled compression springs, helical springs, variable pitch conical springs and the like.
  • a coiled compression spring may have a known, constant biasing strength that allows the spring to resist applied compressive forces to a predictable degree. If the compressive forces exceed the biasing strength constant limit, the spring will compress.
  • the biasing member acts between the two mandrels to bias them into a partially compressed position and in particular, to resist axial movement of the sealing members 53 , 60 apart beyond a certain limit. This prevents damaging forces by the two mandrels being forcibly urged apart, once pressure builds up above the sealing members.
  • the biasing member may be selected, when in a neutral position, to leave some space between the sealing members 53 , 60 in order to allow the agitator to be stopped by removing the weight from the string.
  • the second mandrel may drop by gravity or pump pressure apart such that sealing members do not come together and cannot cause vibration in the string.
  • the outer surface of inner sleeve 42 may have an annular gland 66 to house an inner sealing member 68 .
  • the annular gland may be a rounded groove, a square cut groove, an indentation etc. In the illustrated embodiment of FIGS. 2A and 2B , annular gland 66 is square cut.
  • the inner sealing member may be an o-shaped sealing ring that protrudes from the annular gland so that the sealing member may be compressed between annular gland 66 and the inner surface of the second mandrel creating therebetween a pressure and fluid seal to prevent fluidic communication between the central bore and the annular hollow chamber.
  • the term “sealing member” will, unless otherwise specified, refer to sealing members composed of materials suitable to create and sustain a seal against the pressures associated with a downhole wellbore drilling environment.
  • the inner wall of first mandrel 28 may have a lower annular gland 70 to house a lower sealing member 72 .
  • the lower annular gland may be a rounded groove, a square cut groove, an indentation etc. In the illustrated embodiment of FIG. 2B , the lower annular gland is square cut.
  • the lower sealing member may be an o-shaped sealing ring that protrudes from the lower annular gland so that the lower sealing member may be compressed between the lower annular gland and the outside surface of the second mandrel creating therebetween a pressure and fluid seal to prevent fluidic communication between the wellbore and the annular hollow chamber.
  • flange 64 may include ports 82 to permit the bi-directional flow of fluids therethrough to decrease the likelihood of a pressure build up on either side of the flange. As one can appreciate, such a build up could create a pressure lock impairing the functionality of the agitation sub.
  • a dampener 74 may be installed to mitigate damaging contact between the sealing members.
  • the dampener not shown, may be positioned between wall 48 and the flange.
  • the transmission arrangement may, for example, be a tongue-and-groove arrangement.
  • the transmission arrangement may include the lower sleeve having one or more splines 78 that engage and axially move within one or more receiving grooves 80 on the outer wall of second mandrel 30 .
  • the splines and grooves mate so that rotation of one part is transferred to the other part.
  • the one or more splines may be included on the outer wall of second mandrel and the one or more receiving grooves may be on the inner surface of the lower sleeve.
  • the mandrels may each be constructed of one piece. In another embodiment, the mandrels may each be constructed of two or more components.
  • the first mandrel may be constructed of three primary components, including: an outer sleeve 40 forming walls 32 , 34 , inner sleeve 42 and a lower sleeve 44 forming ledge 50 .
  • the primary components of the first mandrel may define the lateral walls of the annular hollow chamber.
  • lower sleeve 44 may threadedly connect with outer sleeve 40 proximal its lower end.
  • the inner wall of outer sleeve 40 above the connection point with lower sleeve 44 , may define an inner wall 34 open to the annular hollow chamber.
  • the inner sleeve may threadedly connect to outer sleeve 40 , below the tubular connection and above the end wall.
  • the outer wall of the inner sleeve may extend below the end wall to define an inner wall and of the annular hollow chamber.
  • the apparatus can be placed in a string and positioned downhole.
  • the apparatus may be connected in-line with a wellbore string so that the position of second mandrel in the first mandrel is dependent upon weight on the string; applying torsional and axial forces on the string to position the first mandrel and the second mandrel in the fully compressed position; pump fluids through the string to develop a fluid pressure overcoming the weight on bit holding the first mandrel and the second mandrel in a sealing position and driving the first mandrel and the second mandrel apart; allowing the pressure to dissipate when the first mandrel moves out of sealing position with the second mandrel such that the first mandrel returns back to a sealing position against the second mandrel; and continuing to pump fluids through the string to create an agitation effect of the first mandrel and the second mandrel being pumped apart and then returned to a sealing position
  • the profile of the second sealing part may seat in and create a fluidic seal with the profile of the first sealing part, as shown in FIG. 2B , and thereby prevent the flow of fluids there through (except for any small flow through port 63 ).
  • the fluidic seal may be created by the profile of the second sealing part blocking central aperture 53 of the first sealing part, which prevents the flow of fluids through the central bore of the tubular body.
  • the fluidic seal may prevent any fluid communication across the first sealing part so that, for example, drilling fluids being pumped from surface down the central bore of the string will no longer communicate below the fluidic seal provided by parts 52 , 58 .
  • the effect of creating such a fluidic seal, while drilling fluid continues to be pumped from surface, is agitation and hammering in the string.
  • driving the first mandrel and the second mandrel apart includes lifting a drill collar upwardly (i.e. toward surface) away from the drill bit.
  • the agitation and hammering can be applied very close and perhaps directly at the drill bit.
  • the first and second mandrel may be arranged so that torsional forces are transmitted between the two mandrels.
  • the lower sleeve may have one or more splines that engage and axially move within one or more receiving grooves on the outer wall of second mandrel that mate with the one or more splines, or vice versa, the one or more splines may be included on the outer wall of second mandrel and the one or more receiving grooves may be on the inner surface of the lower sleeve.

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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)
US13/829,655 2012-10-15 2013-03-14 Agitator sub Abandoned US20140102804A1 (en)

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US201261714040P 2012-10-15 2012-10-15
US201261731308P 2012-11-29 2012-11-29
US13/829,655 US20140102804A1 (en) 2012-10-15 2013-03-14 Agitator sub

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Cited By (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2015188155A1 (fr) * 2014-06-05 2015-12-10 Toby Scott Baudoin Vibreur de train de tiges de tuyau hydraulique pour réduire un frottement de puits de forage
CN106468138A (zh) * 2015-08-14 2017-03-01 中国石油化工股份有限公司 一种超声波钻井装置及方法
CN106639881A (zh) * 2016-12-30 2017-05-10 淄博润承知识产权代理有限公司 液力振荡器
CN107605404A (zh) * 2017-10-17 2018-01-19 中国石油大学(华东) 一种可产生水力脉冲和冲击振动双作用的钻井提速装置
WO2020246959A1 (fr) * 2019-06-04 2020-12-10 Halliburton Energy Services, Inc. Outil d'intervention pompé et ensemble
US11060370B2 (en) 2018-08-16 2021-07-13 Shane Matthews Downhole agitator tools, and related methods of use
WO2021225817A1 (fr) * 2020-05-05 2021-11-11 Ulterra Drilling Technologies, L.P. Coupleur de trépan pour atténuer les vibrations de torsion
WO2022147169A1 (fr) * 2020-12-29 2022-07-07 Performance Pulsation Control, Inc. Protection reliée au train de tiges contre les énergies de pulsation de trou de forage
US11598171B2 (en) 2019-09-27 2023-03-07 Complete Directional Services Ltd. Tubing string with agitator, tubing drift hammer tool, and related methods
US12618292B2 (en) 2020-07-21 2026-05-05 National Oilwell Varco, L.P. On demand flow pulsing system

Citations (8)

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US1706072A (en) * 1926-10-06 1929-03-19 Walter N Rieger Circulation shut-off device
US1891329A (en) * 1932-02-23 1932-12-20 Nat Oil Drill Corp Braking mechanism for rotary oil well drilling apparatus
US3361220A (en) * 1965-03-17 1968-01-02 Bassinger Tool Company Jarring or drilling mechanism
US4660656A (en) * 1985-11-22 1987-04-28 Amoco Corporation Method and apparatus for controlling the rotational torque of a drill bit
US20010054515A1 (en) * 1996-05-18 2001-12-27 Andergauge Limited Downhole apparatus
US20040112643A1 (en) * 2002-12-17 2004-06-17 Chan Kwong-Onn C. Drill string shutoff valve
US7073610B2 (en) * 2001-05-19 2006-07-11 Rotech Holdings Limited Downhole tool
US20110120773A1 (en) * 2007-08-17 2011-05-26 Paul Hilliard Switchable circulating tool

Patent Citations (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US1706072A (en) * 1926-10-06 1929-03-19 Walter N Rieger Circulation shut-off device
US1891329A (en) * 1932-02-23 1932-12-20 Nat Oil Drill Corp Braking mechanism for rotary oil well drilling apparatus
US3361220A (en) * 1965-03-17 1968-01-02 Bassinger Tool Company Jarring or drilling mechanism
US4660656A (en) * 1985-11-22 1987-04-28 Amoco Corporation Method and apparatus for controlling the rotational torque of a drill bit
US20010054515A1 (en) * 1996-05-18 2001-12-27 Andergauge Limited Downhole apparatus
US7073610B2 (en) * 2001-05-19 2006-07-11 Rotech Holdings Limited Downhole tool
US20040112643A1 (en) * 2002-12-17 2004-06-17 Chan Kwong-Onn C. Drill string shutoff valve
US20110120773A1 (en) * 2007-08-17 2011-05-26 Paul Hilliard Switchable circulating tool

Cited By (18)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2015188155A1 (fr) * 2014-06-05 2015-12-10 Toby Scott Baudoin Vibreur de train de tiges de tuyau hydraulique pour réduire un frottement de puits de forage
US9879495B2 (en) 2014-06-05 2018-01-30 Klx Energy Services Llc Hydraulic pipe string vibrator for reducing well bore friction
CN106468138A (zh) * 2015-08-14 2017-03-01 中国石油化工股份有限公司 一种超声波钻井装置及方法
CN106639881A (zh) * 2016-12-30 2017-05-10 淄博润承知识产权代理有限公司 液力振荡器
CN107605404A (zh) * 2017-10-17 2018-01-19 中国石油大学(华东) 一种可产生水力脉冲和冲击振动双作用的钻井提速装置
WO2019076135A1 (fr) * 2017-10-17 2019-04-25 中国石油大学(华东) Dispositif d'élévation de la vitesse de forage apte à produire des actions doubles d'impulsion hydraulique et de vibration d'impact
US10718176B2 (en) 2017-10-17 2020-07-21 China University Of Petroleum (East China) Drilling speed improvement device capable of producing both hydraulic pulse and impact vibration
US11060370B2 (en) 2018-08-16 2021-07-13 Shane Matthews Downhole agitator tools, and related methods of use
WO2020246959A1 (fr) * 2019-06-04 2020-12-10 Halliburton Energy Services, Inc. Outil d'intervention pompé et ensemble
US11603737B2 (en) 2019-06-04 2023-03-14 Halliburton Energy Services, Inc. Pump down intervention tool and assembly
US11598171B2 (en) 2019-09-27 2023-03-07 Complete Directional Services Ltd. Tubing string with agitator, tubing drift hammer tool, and related methods
WO2021225817A1 (fr) * 2020-05-05 2021-11-11 Ulterra Drilling Technologies, L.P. Coupleur de trépan pour atténuer les vibrations de torsion
CN115485450A (zh) * 2020-05-05 2022-12-16 阿特拉钻孔技术有限合伙公司 用于减轻扭转振动的钻头连接器
US11814907B2 (en) 2020-05-05 2023-11-14 Ulterra Drilling Technologies, L.P. Drill coupler for mitigating torsional vibration
US12618292B2 (en) 2020-07-21 2026-05-05 National Oilwell Varco, L.P. On demand flow pulsing system
WO2022147169A1 (fr) * 2020-12-29 2022-07-07 Performance Pulsation Control, Inc. Protection reliée au train de tiges contre les énergies de pulsation de trou de forage
US11988071B2 (en) 2020-12-29 2024-05-21 Performance Pulsation Control, Inc. Drill string-connected protection from borehole pulsation energies
US12546171B2 (en) 2020-12-29 2026-02-10 Performance Pulsation Control, Inc. Drill string-connected protection from borehole pulsation energies

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Effective date: 20130610

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