WO2017123213A1 - Systèmes et procédés permettant de minimiser les vibrations et les perturbations d'un outil de fond de trou - Google Patents

Systèmes et procédés permettant de minimiser les vibrations et les perturbations d'un outil de fond de trou Download PDF

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Publication number
WO2017123213A1
WO2017123213A1 PCT/US2016/013164 US2016013164W WO2017123213A1 WO 2017123213 A1 WO2017123213 A1 WO 2017123213A1 US 2016013164 W US2016013164 W US 2016013164W WO 2017123213 A1 WO2017123213 A1 WO 2017123213A1
Authority
WO
WIPO (PCT)
Prior art keywords
drilling fluid
housing
flow path
vibration
fluid flow
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.)
Ceased
Application number
PCT/US2016/013164
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English (en)
Inventor
John Gibb
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.)
Halliburton Energy Services Inc
Original Assignee
Halliburton Energy Services 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 Halliburton Energy Services Inc filed Critical Halliburton Energy Services Inc
Priority to PCT/US2016/013164 priority Critical patent/WO2017123213A1/fr
Priority to CA3007654A priority patent/CA3007654C/fr
Publication of WO2017123213A1 publication Critical patent/WO2017123213A1/fr
Anticipated expiration legal-status Critical
Ceased 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
    • E21B28/00—Vibration generating arrangements for boreholes or wells, e.g. for stimulating production
    • 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
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/10—Valve arrangements in drilling-fluid circulation systems
    • E21B21/103—Down-hole by-pass valve arrangements, i.e. between the inside of the drill string and the annulus

Definitions

  • Downhole drilling system can be subject to various vibrations and disturbances during a drilling operation.
  • vibrations and disturbances can be classified into three types: axial, torsional, and lateral.
  • the occurrences of these vibrations or disturbances often lead to excessive wear on downhole tools, increased logging error, and even immediate damage of the downhole tools.
  • axial vibrations such as bit bounce may damage bit cutter and bearings.
  • Lateral vibrations may cause a drill string or bottom hole assembly to impact the wellbore wall.
  • Stick slip is a type of torsional vibration in which the drill bit becomes stationary, or stuck, for a period of time and then exerts a rotational acceleration as the bit breaks free.
  • disturbances such as stick-slip may be controlled by altering the surface parameters to find the combination of rotary speed (RPM) and weight on bit (WOB) which minimize the effects of a stick-slip event.
  • RPM rotary speed
  • WOB weight on bit
  • the RPM and WOB are increased and/or decreased on a trial and error basis, allowing the downhole tool operators to find the smoothest combination.
  • penetration rate ROP
  • PDC poly crystalline diamond compact
  • FIG. 1 depicts a drilling system with a vibration minimization system performing a well drilling operation, in accordance with example
  • FIG. 2A depicts a transverse cross-sectional view of a downhole vibration minimization device for axial pulse generation, in accordance with example embodiments
  • FIG. 2B depicts a radial cross-sectional view of the device of FIG. 2 A, in accordance with example embodiments
  • FIG. 3 A depicts a transverse cross-sectional view of a downhole vibration minimization device for radial pulse generation, in accordance with example embodiments
  • FIG. 3B depicts a radial cross-sectional view of the device of FIG. 3 A, in accordance with example embodiments
  • FIG. 4A depicts a transverse cross-sectional view of a downhole vibration minimization device for tangential pulse generation, in accordance with example embodiments.
  • FIG. 4B depicts a radial cross-sectional view of the device of FIG. 4A, in accordance with example embodiments.
  • the present disclosure is directed towards systems and methods for minimizing vibrations and disturbances of a downhole tool commonly caused by stick-slip, bit bounce, bit whirl, lateral shocks, resonance, and the like.
  • the present disclosure is directed towards a vibration minimization system that senses vibrations or disturbances experienced by the downhole tool. The system then generates movements which antagonize the vibrations or disturbances, thereby minimizing or even cancelling out the vibrations or disturbances. The movements are generated by the opening and closing of a drilling fluid flow path.
  • the system of the present disclosure will be specifically described below such that the system is used to minimize tool vibrations and disturbances in a wellbore, such as a subsea well or a land well. Further, it will be understood that the present disclosure is not limited to only drilling an oil well.
  • the present disclosure also encompasses natural gas wellbores, other hydrocarbon wellbores, or wellbores in general. Further, the present disclosure may be used for the exploration and formation of geothermal wellbores intended to provide a source of heat energy instead of hydrocarbons.
  • FIG. 1 depicts a drilling system 100 performing a well drilling operation, in accordance with example
  • the drilling system 100 includes a drill string 102 disposed in a directional wellbore 101.
  • the drill string 102 includes a plurality of drill pipes 104 coupled end to end extending from the surface 106.
  • the drill string 102 further includes a bottom hole assembly (BHA) 108 coupled to the drill pipes 104 at the distal end of the drill string 102.
  • BHA bottom hole assembly
  • the drill pipes 104 provide the length needed for the BHA to reach well bottom and to advance further into the wellbore 116.
  • the BHA 108 includes various tools for carrying out the functions of the drilling operation.
  • the BHA 108 includes one or more measurement while drilling and/or logging while drilling (MWD/LWD) tools 110, a vibration minimization device 112, a motor or rotary steerable system (RSS) 1 14, a drill bit 116, and a telemetry module 118.
  • MWD/LWD measurement while drilling and/or logging while drilling
  • RSS motor or rotary steerable system
  • the drilling system 100 further includes surface equipment such as a derrick 122 and a mud pump 124.
  • the derrick is configured to raise, lower, and support the drill string 102 downhole.
  • the derrick includes a kelly 126 that supports the drill string 102 as the drill string 102 is lowered through a rotary table 128 which rotates the drill string 102.
  • a topdrive is used to rotate the drill string 102 in place of the kelly 126 and the rotary table 128.
  • the drill bit 116 is driven via rotation of the entire drill string 102 from the surface.
  • the drill bit 1 16 may be driven by the motor or RSS 114 without rotating the rest of the drill string 102. As the drill bit 116 rotates, the drill bit 1 16 creates the wellbore 101 that passes through various formations 120.
  • the mud pump 124 circulates drilling fluid through a feed pipe 130 and downhole through the interior of drill string 102, through orifices in drill bit 116 or elsewhere along the drill string 102, and back to the surface via an annulus 132 around the drill string 102, and back to the surface 106.
  • the drilling fluid removes cuttings from the wellbore 101 and aids in maintaining the integrity of the wellbore 101.
  • the drilling fluid may also drive the motor or RSS 1 14.
  • the MWD/LWD tools 110 collect measurements and data relating to various wellbore and formation properties as well as the position of the drill bit 116 and various other drilling conditions as the drill bit 1 16 extends the wellbore 1 16 through the formations 120.
  • the LWD/MWD tools 1 10 may include a device for measuring formation resistivity, a gamma ray device for measuring formation gamma ray intensity, devices for measuring the inclination and azimuth of the drill bit 1 16, pressure sensors for measuring drilling fluid pressure, temperature sensors for measuring borehole
  • the telemetry module 118 receives data provided by the various sensors of the drill string 102 (e.g., sensors of the MWD/LWD tools 110, motor or RSS 114), and transmits the data to a surface control unit 134. Data may also be provided by the surface control unit 134, received by the telemetry module 1 18, and transmitted to the tools (e.g., LWD/MWD tools 110, motor or RSS 114) of the drill string 102. In one or more embodiments, mud pulse telemetry, wired drill pipe, acoustic telemetry, or other telemetry technologies known in the art may be used to provide communication between the surface control unit 134 and the telemetry module 118.
  • the surface control unit 134 may communicate directly with the LWD/MWD tools 1 10 and/or the motor or RSS 114.
  • the surface control unit 134 may be a computer stationed at the well site, a portable electronic device, a remote computer, or distributed between multiple locations and devices.
  • the surface control unit 134 may also control functions of the equipment of the drill string 102 or derrick 122.
  • the BHA 108 may experience various physical disturbances such as stick-slip, bit bounce, bit whirl, shocks, resonance, and the like. These disturbances may cause excess vibration or undesired movements of the BHA 108.
  • the vibration minimization device 112 is configured to generate pulses or movements aimed at neutralizing these vibrations or disturbances, thereby cancelling out the vibrations or disturbances.
  • FIG. 2A depicts a transverse cross-sectional view of a downhole vibration minimization device 200 for axial force generation, in accordance with example embodiments.
  • FIG. 2B depicts a radial cross-sectional view of the same device 200.
  • the device 200 includes a housing 202 having a drilling fluid flow path 204, a sensor 206 configured to sense a vibration frequency of a tool vibration, and a force generator 208 configured to open and close the drilling fluid flow path 204.
  • drilling fluid flow path 204 is open, drilling fluid can flow through the device 200.
  • the drilling fluid flow path 204 is kept open when the device 200 is inactive. Closing of the drilling fluid flow path 204 while drilling fluid is being injected through the drill string 102 causes an axial force to be applied in the direction of the fluid impact against a barrier, acting as a fluid hammer.
  • the pulse generator 208 can be constructed in many ways.
  • the pulse generator 208 includes a first disk 210 and a second disk 212 located inside the housing and in the drilling fluid flow path.
  • the first disk 210 and the second disk 212 are located within the housing 202 and axially adjacent to each other.
  • the first disk 210 and the second disk 212 are also rotatable with respect to each other.
  • Each of the disks 210, 212 includes at least one flow passage 214.
  • the example disks in FIG. 2 each have four flow passages 214, but the disks 210, 212 can be designed to have any number, shape, or size of flow passes.
  • first disk 210 and the second disk 212 are rotated into a position in which at least one flow passage 214 of the first disk 210 overlaps at least one flow passage 214 of the second disk 214, the overlap provides an opening 216 for the drilling fluid to pass, thereby opening the drilling fluid flow path 204.
  • first disk 210 and the second disk 212 are rotated into a position in which the flow passages 214 are separated and there is no overlap, the disks 210, 212 become a barrier and the drilling fluid flow path 204 is closed. Controlled rotation of the disks 210, 212 with respect to one another brings the flow passages 214 into and out of overlap, thereby controllably opening and closing the drilling fluid flow path 204.
  • the pulse generator 208 further includes a motor 218 coupled to at least one of the first disk 210 or second disk 212.
  • the motor 218 is couple to the disk via a shaft 220.
  • the motor 218 controls rotation of the disks 210, 212 with respect to each other, thereby controlling opening and closing of the drilling fluid flow path 204.
  • the motor 218 may include an electric motor, a hydraulic motor, or any other rotational drive mechanism.
  • One of the first and second disks 210, 212 is a stationary disk and coupled to the housing 202, and the other is a rotating disk coupled to the motor 218 and configured to rotate with respect to the stationary disk and the housing 202.
  • the senor 206 is configured to sense vibrations and disturbances of the BHA 108 and a processing unit 222 receives the sensor readings.
  • the vibrations and disturbance may be represented as a waveform having a vibration frequency and amplitude.
  • fast Fourier transform processing of the vibration sensor signals may be used to produce the spectra of the downhole BHA vibration.
  • a pulsing scheme is determined for controlling opening and closing of the drilling fluid flow path 204.
  • the pulse generator 208 may be controlled in real time to reduce the downhole vibrations.
  • the pulsing scheme is configured to have a frequency approximately 180 degrees offset from the frequency of the BHA vibration, thereby substantially cancelling out the BHA vibrations.
  • the pulse generator 208 is controlled to open and close the drilling fluid flow path 204, generating pulses according to the pulse scheme.
  • the terms approximately and substantially are used herein to be inclusive of a margin of error while remaining within the scope of the present disclosure.
  • the motor 218 controllably drives the rotating disk 212 in a constant circular direction while varying the rotational speed based on pulse scheme.
  • the pulse amplitude is related to the amount of flow that is restricted as the flow passages 214 in the rotating disk 212 rotate out of alignment with the flow passages 214 in the stationary disk 210.
  • the amplitude of the pulse may be controlled to match that of the BHA vibrations.
  • the rotating disk 212 may be controlled to rotationally oscillate back and forth.
  • the amplitude may be controlled by adjusting the amount of angular rotation of the rotating disk 212 relative to the stationary disk 210 such that only a controllable portion of the flow passages 214 overlap.
  • the pulse frequency may be adjusted by the frequency of the back and forth oscillation of the rotating disk 212.
  • the pulse generator 208 may have multiple controlled rotating disk mechanisms for adjusting more than one frequency at a time.
  • the pulses may interfere with mud pulse telemetry signals which are carried by the same drilling fluid.
  • the telemetry module 118 is configured to detect the pulses generated by the pulse generator 208 and search for a new transmission frequency range which is outside of the pulse frequency range. Thus data carried on this transmission frequency range can be clearly distinguished.
  • the surface control unit 134 detects the pulses and searches for the new transmission frequency range.
  • the telemetry module 1 18 or the surface control unit 134 scans multiple band widths for data symbol content and discard channels that fall within or close to the pulse frequencies.
  • the pulse generator 208 may be used as a mud data generator, generating pulses which carry data.
  • FIG. 3 A depicts a transverse cross-sectional view of a downhole vibration extermination device 300 for radial pulse generation, in accordance with one or more embodiments.
  • FIG. 3B depicts a radial cross-sectional view of the same device 300.
  • the device 300 includes a housing 302 and an inner spool 304 located within the housing 302.
  • the inner spool 304 is hollow, creating a drilling fluid flow path 310 and permitting drilling fluid to flow therethrough.
  • the inner spool 304 is rotatable with respect to the housing 302.
  • the housing 302 includes one or more flow passages 308 formed in the wall of the housing 302.
  • the inner spool 304 may likewise include one or more flow passages 306 formed in the wall of the inner spool 304.
  • the inner spool 304 can be rotated to align or overlap the flow passages 306 of the inner spool 304 with the flow passages 308 of the housing 302.
  • the drilling fluid flow path 310 inside the inner spool 304 is put in fluid communication with an annular space outside of the housing 302 via the flow passages 306, 308, permitting drilling fluid to jet out of the flow passages 306, 308.
  • the housing 302 is also rotatable with respect to the wellbore such that the direction of the radial force can be controlled.
  • seals 312 are placed between the inner spool 304 and the housing 302 to prevent leaking of drilling fluid.
  • the frequency and amplitude of the pulses can be determined similar to the axial pulse generation device 200 of FIGS. 2A and 2B, in which a sensor detects tool vibrations or disturbances in the radial direction and a processor determines a pulse scheme for counteracting and thus cancelling out the tool vibrations or disturbances. A motor then rotates the inner spool 304 and/or housing 302 accordingly.
  • FIG. 4A depicts a transverse cross-sectional view of a downhole vibration minimization device 400 for tangential pulse generation, in accordance with one or more embodiments.
  • FIG. 4B depicts a radial cross- sectional view of the same device 400.
  • the device 400 includes a housing 402 and an inner spool 404.
  • the inner spool 404 is hollow, creating a drilling fluid flow path 410 and permitting drilling fluid to flow therethrough.
  • the inner spool 404 is also rotatable with respect to the housing 402.
  • the housing 402 includes one or more tangential flow passages 408 formed through the wall of the housing 402.
  • the inner spool 404 may likewise include one or more flow passages 406 formed in the wall of the inner spool 404.
  • the inner spool 404 can be rotated to align or overlap the flow passages 406 of the inner spool 404 with the tangential flow passages 408 of the housing 402.
  • the drilling fluid flow path 410 inside the inner spool 404 is put in fluid
  • the housing 402 is also rotatable with respect to the wellbore such that the direction of the tangential reaction force can be controlled.
  • seals 412 are placed between the inner spool 404 and the housing 402 to prevent leaking of drilling fluid.
  • the frequency and amplitude of the forces can be determined similar to the axial vibration extermination system 200 of FIGS. 2 A and 2B and radial pulse generation device 300 of FIGS. 3A and 3B, in which a sensor detects tool vibrations or disturbances in the radial direction and a processor determines a force scheme for counteracting and thus minimizing or cancelling out the tool vibrations or disturbances.
  • a motor then rotates the inner spool 404 and/or housing 402 accordingly.
  • a drilling system 100 may include any individual or combination of the vibration extermination systems 200, 300, 400, which can be operated in tandem to cancel out combined axial, torsional, and lateral vibrations and disturbances.
  • axial and axially generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis.
  • a central axis e.g., central axis of a body or a port
  • radial and radially generally mean perpendicular to the central axis.

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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

Cette invention concerne un dispositif de minimisation des vibrations de fond de trou, comprenant un boîtier comprenant un trajet d'écoulement de fluide de forage, un capteur configuré pour détecter une fréquence de vibration et une amplitude de vibration d'un outil, et un générateur de force configuré pour ouvrir et fermer le trajet d'écoulement de fluide de forage à une fréquence d'impulsions déphasée d'environ 180 degrés par rapport à la fréquence de vibration, de sorte à minimiser les vibrations de l'outil.
PCT/US2016/013164 2016-01-13 2016-01-13 Systèmes et procédés permettant de minimiser les vibrations et les perturbations d'un outil de fond de trou Ceased WO2017123213A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
PCT/US2016/013164 WO2017123213A1 (fr) 2016-01-13 2016-01-13 Systèmes et procédés permettant de minimiser les vibrations et les perturbations d'un outil de fond de trou
CA3007654A CA3007654C (fr) 2016-01-13 2016-01-13 Systemes et procedes permettant de minimiser les vibrations et les perturbations d'un outil de fond de trou

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2016/013164 WO2017123213A1 (fr) 2016-01-13 2016-01-13 Systèmes et procédés permettant de minimiser les vibrations et les perturbations d'un outil de fond de trou

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WO2017123213A1 true WO2017123213A1 (fr) 2017-07-20

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Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN109403859B (zh) * 2018-12-04 2024-02-09 湖北三峡职业技术学院 野外便携式钻进系统

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4671392A (en) * 1984-12-18 1987-06-09 Fichtel & Sachs Ag Vibration damper with variable damping force
US20030051954A1 (en) * 2001-09-18 2003-03-20 Darryl Sendrea Temperature compensating shock absorber
US20110291334A1 (en) * 2003-11-07 2011-12-01 Aps Technology, Inc. System And Method For Damping Vibration In A Drill String
US20120290209A1 (en) * 2008-09-30 2012-11-15 Precision Energy Services, Inc. Downhole Drilling Vibration Analysis
WO2014146201A1 (fr) * 2013-03-18 2014-09-25 General Downhole Technologies Ltd. Système, procédé et appareil pour l'amortissement des vibrations de fond

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4671392A (en) * 1984-12-18 1987-06-09 Fichtel & Sachs Ag Vibration damper with variable damping force
US20030051954A1 (en) * 2001-09-18 2003-03-20 Darryl Sendrea Temperature compensating shock absorber
US20110291334A1 (en) * 2003-11-07 2011-12-01 Aps Technology, Inc. System And Method For Damping Vibration In A Drill String
US20120290209A1 (en) * 2008-09-30 2012-11-15 Precision Energy Services, Inc. Downhole Drilling Vibration Analysis
WO2014146201A1 (fr) * 2013-03-18 2014-09-25 General Downhole Technologies Ltd. Système, procédé et appareil pour l'amortissement des vibrations de fond

Also Published As

Publication number Publication date
CA3007654C (fr) 2020-06-09
CA3007654A1 (fr) 2017-07-20

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