CA3007654C

CA3007654C - Systems and methods for minimizing downhole tool vibrations and disturbances

Info

Publication number: CA3007654C
Application number: CA3007654A
Authority: CA
Inventors: John Gibb
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2016-01-13
Filing date: 2016-01-13
Publication date: 2020-06-09
Anticipated expiration: 2036-01-13
Also published as: WO2017123213A1; CA3007654A1

Abstract

A downhole vibration minimization device includes a housing comprising a drilling fluid flow path, a sensor configured to sense a vibration frequency and amplitude of a tool vibration, and a force generator configured to open and close the drilling fluid flow path at a pulse frequency approximately 180 degrees out of phase with the vibration frequency, thereby minimizing the tool vibration.

Description

Systems and Methods for Minimizing Downhole Tool Vibrations and Disturbances Background [0001] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the presently described embodiments. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the described embodiments.
Accordingly, it should be understood that these statements are to be read in this light and not as admissions of prior art.

[0002] Downhole drilling system can be subject to various vibrations and disturbances during a drilling operation. Generally, 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. For example, 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.
Typically 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. Specifically, 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. In the majority of cases controlling stick-slip usually means scarifying performance, penetration rate (ROP) as parameters are usually reduced to limit the depth of cut by the polycrystalline diamond compact (PDC) drill bit.
Summary [0002a] In accordance with a general aspect, there is provided a downhole vibration minimization device, comprising: a housing comprising a drilling fluid flow path; a sensor configured to sense a vibration frequency and amplitude of a tool vibration;
and a force generator configured to open and close the drilling fluid flow path at a pulse frequency approximately 180 degrees out of phase with the vibration frequency, thereby minimizing the tool vibration.

10002b] In accordance with another aspect, there is provided a downhole vibration minimization device, comprising: a housing comprising a wall comprising a housing side opening formed therein; an inner spool located within the housing, the inner spool comprising a wall surrounding a drilling fluid flow path, the wall comprising a spool side opening formed therein; wherein the inner spool is rotatable with respect to the housing, controllably overlapping and separating the housing side opening and the spool side opening; and wherein overlapping of the housing side opening and the spool side opening places the drilling fluid flow path in fluid communication with an annular space external to the housing.
10002c] In accordance with a further aspect, there is provided a method of drilling a well with a downhole tool, comprising: sensing a vibration of a downhole tool, the vibration having a vibration frequency and amplitude; opening and closing a drilling fluid flow path based on the vibration frequency and amplitude; and generating forces at a pulse frequency from the opening and closing of the drilling fluid flow path to minimize the vibration of the downhole tool.
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3 Brief Description of the Drawings [0003] For a detailed description of the embodiments of the invention, reference will now be made to the accompanying drawings in which:

[0004] FIG. 1 depicts a drilling system with a vibration minimization system performing a well drilling operation, in accordance with example embodiments;

[0005] FIG. 2A depicts a transverse cross-sectional view of a downhole vibration minimization device for axial pulse generation, in accordance with example embodiments;

[0006] FIG. 2B depicts a radial cross-sectional view of the device of FIG. 2A, in accordance with example embodiments;

[0007] FIG. 3A depicts a transverse cross-sectional view of a downhole vibration minimization device for radial pulse generation, in accordance with example embodiments;

[0008] FIG. 3B depicts a radial cross-sectional view of the device of FIG. 3A, in accordance with example embodiments;

[0009] FIG. 4A depicts a transverse cross-sectional view of a downhole vibration minimization device for tangential pulse generation, in accordance with example embodiments; and

[0010] FIG. 4B depicts a radial cross-sectional view of the device of FIG. 4A, in accordance with example embodiments.
Detailed Description

[0011] 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.

Specifically, 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.
[0001] 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.
[0002] Referring to the drawings, FIG. 1 depicts a drilling system 100 performing a well drilling operation, in accordance with example embodiments. 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. 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. Specifically, in some embodiments, 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) 114, a drill bit 116, and a telemetry module 118.
[0003] 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. In some embodiments, 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. In one or more embodiments, a topdrive is used to rotate the drill string 102 in place of the kelly 126 and the rotary table 128. In such embodiments, the drill bit 116 is driven via rotation of the entire drill string 102 from the surface.
Alternatively, in some embodiments, the drill bit 116 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 116 creates the wellbore 101 that passes through various formations 120.
[0004] 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 114.
[0005] 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 116 extends the wellbore 116 through the formations 120. The LWD/MWD tools 110 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 116, pressure sensors for measuring drilling fluid pressure, temperature sensors for measuring borehole temperature, among others.
[0006] 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 118, 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.
[0007] In one or more embodiments, the surface control unit 134 may communicate directly with the LWD/MWD tools 110 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.
[0008] As the drill bit 116 drills through the formation 120, 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.
[0009] 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. In some embodiments, 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. When the drilling fluid flow path 204 is open, drilling fluid can flow through the device 200. In some embodiments, 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.
[0010] The pulse generator 208 can be constructed in many ways. In one or more embodiments, 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.

In some embodiments, 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.
[0011] When the 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. When 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.

[0012] The pulse generator 208 further includes a motor 218 coupled to at least one of the first disk 210 or second disk 212. In some embodiments, 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.

[0013] In one or more embodiments, the sensor 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. In one example, fast Fourier transfoim processing of the vibration sensor signals may be used to produce the spectra of the downhole BHA vibration. Using this data, a pulsing scheme is determined for controlling opening and closing of the drilling fluid flow path 204. Using feedback control, the pulse generator 208 may be controlled in real time to reduce the downhole vibrations. In some embodiments, 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.

[0014] In one or more embodiments, the motor 218 controllably drives the rotating disk 212 in a constant circular direction while varying the rotational speed based on pulse scheme. In some embodiments, 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. Thus, 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. For example, the amplitude may be controlled by adjusting the amount of angular rotation of the rotating disk 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. In some embodiments, the pulse generator 208 may have multiple controlled rotating disk mechanisms for adjusting more than one frequency at a time.

[0015] As the opening and closing of the drilling fluid flow path 204 affects the flow of the drilling fluid, the pulses may interfere with mud pulse telemetry signals which are carried by the same drilling fluid. To resolve this, 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. In some embodiments, the surface control unit 134 detects the pulses and searches for the new transmission frequency range. In some embodiments, the telemetry module 118 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.
In some embodiments, the pulse generator 208 may be used as a mud data generator, generating pulses which carry data.

[0016] In addition to imparting axial forces on the BHA 108, the controllable jetting of fluid from the inside of the drill string radially and/or tangentially out towards a return annulus may be used to counteract the radial and torsional forces induced during, for example, stick/slip. FIG. 3A 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. In some embodiments, 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.

[0017] 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. When the flow passages 306 of the inner spool 304 are aligned or overlapped 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. This creates a radial reaction force or pulse in the opposite direction of the jet stream. ln some embodiments, the housing 302 is also rotatable with respect to the wellbore such that the direction of the radial force can be controlled. In some embodiments, seals 312 are placed between the inner spool 304 and the housing 302 to prevent leaking of drilling fluid.

[0018] 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.
[0001] 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.
[0002] 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. When the flow passages 406 of the inner spool 404 are aligned or overlapped with the flow passages 406 of the housing 402, the drilling fluid flow path 410 inside the inner spool 404 is put in fluid communication with an annular space outside of the housing via the flow passages 406,408, permitting drilling fluid to flow out of the flow passages 406,408. This creates a tangential reaction force or torque in the opposite direction of the jet stream, which may result in an angular force. In some embodiments, the housing 402 is also rotatable with respect to the wellbore such that the direction of the tangential reaction force can be controlled. In some embodiments, seals 412 are placed between the inner spool 404 and the housing 402 to prevent leaking of drilling fluid.
[0003] The frequency and amplitude of the forces can be determined similar to the axial vibration extermination system 200 of FIGS. 2A 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 deteimines 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.
[0004] In one or more embodiments, 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.
[0005] In addition to the embodiments described above, many examples of specific combinations are within the scope of the disclosure, some of which are detailed below:
[CLAIMS BANK TO BE COMPLETED AFTER CLAIMS ARE
FINALIZED]
[0006] This discussion is directed to various embodiments of the invention.
The drawing figures are not necessarily to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims.
It is to be fully recognized that the different teachings of the embodiments discussed may be employed separately or in any suitable combination to produce desired results. In addition, one skilled in the art will understand that the description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment.
[0007] Certain terms are used throughout the description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function, unless specifically stated. In the discussion and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to... ." Also, the term "couple" or "couples" is intended to mean either an indirect or direct connection. In addition, the terms "axial" and "axially" generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the teims "radial" and "radially" generally mean perpendicular to the central axis. The use of "top," "bottom," "above,"
"below," and variations of these terms is made for convenience, but does not require any particular orientation of the components.
[0008] Reference throughout this specification to "one embodiment," "an embodiment," or similar language means that a particular feature, structure, or characteristic described in connection with the embodiment may be included in at least one embodiment of the present disclosure. Thus, appearances of the phrases "in one embodiment," "in an embodiment," and similar language throughout this specification may, but do not necessarily, all refer to the same embodiment.
[0009] Although the present invention has been described with respect to specific details, it is not intended that such details should be regarded as limitations on the scope of the invention, except to the extent that they are included in the accompanying claims.

Claims

Claims What is claimed is:

1. A downhole vibration minimization device, comprising:
a housing comprising a drilling fluid flow path;
a sensor configured to sense a vibration frequency and amplitude of a tool vibration; and a force generator configured to open and close the drilling fluid flow path at a pulse frequency approximately 180 degrees out of phase with the vibration frequency, thereby minimizing the tool vibration.

2. The device of claim 1, wherein the force generator comprises:
a first disk located within the housing and comprising at least one flow passage;
a second disk located within the housing adjacent the stationary disk, the second disk comprising at least one flow passage and rotatable with respect to the first disk, wherein overlapping of the flow passages of the first disk and second disk opens the drilling fluid flow path and separation of the flow passages closes the drilling fluid flow path, and wherein closing of the drilling fluid flow path generates a force.

3. The device of claim 2, wherein the force generator further comprises a motor configured to rotate at least one of the first and second disks, opening and closing the drilling fluid flow path.

4. The device of claim 3, further comprising a controller configured to control the motor according to a control scheme determined based on the sensed vibration frequency and amplitude.

5. The device of claim 3, wherein closing of the drilling fluid flow path generates an axial force.

6. The device of claim 1, wherein the force generator is configured to open the drilling fluid flow path an amount corresponding to the vibration amplitude.

7. The device of claim 3, wherein the motor comprises an electric motor or a hydraulic motor.

8. The device of claim 1, further comprising a mud telemetry system configured to detect the pulse frequency and find a mud telemetry transmission frequency spectrum outside of the pulse frequency.

9. The device of claim 3, wherein the first disk is a stationary disk coupled to the housing and the second disk is a rotating disk coupled to the motor.

10. The device of claim 1, wherein the housing is coupleable, directly or indirectly, to a drill string and configured to received drilling fluid from the drill string.

11. A downhole vibration minimization device, comprising:
a housing comprising a wall comprising a housing side opening formed therein;
an inner spool located within the housing, the inner spool comprising a wall surrounding a drilling fluid flow path, the wall comprising a spool side opening formed therein;
wherein the inner spool is rotatable with respect to the housing, controllably overlapping and separating the housing side opening and the spool side opening; and wherein overlapping of the housing side opening and the spool side opening places the drilling fluid flow path in fluid communication with an annular space external to the housing.

12. The device of claim 11, further comprising seals located between the inner spool and the housing.

13. The device of claim 11, wherein the housing side opening is formed radially in the wall and overlapping of the housing side opening and the spool side opening permits drilling fluid to flow out of the device radially, generating a radial force.

14. The device of claim 11, wherein the housing side opening is formed tangentially in the wall and overlapping of the housing side opening and the spool side opening generates a tangential rotation force.

15. The device of claim 11, wherein the housing is coupleable, directly or indirectly, to a drill string and configured to received drilling fluid from the drill string.

16. A method of drilling a well with a downhole tool, comprising:
sensing a vibration of a downhole tool, the vibration having a vibration frequency and amplitude;
opening and closing a drilling fluid flow path based on the vibration frequency and amplitude; and generating forces at a pulse frequency from the opening and closing of the drilling fluid flow path to minimize the vibration of the downhole tool.

17. The method of claim 16, wherein opening and closing of the drilling fluid flow path comprises rotating a first disk relative to a second disk, each disk having a flow passage, wherein coupling of the flow passages opens the drilling fluid flow path and separation of the flow passages closes the drilling fluid flow path.

18. The method of claim 16, further comprising generating the pulse frequency at approximately 180 degrees out of phase with the vibration frequency.

19. The method of claim 16, further comprising finding a mud telemetry transmission frequency spectrum outside of the pulse frequency range.

20. The method of claim 16, wherein the pulses are directed axially, radially, or tangentially.

21. The method of claim 16, further comprising generating axial forces on the downhole tool via the pulses.

22. The method of claim 16, further comprising opening the drilling fluid flow path an amount corresponding to the vibration amplitude, thereby matching amplitude of the pulses to the vibration amplitude.