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Publication numberUS20020148606 A1
Publication typeApplication
Application numberUS 10/051,636
Publication dateOct 17, 2002
Filing dateJan 18, 2002
Priority dateMar 1, 2001
Also published asCA2372366A1
Publication number051636, 10051636, US 2002/0148606 A1, US 2002/148606 A1, US 20020148606 A1, US 20020148606A1, US 2002148606 A1, US 2002148606A1, US-A1-20020148606, US-A1-2002148606, US2002/0148606A1, US2002/148606A1, US20020148606 A1, US20020148606A1, US2002148606 A1, US2002148606A1
InventorsShunfeng Zheng, Benjamin Jeffryes
Original AssigneeShunfeng Zheng, Jeffryes Benjamin J.
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method and apparatus to vibrate a downhole component by use of acoustic resonance
US 20020148606 A1
Abstract
A method and apparatus of vibrating a tubing string in a wellbore comprises a rigid carrier or conveyance structure coupled to an acoustic resonance apparatus. The acoustic resonance apparatus comprises a housing section containing a fluid. A pulser or other device is activated to generate acoustic waves in the fluid. A portion of the acoustic wave energy is reflected by a reflector in the acoustic resonance apparatus. The operating frequency of the pulser or other device is adjusted to achieve acoustic resonance in the fluid.
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Claims(22)
What is claimed is:
1. An apparatus for generating a vibration in a tool string, comprising:
a housing for storing fluid and adapted to be coupled to the tool string; and
a device adapted to generate an acoustic resonance in the fluid.
2. The apparatus of claim 1, wherein the device is adapted to create an acoustic wave in the fluid, the apparatus further comprising a reflector to reflect the acoustic wave to generate the acoustic resonance.
3. The apparatus of claim 2, wherein the device comprises a pulser.
4. The apparatus of claim 2, wherein the reflector comprises an orifice.
5. The apparatus of claim 4, wherein the housing defines a first flow area on a first side of the orifice, the apparatus further comprising a conduit on a second side of the orifice, the conduit having a second flow area that is less than the first flow area.
6. The apparatus of claim 5, wherein a ratio of the first and second flow areas has a predetermined value to determine a reflection coefficient of the reflector.
7. The apparatus of claim 6, wherein the fluid has a predetermined density to determine the reflection coefficient of the reflector.
8. The apparatus of claim 1, further comprising at least one sensor to measure timing of acoustic wave propagation in the fluid.
9. The apparatus of claim 8, further comprising a controller adapted to receive measurement signals from the at least one sensor, the controller further adapted to control the device.
10. The apparatus of claim 9, wherein the device comprises a pulser.
11. The apparatus of claim 10, wherein the controller is adapted to adjust the frequency of the pulser.
12. A method for use in a wellbore, comprising:
coupling an acoustic resonance device to a tubing string;
running the tubing string into a wellbore; and
activating the acoustic resonance device to generate a vibration in the tubing string.
13. The method of claim 12, further comprising generating an acoustic wave in fluid contained in a housing section.
14. The method of claim 13, further comprising providing a reflector in the acoustic resonance device to reflect the acoustic wave.
15. The method of claim 14, wherein activating the acoustic resonance device comprises achieving acoustic resonance in the fluid.
16. The method of claim 15, further comprising providing an orifice in the reflector and selecting flow areas on opposing sides of the orifice to achieve a reflection coefficient of the reflector.
17. The method of claim 16, further comprising selecting a fluid having a predetermined density to control the reflection coefficient of the reflector.
18. A string for use in a wellbore, comprising:
a carrier structure; and
an acoustic resonance device coupled to the carrier structure, the acoustic resonance device adapted to generate a vibration in the carrier structure.
19. The string of claim 18, wherein the acoustic resonance device comprises a housing section and an acoustic wave generating device, the housing section containing a fluid and the acoustic wave generating device adapted to generate an acoustic wave in the fluid.
20. The string of claim 19, wherein the acoustic resonance device further comprises a reflector to reflect the acoustic wave.
21. The string of claim 20, wherein the reflector comprises an orifice.
22. The string of claim 21, wherein the housing section defines a first flow area on one side of the orifice, the string further comprising a conduit defining a second flow area on the other side of the orifice, the second flow area being less than the first flow area.
Description
    CROSS-REFERENCE TO RELATED APPLICATIONS
  • [0001]
    This application claims priority from Provisional Application No. 60/272,647 filed Mar. 1, 2001.
  • BACKGROUND OF THE INVENTION
  • [0002]
    1. Field of the Invention
  • [0003]
    The invention relates to methods and apparatus to vibrate a downhole component.
  • [0004]
    2. Description of the Related Art
  • [0005]
    To prepare a well for production of hydrocarbons, various operations are performed, including drilling and completion operations. In drilling a well, a drill bit is carried on the end of a drill pipe. In completing a well, various operations may be performed by carrying tools down on a tubing string (e.g., a coiled tubing or jointed pipe). As used here, the term “tubing string” is used to denote a rigid carrier or conveyance mechanism, such as a coiled tubing or drill pipe, that can be used to carry tools or fluids into a wellbore.
  • [0006]
    For a given well, the reach of a tool carried on a tubing string is limited by the propensity of the tubing string to lock up. As a tubing string is run into a wellbore, it has to overcome the frictional force between itself and the wall of the wellbore. The longer the length of the tubing string that is run into the wellbore, the greater the frictional force that is developed between the tubing string and the wellbore wall. When the frictional force becomes large enough, it will cause the tubing string to buckle, first into a sinusoidal shape and then into a helical shape. After helical buckling occurs, continuing to run the tubing string into the wellbore will eventually lead to a stage where further pushing of the tubing string will not result in further advancement of the tubing string. Such a stage is referred to as tubing string lockup. The depth of a tubing string lockup defines the maximum depth a tool can be delivered into the well.
  • [0007]
    Various factors affect (directly or indirectly) the maximum depth that a tubing string can be run into a wellbore. One factor is the friction coefficient between the tubing string and the wellbore. Another factor is the normal contact force between the tubing string and the wellbore, which is dependent on the weight of the tubing string and the stiffness of the tubing string. Generally, a lower friction coefficient or lower tubing string weight usually indicates that the tubing string can extend further into the wellbore. Also, higher bending stiffness tends to delay the occurrence of buckling, which may extend the reach of the tubing string into the wellbore.
  • [0008]
    Although useful in any wellbore, extending the reach of tubing strings into a wellbore has particular application in deviated or extended reach wells, for example. In recent years, many deviated or extended reach wells have been drilled to facilitate the recovery of hydrocarbons. Extended reach wells have been proven to significantly increase the recovery rate of hydrocarbon while reducing its associated cost. In general, the deeper one can drill or service extended reach wells, the higher the economic benefit. Despite many technical advances in the area of extended reach technology, it remains a technical challenge to drill or service an extended reach well.
  • [0009]
    Various solutions have been attempted or implemented to extend the reach of a tubing string in a wellbore. One is to reduce the contact force between the tubing string and the wellbore, such as by using different fluids inside and outside the tubing string to reduce the buoyancy weight of the tubing string or by using a more lightweight material for the tubing. Another technique is to delay or prevent the onset of helical buckling, which can be achieved by using larger diameter tubing. However, this increases the weight of the tubing string and reduces flexibility. Yet another approach uses a tractor to pull the end of tubing string into the well. Other approaches employ vibration to aid in friction reduction.
  • [0010]
    However, despite the various solutions that have been proposed or implemented, a need continues to exist for an improved method and apparatus to improve the reach of a tubing string in a wellbore.
  • BRIEF SUMMARY OF THE INVENTION
  • [0011]
    In general, according to one embodiment of the invention, an apparatus for generating a vibration in a tool string comprises a housing for storing fluid and adapted to be coupled to the tool string. A device is adapted to generate an acoustic resonance in the fluid, with the acoustic resonance in the fluid to create vibration in the tool string.
  • [0012]
    Other or alternative features will become apparent from the following description and drawings.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • [0013]
    [0013]FIG. 1 illustrates an embodiment of a tool attached to a tubing string in a wellbore, the tubing string including one or more vibration devices.
  • [0014]
    [0014]FIG. 2 illustrates an acoustic resonance vibration device in accordance with an embodiment of the invention.
  • [0015]
    [0015]FIG. 3 is a block diagram of some components of the acoustic resonance vibration device of FIG. 2.
  • DETAILED DESCRIPTION OF THE INVENTION
  • [0016]
    In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.
  • [0017]
    As used here, the terms “up” and “down”; “upward” and “downward”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention. However, when applied to apparatus and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or other relationship as appropriate.
  • [0018]
    Referring to FIG. 1, a tubing string includes a tool 18 carried on a tubing or pipe 14 (hereinafter referred to as “tubing” or “tubular conduit” or “tubular structure”) into a wellbore 10. In another embodiment, the structure that carries the tool 18 into the wellbore does not need to be tubular, but rather can be any other shape that is suitable for use in the wellbore as a rigid carrier or conveyance structure. As used here, a carrier structure is considered to be “rigid” if a conveyance force can be applied at one end of the carrier structure to move it downwardly into the wellbore. A rigid carrier structure is contrasted to non-rigid carrier structures such as wirelines or slicklines.
  • [0019]
    The wellbore 10 is lined with a casing 12, and has a generally vertical section as well as a deviated section 20. In other embodiments, the wellbore 10 can be a generally vertical well, a deviated well, or a horizontal well.
  • [0020]
    In accordance with some embodiments of the invention, one or more vibration devices 16 are mounted on the tubing string. In the illustrated example of FIG. 1, two vibration devices 16 a and 16 b are illustrated. In other examples, a single vibration device or more than two vibration devices may be used. By imparting vibration onto the tubing string, the maximum depth reachable by the tubing string in the wellbore 10 can be extended. Vibration of the tubing string helps to reduce the friction coefficient between the tubing string and the inner wall of the wellbore.
  • [0021]
    Referring to FIG. 2, in accordance with one embodiment of the invention, the vibration device 16 includes an acoustic resonance apparatus that generates vibration in the tubing string by creating resonance acoustic oscillations in fluid contained within a housing section 106. The upper end of the housing section 106 is connected to a tubing string 108, which in one example is coiled tubing. Alternatively, the housing section 106 may be connected to a downhole component. In yet another embodiment, the vibration device 16 may be attached at some other location along the tubing string 108 (instead of at the end of the tubing string 108). In the illustrated arrangement, the lower end of the housing section 106 is coupled to a controllable pulser 100, such as a phase-controlled pulser. A controller 105 regulates the frequency of the pulser 100. Example pulser systems include those described in U.S. Pat. Nos. 4,847,815 and 5,375,098, which are incorporated herein by reference.
  • [0022]
    An intermediate housing section 102 is coupled between the pulser 100 and the housing section 106. One or more sensors 103 may be attached to the intermediate housing section 102 to measure acoustic oscillations created in the fluid contained within housing sections 102 and 106. The sensors 103 communicate the measurements to the controller 105, which adjusts the frequency of the pulser 100 in response to the measurements to create acoustic waves within the vibration device 16.
  • [0023]
    A block diagram showing the electrical interconnection between various components of the vibration device 16 is illustrated in FIG. 3. Measurements collected by the sensors 103 are communicated as signals over communications line(s) 120 to the controller 105. The controller 105 contains a microprocessor, microcontroller, or other control device 124 to receive and process the measurements from the sensors 103. A memory or storage device 126 in the controller 105 stores instructions or data that are accessible by the control device 124. Based on the received measurements, the controller 105 generates signals communicated over communications line(s) 122 to the pulser 100. The signals carry control information to adjust the operating frequency of the pulser 100.
  • [0024]
    Referring again to FIG. 2, a reflector 109 is located at an upper end of the housing section 106. The reflector 109 generates a reflection for an acoustic wave (created by the pulser 100) traveling in the housing section 106. An orifice 107 in the reflector 109 allows communication of fluid from the tubing string 108 into the vibration device 16. In addition, fluid can flow from the housing section 106 into the tubing string 108 through the orifice 107, which creates a pressure drop in the housing section 106.
  • [0025]
    In one embodiment, the inner cross-sectional area of the housing section 106 is larger than the inner cross-sectional area of the tubing string 108. The housing section 106 has an inner diameter D1, and the tubing string 108 has an inner diameter D2 that is less than D1. The significance of the different cross-sectional areas is discussed below.
  • [0026]
    A characteristic (λ) of the reflector 109 is defined as λ = 2 Δ p ρ cV , ( Eq . 1 )
  • [0027]
    where ρ is the density of the fluid inside the housing section 106, Δp is the mean pressure drop across the reflector 109, c is the speed of sound in the fluid within the housing section 106, and V is the mean flow velocity below the reflector 109. The reflector coefficient R for the fluid below the orifice 107 is given by R = λ - 1 + Z λ + 1 + Z , ( Eq . 2 )
  • [0028]
    where Z = A 1 A t ,
  • [0029]
    A1 is the fluid flow area below the orifice 107 (inner cross-sectional area of housing section 106), and At is the fluid flow area above the orifice 107 (inner cross-sectional area of the tubing string 108).
  • [0030]
    Eq. 2 indicates that the reflection coefficient R can be increased by either increasing the pressure drop (Δp) across the orifice 107 or increasing the cross-sectional fluid flow area below the orifice 107 with respect to the cross-sectional fluid flow area above the orifice 107. An increase in the value of the reflection coefficient R indicates that the reflector 109 is able to reflect a larger percentage of the acoustic wave energy traveling in the fluid contained in the housing section 106. This enhances the ability to achieve acoustic resonance within the housing section 106.
  • [0031]
    The frequency of operation of the pulser 100 is set to correspond to a resonance frequency of the fluid within the housing section 106. The resonance frequency is a function of the fluid properties and the geometry of the housing, and thus it can be adjusted by different fluids or changing the length of the housing.
  • [0032]
    The use of resonance amplifies the dynamic pressure drop achievable by the pulser 100. If P is the pressure drop across the pulser 100 without acoustic resonance, α is the reflection coefficient of the reflector 109, and β is the reflection coefficient of the pulser 100, then the resonance pressure drop Pr through orifice 107 is calculated as P r = P 1 - αβ . ( Eq . 3 )
  • [0033]
    The values of the parameters α and β are derived by calculating R using Eq. 2. As an example, if α=0.8, β=0.9, then Pr=3.6P, which corresponds to about a 260% increase in pressure pulse magnitude by using the reflector 109 and a control system for adjusting the frequency of the pulser 100 (as compared to an apparatus that does not use the reflector 109).
  • [0034]
    While frequency of operation can be estimated in advance, the signals from the pressure sensors 103 are used to fine-tune the acoustic resonance apparatus. Since the distance between the pulser 100 and the sensors 103 and the distance between the pulser 100 and reflector 109 are known, the travel time between the pulser 100 and the reflector 109 can be calculated and from this the period of the desired resonance. If this period is shorter than the current operating period, then the operating frequency of the pulser 100 is increased accordingly; if the period is longer, then the operating frequency of the pulser 100 is decreased.
  • [0035]
    In operation, a tubing string (such as the one shown in FIG. 1) is lowered into the wellbore 10, with the tubing string coupled to at least one acoustic resonance apparatus. As used here, “coupled” means directly connected or attached, or indirectly connected or attached through one or more other elements. The acoustic resonance apparatus may be activated at the well surface, or alternatively, the acoustic resonance apparatus is activated once a tool reaches a predetermined depth at which vibration of the tubing string is deemed useful.
  • [0036]
    Once activated, acoustic waves are generated in the fluid contained in the housing section 106. A portion of the acoustic wave energy is reflected by the reflector 109. Sensors 103 detect the delay time periods between acoustic waves (those generated and those reflected), with measurements communicated to the controller 105. Based on the measurements, the controller 105 is able to vary the operating frequency of the pulser 100 to achieve acoustic resonance in the fluid.
  • [0037]
    The coefficient of reflection of the reflector 109 is controlled by selecting the flow area on the opposing sides of the orifice 107. In addition, the coefficient of reflection is controlled by varying the density of the fluid in the housing section 106.
  • [0038]
    While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover such modifications and variations as fall within the true spirit and scope of the invention.
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7264055Jun 15, 2005Sep 4, 2007Baker Hughes IncorporatedApparatus and method of applying force to a stuck object in a wellbore
US7382684Jun 13, 2006Jun 3, 2008Seispec, L.L.C.Method for selective bandlimited data acquisition in subsurface formations
US7575051Apr 21, 2005Aug 18, 2009Baker Hughes IncorporatedDownhole vibratory tool
US7599251Mar 14, 2008Oct 6, 2009Seispec, L.L.C.Method for selective bandlimited data acquisition in subsurface formations
US7986588Jul 26, 2011Seispec, L.L.C.Method for selective bandlimited data acquisition in subsurface formations
US8467266Oct 22, 2009Jun 18, 2013Seispec, L.L.C.Exploring a subsurface region that contains a target sector of interest
US8997855 *Sep 27, 2007Apr 7, 2015Baker Hughes IncorporatedReduction of expansion force via resonant vibration of a swage
US9036451May 20, 2013May 19, 2015Seispec, LlcExploring a subsurface region that contains a target sector of interest
US9109442 *Aug 15, 2012Aug 18, 2015Nov Downhole Eurasia LimitedDownhole pulse-generating apparatus
US9200494Sep 29, 2011Dec 1, 2015Gary James BAKKENVibration tool
US20050257931 *Jun 15, 2005Nov 24, 2005Baker Hughes IncorporatedApparatus and method of applying force to a stuck object in a wellbore
US20060237187 *Apr 21, 2005Oct 26, 2006Stoesz Carl WDownhole vibratory tool
US20070286019 *Jun 13, 2006Dec 13, 2007Love Jeff LMethod for selective bandlimited data acquisition in subsurface formations
US20080073076 *Sep 27, 2007Mar 27, 2008Baker Hughes IncorporatedReduction of expansion force via resonant vibration of a swage
US20080205196 *Mar 14, 2008Aug 28, 2008Seispec, L.L.C.Method for selective bandlimited data acquisition in subsurface formations
US20090310442 *Jul 13, 2009Dec 17, 2009Seispec, LlcMethod for selective bandlimited data acquisition in subsurface formations
US20100110831 *Oct 22, 2009May 6, 2010Seispec, LlcExploring a subsurface region that contains a target sector of interest
US20110290559 *Dec 1, 2011Rodney Paul FSurface real-time processing of downhole data
US20130043022 *Feb 21, 2013Ian ForsterDownhole pulse-generating apparatus
Classifications
U.S. Classification166/249, 166/177.6
International ClassificationE21B31/00
Cooperative ClassificationE21B31/005
European ClassificationE21B31/00C
Legal Events
DateCodeEventDescription
Jan 18, 2002ASAssignment
Owner name: SCHLUMBERGER TECHNOLOGY CORPORATION, TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:ZHENG, SHUNFENG;JEFFRYES, BENJAMIN P.;REEL/FRAME:012519/0325;SIGNING DATES FROM 20020116 TO 20020117
Mar 18, 2002ASAssignment
Owner name: SCHLUMBERGER TECHNOLOGY CORPORATION, TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:ZHENG, SHUNFENG;JEFFRYES, BENJAMIN P.;REEL/FRAME:012731/0097;SIGNING DATES FROM 20020305 TO 20020306