WO2008127838A1 - Devices and methods for translating tubular members within a well bore - Google Patents
Devices and methods for translating tubular members within a well bore Download PDFInfo
- Publication number
- WO2008127838A1 WO2008127838A1 PCT/US2008/057703 US2008057703W WO2008127838A1 WO 2008127838 A1 WO2008127838 A1 WO 2008127838A1 US 2008057703 W US2008057703 W US 2008057703W WO 2008127838 A1 WO2008127838 A1 WO 2008127838A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- vibratory
- string
- tubular members
- signal
- wellbore
- Prior art date
Links
- 238000000034 method Methods 0.000 title claims abstract description 14
- 239000012530 fluid Substances 0.000 claims description 13
- 230000004044 response Effects 0.000 claims description 10
- 230000000712 assembly Effects 0.000 claims description 3
- 238000000429 assembly Methods 0.000 claims description 3
- 238000010348 incorporation Methods 0.000 claims 3
- 238000005553 drilling Methods 0.000 description 9
- 230000015572 biosynthetic process Effects 0.000 description 5
- 238000005755 formation reaction Methods 0.000 description 5
- 238000001514 detection method Methods 0.000 description 4
- 239000000463 material Substances 0.000 description 2
- 230000004913 activation Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 230000035515 penetration Effects 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 239000002689 soil Substances 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
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
- E21B31/00—Fishing for or freeing objects in boreholes or wells
- E21B31/005—Fishing for or freeing objects in boreholes or wells using vibrating or oscillating means
Definitions
- the invention relates generally to devices and methods for releasing a stuck portion of a tubular string from within a wellbore and thereby translating tubular members within a wellbore.
- the invention relates to tubular string arrangements which incorporate vibratory devices within the string itself.
- the invention relates to the use of rotational vibration devices in association with tubular strings in wellbores to help prevent and respond to sticking conditions.
- the invention provides devices and methods for translating casing within a wellbore and, as a result, effectively freeing a stuck tubular string within a wellbore.
- multiple vibrator devices are incorporated into a tubular string, such as a drill string.
- Each of the vibratory devices may be turned on or off independently, as needed, to help effectively free the tubular string from a stuck condition.
- each of the vibrators is a rotary vibrator device that can be incorporated into the tubular string and, where required, provide an open central flowbore which will allow drilling mud, tools, and the like to be passed through the vibrator so that normal operations need not be interrupted by operation of the vibrator.
- the vibrator includes a housing that encloses a rotary vibratory element, a motor to rotate the vibratory element, and a power source.
- the vibrator includes an actuation mechanism for selectively starting and stopping the motor.
- pressure pulse identification is used to communicate with the vibrators.
- each vibrator has a receiver adapted to receive a specific pressure pulse activation signal that is provided from the surface of the wellbore.
- each of the vibrators is provided with a detector for detecting signals indicative of wellbore conditions.
- the signals may be MWD (measurement-while-drilling) or LWD (logging-while-drilling) pulsed signals of a type known in the art.
- a tubular string is constructed having one or more vibrators positioned within.
- a plurality of vibrators are incorporated into the tubular string at predetermined intervals.
- the vibrators incorporated therein are selectively actuated to help free the tubular string from its stuck condition.
- signals be sent from the surface of the wellbore to determine the approximate location of the point at which the tubular string is stuck. Once the location of the stuck portion of the tubular string is determined, the vibrator or vibrators that are located proximate the sticking point are actuated to create one or more vibrations proximate the sticking point.
- Figure 1 is a side, cross-sectional view depicting an exemplary wellbore containing a drill string with a plurality of vibratory assemblies constructed in accordance with the present invention.
- Figure 2 is a side, cross-sectional view of an exemplary vibratory device used within the vibratory assembly shown in Figure 1.
- Figure 3 is an isometric view of an exemplary vibratory element used within the vibratory device shown in Figure 2.
- Figure 4 is a top view of the vibratory element shown in Figure 3.
- Figure 1 illustrates a wellbore 10 that has been drilled from drilling rig 12 on the surface 14 downward through earth 16 and formation zones 18, 20, 22.
- the wellbore 10 has a deviated portion 24. It is noted that, while the deviated portion 24 is shown as being substantially horizontal, it may be angled in other directions as well.
- the wellbore 10 has a cased portion 26 proximate the surface 14 and an uncased portion 28.
- a tubular string in the form of a drill string 30 is disposed within the wellbore 10 and includes a plurality of drill string sections 32, 34, 36, 38, 40 that are secured together in a manner well known in the art.
- An axial fluid flowbore 42 is defined along the length of the drill string 30.
- the lower end of the drill string 30 carries a bottom hole assembly (BHA) 44 with drill bit.
- Vibration subs 46, 48, 50, 52 are incorporated within the drill string 30 in between each adjacent sections of the drill string 30.
- Figure 1 illustrates a vibration sub disposed between each of the drill string sections 32, 34, 36, 38 and 40, this need not be the case. It is preferred that vibration subs be located within the drill string 30 at predetermined intervals which correspond to expected wellbore conditions at the depths at which those portions of the drill string will be located. Thus, there may be long stretches of drill string that have no vibration subs incorporated in them and other stretches of drill string that have a number of vibrators located therein.
- the surface 14 will include a pressure pulse generator 54, of a type known in the art for generating fluid pulses within the fluid flowbore 42 of the drill string 30, and a controller 56 operably associated with the generator 54.
- Figure 1 illustrates a stuck position 58 in the uncased well portion 28 which has resulted from the formation 20 surrounding the wellbore 10 caving in and partially burying the drill string 30.
- FIG. 2 depicts an exemplary vibratory assembly 60, which may be representative of each of the vibration subs 46, 48, 50, 52 incorporated into the drill string 30.
- the vibratory assembly 60 includes a housing 62 with upper and lower axial ends 64, 66, respectively.
- the housing 62 defines a central axial flowbore 68 that extends through the housing 62.
- the upper end 64 is provided with a box-type threaded connection while the lower end 66 is provided with a pin-type threaded connection so that the vibratory assembly 60 may be threadedly affixed to neighboring components in the drill string 30.
- a compartment 70 is formed within the vibratory assembly 60. In Figure 2, the compartment 70 is an annular space formed between the housing 62 and cover member 72.
- the compartment 70 houses a power source 74, which may be a battery and an electric motor 76, which is operably associated with the power source 74.
- the motor 76 turns drive gearing 78 to rotate vibratory element 80 within the compartment 70.
- Figures 3 and 4 illustrates an exemplary vibratory element 80 apart from the other components.
- the vibratory element 80 includes an annular ring body 82 that is heavier upon one half 84 of the body 82 than the other half 86. In the depicted embodiment, the half 84 is heavier than the half 86 because of the presence of a plurality of blind bores 88 that are disposed within the half 86, thereby removing mass from that half.
- Rotation of the vibratory element 80 within the compartment 70 will be eccentric due to the off-center location for the center of mass for the element 80.
- the vibratory element 80 When rotated by the motor 76 and the gearing 78, the vibratory element 80 will cause the housing 62 to wobble or vibrate due to the eccentric motion of the element 80.
- eccentric vibration of the housing 62 could be created by, for example, rotation of a heavy fluid within an annular chamber within the housing 62 could cause a similar vibratory effect.
- a fluid conduit 90 is formed within the housing 62 of the vibratory assembly 60 and extends from the central flowbore 68 to the compartment 70.
- a sensor 92 is located within the compartment 70 and is associated with the fluid conduit 90 so that fluid from the flowbore 68 will be transmitted to the sensor 92 during typical operation of the drill string 30.
- the sensor 92 is selected to detect MWD or LWD signals within a drilling mud column passing through the flowbore 68.
- the sensor 92 is operably associated with a programmable processor/controller 94.
- the processor/controller 94 is also operably interconnected with the power source 74 and the motor 76.
- the vibratory subs 46, 48, 50, 52 is operated to free the drill string and allow drilling to continue.
- the subs 46, 48, 50, 52 are selectively chosen and actuated from the surface 14.
- the drilling operation is halted and an attempt is made to determine the approximate location of the sticking point 58 within the wellbore 10. This can be done, for example, by pulling upward on the drill string and measuring the amount of stretch that the upper portion of the drill string 30 provides. Using a measured or approximated modulus of elasticity for the drill string 30, the approximate distance along the drill string 30 to the stuck point 58 can be determined.
- each of the vibratory subs 46, 48, 50, 52 can be selectively operated using a distinct pulsed signal from the pulse generator 54 at the surface 14.
- the processor/controller 94 of each of the vibrator subs 46, 48, 50, 52 must be preprogrammed to actuate its respective motor 74 in response to receipt of a unique signal from the sensor 92.
- a unique pulsed signal is generated by the pulse generator 54.
- the pulsed signal is transmitted through the axial flowbore 42 of the drill string 30. Due to the presence of the fluid conduit 90 in the housing 62, the pulsed signal will be detected by the sensor 92 and the processor/controller 94 will actuate the motor 74 upon detection of the correct unique pulsed signal.
- An alternative method of operation of the vibratory subs 46, 48, 50, 52 allows automatic operation of the subs 46, 48, 50, 52 in response to one or more predetermined wellbore conditions.
- the processor/controllers 94 of the various vibration subs 46, 48, 50, 52 are preprogrammed to actuate their respective motors 74 upon detection by the sensor 92 of a particular predetermined wellbore condition or conditions.
- the sensor 92 is one that is able to detect MWD or LWD signals.
- the BHA 44 must be provided with an MWD or LWD pulser system, of a type well-known in the art for detecting wellbore conditions proximate the BHA 44 and transmitting fluid pulse signals representative of those conditions through the flowbore 42 of the drill string 30.
- the pulsed signals are traditionally received by a receiver located at the surface 14 of the wellbore 10 and are then interpreted.
- Typical wellbore conditions detected and transmitted by MWD/LWD systems include temperature, pressure, depth, weight on bit (WOB), drill string torque, and rate of penetration.
- the processor/controllers 94 of the vibration subs 46, 48, 50, and 52 are preprogrammed to actuate their respective motors 74 in response to detected wellbore condition of torque, as detected by the BHA 44.
- the processor/controllers 94 of one or more of the vibration subs 46, 48, 50, 52 are programmed so as to actuate their respective motors 74 upon detection of a predetermined level of torque, as detected by the BHA.
- the processors/controllers 94 of one or more of the vibration subs 46, 48, 50, 52 may be preprogrammed to actuate their respective motors 74 upon detection that the BHA 44 has reached a particular predetermined depth. The depth would correspond, for example, to a particularly unstable formation or formations. Other measured MWD/LWD parameters may be used as well to selectively operate the subs 46, 48, 50, 52.
- the several vibration subs 46, 48, 50, 52 may be collectively considered to be a vibratory system 100 since they act in accordance with one of the predetermined control schemes outlined above. It is noted that the vibratory system 100 of the present invention is not confined to use with a drill string, but may also be adapted for use with other strings of tubular members, such as production tubing strings or work strings. In the example outlined above, it will be appreciated that once vibration of the selected vibration sub or subs begins, the drill string 30 becomes unstuck by the localized vibration of the vibration sub 52 proximate the stuck location 58. The vibration will cause the surrounding solids to be broken up and the drill string 30 to be translated within the wellbore 10.
- vibrations subs 46, 48, 50, 52 can be vibrated during normal operation of the drill string 30 (i.e., when the drill string 30 is not stuck) in order to help prevent sticking conditions from occurring.
- vibrations subs 46, 48, 50, 52 can be vibrated during normal operation of the drill string 30 (i.e., when the drill string 30 is not stuck) in order to help prevent sticking conditions from occurring.
Landscapes
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Marine Sciences & Fisheries (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
Abstract
Devices and methods for translating tubulars within a wellbore and, as a result, effectively freeing a stuck tubular string within a wellbore. One or more vibrator devices are incorporated into a tubular string, such as a drill string. Each of the vibratory devices may be turned on or off independently, as needed, to help effectively free the tubular string from a stuck condition.
Description
DEVICES AND METHODS FOR TRANSLATING TUBULAR MEMBERS WITHIN A WELL BORE
BACKGROUND OF THE INVENTION
1. Field of the Invention
[0001] The invention relates generally to devices and methods for releasing a stuck portion of a tubular string from within a wellbore and thereby translating tubular members within a wellbore. In particular aspects, the invention relates to tubular string arrangements which incorporate vibratory devices within the string itself. In other aspects, the invention relates to the use of rotational vibration devices in association with tubular strings in wellbores to help prevent and respond to sticking conditions.
2. Description of the Related Art
[0002] The process of drilling through open hole at bottom of cased wellbore requires that the drill string pass through multiple layers, or zones, of formation. Depending upon the composition, some of these layers are problematic because they do not hold their drill diameter well. They are prone to caving in and sloughing off. The drill string tends to becomes stuck in these areas. This problem is complicated when portions of the wellbore are deviated or even horizontal as lower portions of the drill string will tend to contact the side of the wellbore and the weight of the drill string will create increased friction and drag to inhibit movement of the drill string along the wellbore, increasing the likelihood that the drill string will become stuck. [0003] It is noted that the problems of sticking is not unique to drill strings and, in fact, is
inherent in other varieties of tubular strings used in wellbores, such as casing and liner drilling strings, work strings, and production strings, whether used in cased or uncased bores. Sticking can occur during run-in as well as retrieval of a tubular string from a wellbore.
[0004] Attempts to free conventional tubular strings from a stuck condition are often done using a set of impact jars that are translated through the drill string to the total depth and then engaged and actuated to try to unstick the drill string. However, if the sticking zone is significantly distant (i.e., above) the location of effective jarring, the jar attempt may fail. In these cases, it would be desirable to locate a vibratory device proximate the sticking zone in order to effectively unstick the string, as vibration is effective in loosening surrounding soils or debris that may be causing the tubular string to be stuck. In addition, vibration is useful in overcoming frictional jams within the wellbore. However, there are practical difficulties in placing an effective vibration device close to the stuck location. The flowbore defined within a drill string is generally too small to run in an effective vibration device. [0005] U.S. Patent Publication No. US 2005/0257931 describes a method and apparatus for helping to remove a stuck object in a wellbore wherein a tubular assembly includes a work string with a vibratory apparatus that may have been incorporated therein before its initial tripping into the wellbore. However, this system may not be sufficient in all situations to free a stuck string. [0006] The present invention addresses the problems of the prior art.
SUMMARY OF THE INVENTION
[0007] The invention provides devices and methods for translating casing within a wellbore and, as a result, effectively freeing a stuck tubular string within a wellbore. In a
preferred embodiment, multiple vibrator devices are incorporated into a tubular string, such as a drill string. Each of the vibratory devices may be turned on or off independently, as needed, to help effectively free the tubular string from a stuck condition. [0008] In a preferred embodiment, each of the vibrators is a rotary vibrator device that can be incorporated into the tubular string and, where required, provide an open central flowbore which will allow drilling mud, tools, and the like to be passed through the vibrator so that normal operations need not be interrupted by operation of the vibrator. The vibrator includes a housing that encloses a rotary vibratory element, a motor to rotate the vibratory element, and a power source. In addition, the vibrator includes an actuation mechanism for selectively starting and stopping the motor. In one embodiment, pressure pulse identification is used to communicate with the vibrators. In this embodiment, each vibrator has a receiver adapted to receive a specific pressure pulse activation signal that is provided from the surface of the wellbore. In a further embodiment, each of the vibrators is provided with a detector for detecting signals indicative of wellbore conditions. The signals may be MWD (measurement-while-drilling) or LWD (logging-while-drilling) pulsed signals of a type known in the art.
[0009] In operation, a tubular string is constructed having one or more vibrators positioned within. In a preferred embodiment, a plurality of vibrators are incorporated into the tubular string at predetermined intervals. Should the tubular string become struck during normal operation in the wellbore, the vibrators incorporated therein are selectively actuated to help free the tubular string from its stuck condition. To do this, it is preferred that signals be sent from the surface of the wellbore to determine the approximate location of the point at which the tubular string is stuck. Once the location of the stuck portion of
the tubular string is determined, the vibrator or vibrators that are located proximate the sticking point are actuated to create one or more vibrations proximate the sticking point.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] Figure 1 is a side, cross-sectional view depicting an exemplary wellbore containing a drill string with a plurality of vibratory assemblies constructed in accordance with the present invention.
[0011] Figure 2 is a side, cross-sectional view of an exemplary vibratory device used within the vibratory assembly shown in Figure 1.
[0012] Figure 3 is an isometric view of an exemplary vibratory element used within the vibratory device shown in Figure 2. [0013] Figure 4 is a top view of the vibratory element shown in Figure 3.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS [0014] Figure 1 illustrates a wellbore 10 that has been drilled from drilling rig 12 on the surface 14 downward through earth 16 and formation zones 18, 20, 22. The wellbore 10 has a deviated portion 24. It is noted that, while the deviated portion 24 is shown as being substantially horizontal, it may be angled in other directions as well. The wellbore 10 has a cased portion 26 proximate the surface 14 and an uncased portion 28. [0015] A tubular string in the form of a drill string 30 is disposed within the wellbore 10 and includes a plurality of drill string sections 32, 34, 36, 38, 40 that are secured together in a manner well known in the art. An axial fluid flowbore 42 is defined along the length of the drill string 30. The lower end of the drill string 30 carries a bottom hole assembly (BHA) 44 with drill bit. Vibration subs 46, 48, 50, 52 are incorporated within the drill string 30 in
between each adjacent sections of the drill string 30. Although Figure 1 illustrates a vibration sub disposed between each of the drill string sections 32, 34, 36, 38 and 40, this need not be the case. It is preferred that vibration subs be located within the drill string 30 at predetermined intervals which correspond to expected wellbore conditions at the depths at which those portions of the drill string will be located. Thus, there may be long stretches of drill string that have no vibration subs incorporated in them and other stretches of drill string that have a number of vibrators located therein. In particular embodiments, the surface 14 will include a pressure pulse generator 54, of a type known in the art for generating fluid pulses within the fluid flowbore 42 of the drill string 30, and a controller 56 operably associated with the generator 54.
[0016] Figure 1 illustrates a stuck position 58 in the uncased well portion 28 which has resulted from the formation 20 surrounding the wellbore 10 caving in and partially burying the drill string 30.
[0017] Figure 2 depicts an exemplary vibratory assembly 60, which may be representative of each of the vibration subs 46, 48, 50, 52 incorporated into the drill string 30. The vibratory assembly 60 includes a housing 62 with upper and lower axial ends 64, 66, respectively. The housing 62 defines a central axial flowbore 68 that extends through the housing 62. The upper end 64 is provided with a box-type threaded connection while the lower end 66 is provided with a pin-type threaded connection so that the vibratory assembly 60 may be threadedly affixed to neighboring components in the drill string 30. A compartment 70 is formed within the vibratory assembly 60. In Figure 2, the compartment 70 is an annular space formed between the housing 62 and cover member 72. The compartment 70 houses a power source 74, which may be a battery and an electric motor
76, which is operably associated with the power source 74. The motor 76 turns drive gearing 78 to rotate vibratory element 80 within the compartment 70. [0018] Figures 3 and 4 illustrates an exemplary vibratory element 80 apart from the other components. The vibratory element 80 includes an annular ring body 82 that is heavier upon one half 84 of the body 82 than the other half 86. In the depicted embodiment, the half 84 is heavier than the half 86 because of the presence of a plurality of blind bores 88 that are disposed within the half 86, thereby removing mass from that half. Rotation of the vibratory element 80 within the compartment 70 will be eccentric due to the off-center location for the center of mass for the element 80. When rotated by the motor 76 and the gearing 78, the vibratory element 80 will cause the housing 62 to wobble or vibrate due to the eccentric motion of the element 80. It is noted that one can create an eccentric vibratory element in a number of alternative ways as well. For example, two halves of an annular element could be made from two separate materials, with one of the materials being of a lighter weight than the other half. Additionally, eccentric vibration of the housing 62 could be created by, for example, rotation of a heavy fluid within an annular chamber within the housing 62 could cause a similar vibratory effect.
[0019] Referring once again to Figure 2, it is noted that a fluid conduit 90 is formed within the housing 62 of the vibratory assembly 60 and extends from the central flowbore 68 to the compartment 70. A sensor 92 is located within the compartment 70 and is associated with the fluid conduit 90 so that fluid from the flowbore 68 will be transmitted to the sensor 92 during typical operation of the drill string 30. The sensor 92 is selected to detect MWD or LWD signals within a drilling mud column passing through the flowbore 68. The sensor 92 is operably associated with a programmable processor/controller 94. The
processor/controller 94 is also operably interconnected with the power source 74 and the motor 76.
[0020] If, during normal operation, the drill string 30 should become stuck within the wellbore 10, one or more of the vibratory subs 46, 48, 50, 52 is operated to free the drill string and allow drilling to continue. In one embodiment, the subs 46, 48, 50, 52 are selectively chosen and actuated from the surface 14. First, the drilling operation is halted and an attempt is made to determine the approximate location of the sticking point 58 within the wellbore 10. This can be done, for example, by pulling upward on the drill string and measuring the amount of stretch that the upper portion of the drill string 30 provides. Using a measured or approximated modulus of elasticity for the drill string 30, the approximate distance along the drill string 30 to the stuck point 58 can be determined. Thereafter, the vibratory sub or subs that are located closest to the stuck point 58 are operated to cause vibration of the drill string 30 proximate the stuck point 58. In the instance depicted in Figure 1 , the vibratory sub 52 would be actuated. [0021] In this method of operation, each of the vibratory subs 46, 48, 50, 52 can be selectively operated using a distinct pulsed signal from the pulse generator 54 at the surface 14. In order to accomplish this, the processor/controller 94 of each of the vibrator subs 46, 48, 50, 52 must be preprogrammed to actuate its respective motor 74 in response to receipt of a unique signal from the sensor 92. In order to actuate the vibratory sub 52, a unique pulsed signal is generated by the pulse generator 54. The pulsed signal is transmitted through the axial flowbore 42 of the drill string 30. Due to the presence of the fluid conduit 90 in the housing 62, the pulsed signal will be detected by the sensor 92 and
the processor/controller 94 will actuate the motor 74 upon detection of the correct unique pulsed signal.
[0022] An alternative method of operation of the vibratory subs 46, 48, 50, 52 allows automatic operation of the subs 46, 48, 50, 52 in response to one or more predetermined wellbore conditions. In this embodiment, the processor/controllers 94 of the various vibration subs 46, 48, 50, 52 are preprogrammed to actuate their respective motors 74 upon detection by the sensor 92 of a particular predetermined wellbore condition or conditions. In a currently preferred embodiment, the sensor 92 is one that is able to detect MWD or LWD signals. In this embodiment, of course, the BHA 44 must be provided with an MWD or LWD pulser system, of a type well-known in the art for detecting wellbore conditions proximate the BHA 44 and transmitting fluid pulse signals representative of those conditions through the flowbore 42 of the drill string 30. The pulsed signals are traditionally received by a receiver located at the surface 14 of the wellbore 10 and are then interpreted. Typical wellbore conditions detected and transmitted by MWD/LWD systems include temperature, pressure, depth, weight on bit (WOB), drill string torque, and rate of penetration. In a particularly preferred embodiment of the present invention, the processor/controllers 94 of the vibration subs 46, 48, 50, and 52 are preprogrammed to actuate their respective motors 74 in response to detected wellbore condition of torque, as detected by the BHA 44. The processor/controllers 94 of one or more of the vibration subs 46, 48, 50, 52 are programmed so as to actuate their respective motors 74 upon detection of a predetermined level of torque, as detected by the BHA.
[0023] Alternately, the processors/controllers 94 of one or more of the vibration subs 46, 48, 50, 52 may be preprogrammed to actuate their respective motors 74 upon detection that the BHA 44 has reached a particular predetermined depth. The depth would correspond, for example, to a particularly unstable formation or formations. Other measured MWD/LWD parameters may be used as well to selectively operate the subs 46, 48, 50, 52.
[0024] The several vibration subs 46, 48, 50, 52 may be collectively considered to be a vibratory system 100 since they act in accordance with one of the predetermined control schemes outlined above. It is noted that the vibratory system 100 of the present invention is not confined to use with a drill string, but may also be adapted for use with other strings of tubular members, such as production tubing strings or work strings. In the example outlined above, it will be appreciated that once vibration of the selected vibration sub or subs begins, the drill string 30 becomes unstuck by the localized vibration of the vibration sub 52 proximate the stuck location 58. The vibration will cause the surrounding solids to be broken up and the drill string 30 to be translated within the wellbore 10. [0025] It is also noted that one or more of the vibrations subs 46, 48, 50, 52 can be vibrated during normal operation of the drill string 30 (i.e., when the drill string 30 is not stuck) in order to help prevent sticking conditions from occurring. [0026] Those of skill in the art will recognize that numerous modifications and changes may be made to the exemplary designs and embodiments described herein and that the invention is limited only by the claims that follow and any equivalents thereof.
Claims
1. A vibratory system for translating a string of tubular members within a wellbore, comprising: at least one vibratory assembly incorporated into the string of tubular members, the vibratory assembly creating vibration in response to a signal transmitted along the string of tubular members.
2. The vibratory system of claim 1 wherein there are a plurality of vibratory assemblies incorporated into the string of tubular members, and each of said vibratory assemblies is actuated independently.
3. The vibratory system of claim 1 wherein the vibratory assembly comprises: a housing having first and second axial ends adapted for incorporation into the string of tubular members; the housing defining a central axial fluid flowbore; an annular compartment defined within the housing; a vibratory element contained within the compartment, the vibratory element causing vibration of the housing when rotated within the compartment; and ; a motor for rotating the vibratory element within the compartment.
4. The vibratory system of claim 3 wherein the vibratory assembly further '. comprises:
; a sensor for detecting a condition within the fluid flowbore and generating a
\ signal representative thereof; and
; a programmable processor/controller to receive the signal from the sensor and
; selectively operate the motor in response thereto.
5. The vibratory system of claim 1 wherein the signal comprises a pulsed signal : provided from a surface location.
6. The vibratory system of claim 1 wherein the signal comprises an MWD/LWD
: signal transmitted from an MWD/LWD pulser within the string of tubular members along i a flowbore defined within the string of tubular members.
7. The vibratory system of claim 6 wherein the processor/controller is programmed : to actuate the motor in response to a predetermined level of drill string torque detected i within the MWD/LWD pulser signal.
8. The vibratory system of claim 6 wherein the processor/controller is programmed • to actuate the motor in response to a predetermined depth detected within the i MWD/LWD pulser signal.
9. A vibratory assembly for incorporation within a string of tubular members and selectively actuatable to help free the string of tubular members from a stuck condition within a wellbore, the vibratory assembly comprising: a housing having first and second axial ends adapted for incorporation into the string of tubular members; the housing defining a central axial fluid flowbore; an annular compartment defined within the housing; a vibratory element contained within the compartment, the vibratory element causing vibration of the housing when rotated within the compartment; and a motor for rotating the vibratory element within the compartment.
10. The vibratory assembly of claim 9 further comprising: a sensor for detecting a condition within the fluid flowbore and generating a signal representative thereof.
11. The vibratory assembly of claim 10 further comprising a programmable processor/controller to receive the signal from the sensor and selectively operate the motor in response thereto.
12. The vibratory assembly of claim 11 wherein the processor/controller is programmed to actuate the motor in response to a predetermined level of drill string torque detected within an MWD/LWD pulser signal.
13. The vibratory assembly of claim 11 wherein the processor/controller is programmed to actuate the motor in response to a predetermined depth detected within an MWD/LWD pulser signal.
14. The vibratory assembly of claim 9 wherein the vibratory element comprises an annular ring body having first and second ring portions and wherein the first ring portion is heavier than the second ring portion.
15. A method of translating a string of tubular members within a wellbore comprising the steps of: incorporating at least one vibratory assembly into a string of tubular members; disposing the string of tubular members and at least one vibratory assembly into a wellbore; actuating the at least one vibratory assembly via signal transmitted along the string of tubular members to vibrate and thereby permit free movement of the string of tubular members within the wellbore.
16. The method of claim 15 wherein the step of actuating the at least one vibratory assembly further comprises transmitting an MWD/LWD signal to the vibratory assembly representative of at least one wellbore condition.
17. The method of claim 15 wherein the step of actuating the at least one vibratory assembly further comprises transmitting signal from a surface location.
18. The method of claim 15 further comprising the step of determining an approximate location of a stuck location within the wellbore prior to actuating the at least one vibratory assembly.
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US11/787,380 US20080251254A1 (en) | 2007-04-16 | 2007-04-16 | Devices and methods for translating tubular members within a well bore |
US11/787,380 | 2007-04-16 |
Publications (1)
Publication Number | Publication Date |
---|---|
WO2008127838A1 true WO2008127838A1 (en) | 2008-10-23 |
Family
ID=39643991
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2008/057703 WO2008127838A1 (en) | 2007-04-16 | 2008-03-20 | Devices and methods for translating tubular members within a well bore |
Country Status (2)
Country | Link |
---|---|
US (1) | US20080251254A1 (en) |
WO (1) | WO2008127838A1 (en) |
Families Citing this family (20)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
CA2753595A1 (en) * | 2009-02-26 | 2010-09-02 | Frank's International, Inc. | Downhole vibration apparatus and method |
US8210251B2 (en) * | 2009-04-14 | 2012-07-03 | Baker Hughes Incorporated | Slickline conveyed tubular cutter system |
US8191623B2 (en) * | 2009-04-14 | 2012-06-05 | Baker Hughes Incorporated | Slickline conveyed shifting tool system |
US20100288492A1 (en) * | 2009-05-18 | 2010-11-18 | Blackman Michael J | Intelligent Debris Removal Tool |
GB2470762A (en) * | 2009-06-04 | 2010-12-08 | Lance Stephen Davis | Method for generating transverse vibrations in a well bore tool. |
US20120160476A1 (en) | 2010-12-22 | 2012-06-28 | Bakken Gary James | Vibration tool |
US9109411B2 (en) | 2011-06-20 | 2015-08-18 | Schlumberger Technology Corporation | Pressure pulse driven friction reduction |
US9133671B2 (en) | 2011-11-14 | 2015-09-15 | Baker Hughes Incorporated | Wireline supported bi-directional shifting tool with pumpdown feature |
US9702192B2 (en) * | 2012-01-20 | 2017-07-11 | Schlumberger Technology Corporation | Method and apparatus of distributed systems for extending reach in oilfield applications |
US9540895B2 (en) * | 2012-09-10 | 2017-01-10 | Baker Hughes Incorporated | Friction reduction assembly for a downhole tubular, and method of reducing friction |
EP2917458B1 (en) | 2012-10-23 | 2018-08-22 | Saudi Arabian Oil Company | Vibrator sub |
US9500045B2 (en) | 2012-10-31 | 2016-11-22 | Canrig Drilling Technology Ltd. | Reciprocating and rotating section and methods in a drilling system |
US20140126330A1 (en) * | 2012-11-08 | 2014-05-08 | Schlumberger Technology Corporation | Coiled tubing condition monitoring system |
US10184333B2 (en) | 2012-11-20 | 2019-01-22 | Halliburton Energy Services, Inc. | Dynamic agitation control apparatus, systems, and methods |
BR112015010754A2 (en) * | 2012-11-20 | 2017-07-11 | Halliburton Energy Services Inc | appliance, system and method implemented by processor |
US9470055B2 (en) | 2012-12-20 | 2016-10-18 | Schlumberger Technology Corporation | System and method for providing oscillation downhole |
US9222316B2 (en) | 2012-12-20 | 2015-12-29 | Schlumberger Technology Corporation | Extended reach well system |
US9506318B1 (en) | 2014-06-23 | 2016-11-29 | Solid Completion Technology, LLC | Cementing well bores |
WO2019083516A1 (en) * | 2017-10-24 | 2019-05-02 | Halliburton Energy Services, Inc. | Agitator for use with a drill string |
CA3057030A1 (en) * | 2019-09-27 | 2021-03-27 | Complete Directional Services Ltd. | Tubing string with agitator, tubing drift hammer tool, and related methods |
Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US4384625A (en) * | 1980-11-28 | 1983-05-24 | Mobil Oil Corporation | Reduction of the frictional coefficient in a borehole by the use of vibration |
EP1239112A2 (en) * | 2001-03-01 | 2002-09-11 | Schlumberger Technology B.V. | Method and apparatus to vibrate a downhole component |
WO2003012250A1 (en) * | 2001-07-26 | 2003-02-13 | Xl Technology Ltd | Downhole vibrating device |
GB2383356A (en) * | 2001-12-18 | 2003-06-25 | Schlumberger Holdings | Drill String Telemetry System with Reflector |
Family Cites Families (22)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2972380A (en) * | 1956-02-20 | 1961-02-21 | Jr Albert G Bodine | Acoustic method and apparatus for moving objects held tight within a surrounding medium |
US3578081A (en) * | 1969-05-16 | 1971-05-11 | Albert G Bodine | Sonic method and apparatus for augmenting the flow of oil from oil bearing strata |
DE2133561B2 (en) * | 1971-07-06 | 1973-05-17 | Bauer, Karlheinz, Dr Ing , 8898 Schrobenhausen | DEEP RUETTLER FOR COMPACTING THE SOIL AND MAKING DRILLING HOLES IN THE SOIL |
US4236580A (en) * | 1978-04-04 | 1980-12-02 | Bodine Albert G | Method and apparatus for sonically extracting oil well liners |
GB8612019D0 (en) * | 1986-05-16 | 1986-06-25 | Shell Int Research | Vibrating pipe string in borehole |
US4815328A (en) * | 1987-05-01 | 1989-03-28 | Bodine Albert G | Roller type orbiting mass oscillator with low fluid drag |
US5156223A (en) * | 1989-06-16 | 1992-10-20 | Hipp James E | Fluid operated vibratory jar with rotating bit |
US4958691A (en) * | 1989-06-16 | 1990-09-25 | James Hipp | Fluid operated vibratory jar with rotating bit |
US6009948A (en) * | 1996-05-28 | 2000-01-04 | Baker Hughes Incorporated | Resonance tools for use in wellbores |
NO302586B1 (en) * | 1996-06-07 | 1998-03-23 | Rf Procom As | Device intended for connection to a pipe string |
EG21606A (en) * | 1997-02-25 | 2001-12-31 | Shell Int Research | Drill string tool |
US6502638B1 (en) * | 1999-10-18 | 2003-01-07 | Baker Hughes Incorporated | Method for improving performance of fishing and drilling jars in deviated and extended reach well bores |
GB2374623B (en) * | 1999-12-03 | 2004-03-10 | Wireline Engineering Ltd | Downhole device |
US6464014B1 (en) * | 2000-05-23 | 2002-10-15 | Henry A. Bernat | Downhole coiled tubing recovery apparatus |
WO2002036935A1 (en) * | 2000-11-03 | 2002-05-10 | Bechtel Bwxt Idaho, Llc | Methods of performing downhole operations using orbital vibrator energy sources |
US6619394B2 (en) * | 2000-12-07 | 2003-09-16 | Halliburton Energy Services, Inc. | Method and apparatus for treating a wellbore with vibratory waves to remove particles therefrom |
US7389183B2 (en) * | 2001-08-03 | 2008-06-17 | Weatherford/Lamb, Inc. | Method for determining a stuck point for pipe, and free point logging tool |
US20050006146A1 (en) * | 2003-07-09 | 2005-01-13 | Mody Rustom K. | Shear strength reduction method and apparatus |
US7204324B2 (en) * | 2004-03-03 | 2007-04-17 | Halliburton Energy Services, Inc. | Rotating systems associated with drill pipe |
US7219747B2 (en) * | 2004-03-04 | 2007-05-22 | Halliburton Energy Services, Inc. | Providing a local response to a local condition in an oil well |
US20060054315A1 (en) * | 2004-09-10 | 2006-03-16 | Newman Kenneth R | Coiled tubing vibration systems and methods |
US7748474B2 (en) * | 2006-06-20 | 2010-07-06 | Baker Hughes Incorporated | Active vibration control for subterranean drilling operations |
-
2007
- 2007-04-16 US US11/787,380 patent/US20080251254A1/en not_active Abandoned
-
2008
- 2008-03-20 WO PCT/US2008/057703 patent/WO2008127838A1/en active Application Filing
Patent Citations (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US4384625A (en) * | 1980-11-28 | 1983-05-24 | Mobil Oil Corporation | Reduction of the frictional coefficient in a borehole by the use of vibration |
EP1239112A2 (en) * | 2001-03-01 | 2002-09-11 | Schlumberger Technology B.V. | Method and apparatus to vibrate a downhole component |
US20050230101A1 (en) * | 2001-03-01 | 2005-10-20 | Shunfeng Zheng | Method and apparatus to vibrate a downhole component |
WO2003012250A1 (en) * | 2001-07-26 | 2003-02-13 | Xl Technology Ltd | Downhole vibrating device |
GB2383356A (en) * | 2001-12-18 | 2003-06-25 | Schlumberger Holdings | Drill String Telemetry System with Reflector |
Also Published As
Publication number | Publication date |
---|---|
US20080251254A1 (en) | 2008-10-16 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US20080251254A1 (en) | Devices and methods for translating tubular members within a well bore | |
CA2351270C (en) | Drilling method and measurement-while-drilling apparatus and shock tool | |
US7591314B2 (en) | Measurement-while-fishing tool devices and methods | |
CA2780248C (en) | Tubular retrieval | |
US6009948A (en) | Resonance tools for use in wellbores | |
CA2514534C (en) | A downhole tool with an axial drive unit | |
US9027650B2 (en) | Remotely-controlled downhole device and method for using same | |
CA2601786C (en) | Method and apparatus for downlink communication | |
US20180340407A1 (en) | Automated directional steering systems and methods | |
US20130000981A1 (en) | Control of downhole safety devices | |
CA2881918C (en) | Method and apparatus for communicating incremental depth and other useful data to downhole tool | |
US11414976B2 (en) | Systems and methods to control drilling operations based on formation orientations | |
CA2916910C (en) | Communication methods and apparatuses for downhole logging tools | |
GB2349403A (en) | Drill string with a vibratory source | |
US20210404324A1 (en) | Tagging assembly including a sacrificial stop component | |
US20200095829A1 (en) | Direct wrap measurement during connection for optimal slide drilling | |
CA3007654C (en) | Systems and methods for minimizing downhole tool vibrations and disturbances | |
US20230167701A1 (en) | Method and apparatus to recover cores from downhole environments | |
WO2003012250A1 (en) | Downhole vibrating device |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
121 | Ep: the epo has been informed by wipo that ep was designated in this application |
Ref document number: 08732594 Country of ref document: EP Kind code of ref document: A1 |
|
NENP | Non-entry into the national phase |
Ref country code: DE |
|
122 | Ep: pct application non-entry in european phase |
Ref document number: 08732594 Country of ref document: EP Kind code of ref document: A1 |