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Publication numberUS20080251254 A1
Publication typeApplication
Application numberUS 11/787,380
Publication dateOct 16, 2008
Filing dateApr 16, 2007
Priority dateApr 16, 2007
Also published asWO2008127838A1
Publication number11787380, 787380, US 2008/0251254 A1, US 2008/251254 A1, US 20080251254 A1, US 20080251254A1, US 2008251254 A1, US 2008251254A1, US-A1-20080251254, US-A1-2008251254, US2008/0251254A1, US2008/251254A1, US20080251254 A1, US20080251254A1, US2008251254 A1, US2008251254A1
InventorsGerald D. Lynde, Carl W. Stoesz, David B. Haughton
Original AssigneeBaker Hughes Incorporated
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Devices and methods for translating tubular members within a well bore
US 20080251254 A1
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.
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Claims(18)
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 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 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 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.
Description
BACKGROUND OF THE INVENTION

1. Field of the Invention

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

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.

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.

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.

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.

The present invention addresses the problems of the prior art.

SUMMARY OF THE INVENTION

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.

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.

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

FIG. 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.

FIG. 2 is a side, cross-sectional view of an exemplary vibratory device used within the vibratory assembly shown in FIG. 1.

FIG. 3 is an isometric view of an exemplary vibratory element used within the vibratory device shown in FIG. 2.

FIG. 4 is a top view of the vibratory element shown in FIG. 3.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 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. Although FIG. 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.

FIG. 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 FIG. 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.

FIGS. 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.

Referring once again to FIG. 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.

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 FIG. 1, the vibratory sub 52 would be actuated.

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.

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.

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.

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.

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.

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.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US8191623Apr 14, 2009Jun 5, 2012Baker Hughes IncorporatedSlickline conveyed shifting tool system
US8210251 *Apr 14, 2009Jul 3, 2012Baker Hughes IncorporatedSlickline conveyed tubular cutter system
US20100212901 *Feb 26, 2010Aug 26, 2010Frank's International, Inc.Downhole vibration apparatus and methods
Classifications
U.S. Classification166/301
International ClassificationE21B31/00
Cooperative ClassificationE21B31/005
European ClassificationE21B31/00C
Legal Events
DateCodeEventDescription
Jul 11, 2007ASAssignment
Owner name: BAKER HUGHES INCORPORATED, TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:LYNDE, GERALD D.;STOESZ, CARL W.;HAUGHTON, DAVID B.;REEL/FRAME:019592/0155;SIGNING DATES FROM 20070524 TO 20070709