U.S. patent application number 11/787380 was filed with the patent office on 2008-10-16 for devices and methods for translating tubular members within a well bore.
This patent application is currently assigned to Baker Hughes Incorporated. Invention is credited to David B. Haughton, Gerald D. Lynde, Carl W. Stoesz.
Application Number | 20080251254 11/787380 |
Document ID | / |
Family ID | 39643991 |
Filed Date | 2008-10-16 |
United States Patent
Application |
20080251254 |
Kind Code |
A1 |
Lynde; Gerald D. ; et
al. |
October 16, 2008 |
Devices and methods for translating tubular members within a well
bore
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.
Inventors: |
Lynde; Gerald D.; (Houston,
TX) ; Stoesz; Carl W.; (Houston, TX) ;
Haughton; David B.; (Houston, TX) |
Correspondence
Address: |
SHAWN HUNTER
P.O Box 270110
HOUSTON
TX
77277-0110
US
|
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Family ID: |
39643991 |
Appl. No.: |
11/787380 |
Filed: |
April 16, 2007 |
Current U.S.
Class: |
166/301 |
Current CPC
Class: |
E21B 31/005
20130101 |
Class at
Publication: |
166/301 |
International
Class: |
E21B 31/00 20060101
E21B031/00 |
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 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
[0001] 1. Field of the Invention
[0002] 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.
[0003] 2. Description of the Related Art
[0004] 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.
[0005] 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.
[0006] 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.
[0007] 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.
[0008] The present invention addresses the problems of the prior
art.
SUMMARY OF THE INVENTION
[0009] 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.
[0010] 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.
[0011] 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
[0012] 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.
[0013] FIG. 2 is a side, cross-sectional view of an exemplary
vibratory device used within the vibratory assembly shown in FIG.
1.
[0014] FIG. 3 is an isometric view of an exemplary vibratory
element used within the vibratory device shown in FIG. 2.
[0015] FIG. 4 is a top view of the vibratory element shown in FIG.
3.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0016] 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.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] 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.
[0021] 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.
[0022] 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.
[0023] 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.
[0024] 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.
[0025] 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.
[0026] 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.
[0027] 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.
[0028] 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.
* * * * *