U.S. patent application number 14/078933 was filed with the patent office on 2015-05-14 for pump actuated jar for downhole sampling tools.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to NATHAN LANDSIEDEL.
Application Number | 20150129220 14/078933 |
Document ID | / |
Family ID | 53042705 |
Filed Date | 2015-05-14 |
United States Patent
Application |
20150129220 |
Kind Code |
A1 |
LANDSIEDEL; NATHAN |
May 14, 2015 |
PUMP ACTUATED JAR FOR DOWNHOLE SAMPLING TOOLS
Abstract
An apparatus configured to impart a force on a downhole
component, having a piston configured to expand from a movement of
a drilling fluid in a downhole environment, a weight configured to
move from a first position to a second position, wherein the weight
contacts the piston and the piston is configured to move the weight
from the first position to the second position when the piston
expands from movement of the drilling fluid, a spring configured to
contact a bearing surface and the weight, wherein movement of the
weight toward the second position compresses the spring, a return
spring configured to impart a force on the weight to return the
weight to the first position from the second position and a trigger
mechanism configured to actuate a return of the weight from the
second position to the first position by the return spring.
Inventors: |
LANDSIEDEL; NATHAN; (Fresno,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
53042705 |
Appl. No.: |
14/078933 |
Filed: |
November 13, 2013 |
Current U.S.
Class: |
166/301 ;
166/178 |
Current CPC
Class: |
E21B 31/1135
20130101 |
Class at
Publication: |
166/301 ;
166/178 |
International
Class: |
E21B 31/113 20060101
E21B031/113; E21B 7/00 20060101 E21B007/00 |
Claims
1. An apparatus configured to impart a force on a downhole
component, comprising: a piston configured to expand from a
movement of a fluid; a weight configured to move from a first
position to a second position, wherein the weight contacts the
piston and the piston is configured to move the weight from the
first position to the second position when the piston expands from
movement of the drilling fluid; a spring configured to contact a
bearing surface and the weight, wherein movement of the weight
toward the second position compresses the spring; a return spring
configured to impart a force on the weight to return the weight to
the first position from the second position; and a trigger
mechanism configured to actuate a return of the weight from the
second position to the first position by the return spring.
2. The apparatus according to claim 1, wherein the fluid is a
drilling fluid.
3. The apparatus according to claim 1, wherein the component is a
downhole component.
4. The apparatus according to claim 1, wherein the drilling fluid
is in a downhole environment.
5. A method for creating a force on a downhole tool, comprising:
pumping a fluid to a downhole location; expanding a piston in the
downhole location, an expansion of the piston caused by the fluid
entering the piston; moving a weight through the expansion of the
piston, the movement of the weight compressing a spring from an
uncompressed position to a compressed position; triggering a
mechanism such that the weight is allowed to move and the spring
returns from the compressed position to the uncompressed position;
and impacting the weight upon a surface to deliver a force to a
downhole environment.
6. The method according to claim 5, wherein the force is delivered
to a tool string.
7. The method according to claim 5, wherein the fluid is a drilling
mud.
8. The method according to claim 5, wherein the mechanism used for
triggering is a ball bearing mechanism.
9. The method according to claim 5, wherein the mechanism used for
triggering is a keyed, twisting track trigger mechanism.
10. The method according to claim 5, wherein the pumped fluid
expands the piston through one flowline.
11. The method according to claim 5, wherein the pumped fluid
expands the piston through one of two flowlines.
Description
FIELD OF THE INVENTION
[0001] Aspects of the disclosure relate to downhole drilling and
subsurface investigation. More specifically, aspects of the
disclosure relate to a pump actuated jar mechanism for downhole
sampling tools.
BACKGROUND INFORMATION
[0002] Tool sticking is a leading source of nonproductive time in
field operations for both wireline and drilling operations in the
oilfield industry. Typically, when a tool string becomes "stuck" in
a borehole, a mechanism called a "jar" is used to dislodge the
stuck tool string. The jar is actuated by applying tension to a
wireline cable up to approximately one thousand (1000) to three
thousand (3000) pounds force above tool weight. Applying this force
causes the jar to release under tension and travel freely for
approximately 6 inches (15.24 centimeters). The moving portion of
the jar impacts the stationary portion of the jar and an impact
force is generated. This sudden impact force is transmitted to the
tool string in the hopes of freeing the stuck tool. Jar function is
similar to slide hammer operations used to remove plugs, pistons
and tight tolerance components in industrial applications. The
process described above for the jar can be repeated by slacking the
cable and allowing the jar to move back 6 inches (15.24
centimeters) of travel at which point a trigger is reset and the
process is repeated, applying tension to the cable.
[0003] There are several disadvantages to conventional jar systems.
First, existing jars are run at the top of the tool string while
sampling tools most often become stuck at the probe or packer
located near the bottom of the tool string. The rapid attenuation
of the jarring force along the length of the tool string means that
jars have to be set to a very high jarring force to ensure
sufficient force reaches the stuck portion of the tool to free the
tool. This high force often results in damage to the tools nearest
to the jar. Second, the existing wireline jars depend on the
stretch of the cable to provide the potential energy force. This
high tension, followed by the release and impact, causes rapid
degradation of the wireline cable. Third, conventional jars are
excessively long and have significant weight as well as being
expensive.
[0004] Conventional jars used in drilling apparatus have slightly
different configurations, but have similar challenges. The defects
of conventional jars limit their usefulness in many
applications.
SUMMARY
[0005] In one example embodiment, an apparatus is presented wherein
the apparatus is configured to impart a force on a downhole
component, having a piston configured to expand from a movement of
a drilling fluid in a downhole environment, a weight configured to
move from a first position to a second position, wherein the weight
contacts the piston and the piston is configured to move the weight
from the first position to the second position when the piston
expands from movement of the drilling fluid, a spring configured to
contact a bearing surface and the weight, wherein movement of the
weight toward the second position compresses the spring; a return
spring configured to impart a force on the weight to return the
weight to the first position from the second position and a trigger
mechanism configured to actuate a return of the weight from the
second position to the first position by the return spring. The
preceding summary is not intended to limit the scope of the
invention, but rather provide but one example embodiment that may
be used to accomplish the features and methods described.
[0006] In another embodiment, a method for creating a force on a
downhole tool is provided having features of pumping a fluid to a
downhole location, expanding a piston in the downhole location, an
expansion of the piston caused by the fluid entering the piston,
moving a weight through the expansion of the piston, the movement
of the weight compressing a spring from an uncompressed position to
a compressed position, triggering a mechanism such that the weight
is allowed to move and the spring returns from the compressed
position to the uncompressed position, and impacting the weight
upon a surface to deliver a force to a downhole environment.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] FIG. 1 is a side elevation cut away view of a device of a
jar with the housing removed for clarity of illustration in
conformance with one example embodiment.
[0008] FIG. 2 is a side view of the weight attachment area of FIG.
1 with the housing removed for clarity of illustration.
[0009] FIG. 3 is a side view of a ball bearing trigger
mechanism.
[0010] FIG. 4 is a side view of a ball bearing trigger
mechanism.
[0011] FIG. 5 is a side view of a keyed, twisting track trigger
mechanism embodiment that may be used with FIG. 1.
[0012] FIG. 6 is a flow chart for conducting pump actuated jar
activities on downhole components used during drilling
operations.
[0013] FIG. 7 is a side elevation view of a drilling apparatus for
which the jar of FIG. 1 may be used.
DETAILED DESCRIPTION
[0014] In accordance with the present disclosure, a wellsite with
associated wellbore and apparatus is described in order to describe
a typical, but not limiting, embodiment of the application. To that
end, apparatus at the wellsite may be altered, as necessary, due to
field considerations encountered.
[0015] An example well site system is schematically depicted in
FIG. 7 wherein components described above are incorporated in the
larger systems described therein or are used in configurations
utilizing the wellbores established using the systems illustrated
in FIG. 8. The well site comprises a well. A drill string 105 may
extend from the drill rig 101 into a zone of the formation of
reservoir 115. The drill string 105 employs a telemetry system for
transmitting data from downhole to the surface. In the illustrated
embodiment, the telemetry system is a mud pulse telemetry
system.
[0016] Although illustrated with a mud pulse telemetry, the drill
string 105 may employ any type of telemetry system or any
combination of telemetry systems, such as electromagnetic, acoustic
and\or wired drill pipe, however in the preferred embodiment, only
the mud pulse telemetry system is used. A bottom hole assembly
("BHA") is suspended at the end of the drill string 105. In an
embodiment, the bottom hole assembly comprises a plurality of
measurement while drilling or logging while drilling downhole tools
125, such as shown by numerals 6a and 6b. For example, one or more
of the downhole tools 6a and 6b may be a formation pressure while
drilling tool.
[0017] Logging while drilling ("LWD") tools used at the end of the
drill string 105 may include a thick walled housing, commonly
referred to as a drill collar, and may include one or more of a
number of logging devices. The logging while drilling tool may be
capable of measuring, processing, and/or storing information
therein, as well as communicating with equipment disposed at the
surface of the well site.
[0018] Measurement while drilling ("MWD") tools may include one or
more of the following measuring tools: a modulator, a weight on bit
measuring device, a torque measuring device, a vibration measuring
device, a shock measuring device, a stick slip measuring device, a
direction measuring device, and inclination measuring device,
and\or any other device.
[0019] Measurements made by the bottom hole assembly or other tools
and sensors with the drill string 105 may be transmitted to a
computing system 185 for analysis. For example, mud pulses may be
used to broadcast formation measurements performed by one or more
of the downhole tools 6a and 6b to the computing system 185.
[0020] The computing system 185 is configured to host a plurality
of models, such as a reservoir model, and to acquire and process
data from downhole components, as well as determine the bottom hole
location in the reservoir 115 from measurement while drilling data.
Examples of reservoir models and cross well interference testing
may be found in the following references: "Interpreting an
RFT-Measured Pulse Test with a Three-Dimensional Simulator" by
Lasseter, T., Karakas, M., and Schweltzer, J., SPE 14878, March
1988. "Design, Implementation, and Interpretation of a
Three-Dimensional Well Test in the Cormorant Field, North Sea" by
Bunn, G. F., and Yaxley, L. M., SPE 15858, October 1986. "Layer
Pulse Testing Using a Wireline Formation Tester" by Saeedi, J., and
Standen, E., SPE 16803, September 1987. "Distributed Pressure
Measurements Allow Early Quantification of Reservoir Dynamics in
the Jene Field" by Bunn, G. F., Wittman, M. J., Morgan, W. D., and
Curnutt, R. C., SPE 17682, March 1991. "A Field Example of
Interference Testing Across a Partially Communicating Fault" by
Yaxley, L. M., and Blaymires, J. M., SPE 19306, 1989.
"Interpretation of a Pulse Test in a Layered Reservoir" by Kaneda,
R., Saeedi, J., and Ayestaran, L. C., SPE 21337, December 1991.
[0021] The drill rig 101 or similar looking/functioning device may
be used to move the drill string 105 within the well that is being
drilled through subterranean formations of the reservoir, generally
at 115. The drill string 105 may be extended into the subterranean
formations with a number of coupled drill pipes (one of which is
designated 120) of the drill string 105. The drill pipe 120
comprising the drill string 105 may be structurally similar to
ordinary drill pipes, as illustrated for example and U.S. Pat. No.
6,174,001, issued to Enderle, entitled "Two-Step, a Low Torque,
Wedge Thread for Tubular Connector," issued Aug. 7, 2001, which is
incorporated herein by reference in its entirety, and may include a
cable associated with each drill pipe 120 that serves as a
communication channel.
[0022] The bottom hole assembly at the lower end of the drill
string 105 may include one, an assembly, or a string of downhole
tools. In the illustrated example, the downhole tool string 105 may
include well logging tools 125 coupled to a lower end thereof. As
used in the present description, the term well logging tool or a
string of such tools, may include at least one or more logging
while drilling tools ("LWD"), formation evaluation tools, formation
sampling tools and other tools capable of measuring a
characteristic of the subterranean formations of the reservoir 115
and\or of the well.
[0023] Several of the components disposed proximate to the drill
rig 101 may be used to operate components of the overall system.
These components will be explained with respect to their uses in
drilling the well 110 for a better understanding thereof. The drill
string 105 may be used to turn and urge a drill bit 116 into the
bottom the well 110 to increase its length (depth). During drilling
of the well 110, a pump 130 lifts drilling fluid (mud) 135 from a
tank 140 or pits and discharges the mud 135 under pressure through
a standpipe 145 and flexible conduit 150 or hose, through a top
drive 155 and into an interior passage inside the drill pipe 105.
The mud 135 which can be water or oil-based, exits the drill pipe
105 through courses or nozzles (not shown separately) in the drill
bit 116, wherein it cools and lubricates the drill bit 116 and
lifts drill cuttings generated by the drill bit 116 to the surface
of the earth through an annular arrangement.
[0024] When the well 110 has been drilled to a selected depth, the
well logging tools 125 may be positioned at the lower end of the
pipe 105 if not previously installed. The well logging tools 125
may be positioned by pumping the well logging downhole tools 125
down the pipe 105 or otherwise moving the well logging downhole
tools 125 down the pipe 105 while the pipe 105 is within the well
110. The well logging tools 125 may then be coupled to an adapter
sub 160 at the end of the drill string 105 and may be moved
through, for example in the illustrated embodiment, a highly
inclined portion 165 of the well 110, which would be inaccessible
using armored electrical cable to move the well logging downhole
tools 125.
[0025] During well logging operations, the pump 130 may be operated
to provide fluid flow to operate one or more turbines in the well
logging downhole tools 125 to provide power to operate certain
devices in the well logging tools 125. When tripping in or out of
the well 110, (turning on and off the mud pumps 130) it may be in
feasible to provide fluid flow. As a result, power may be provided
to the well logging tools 125 in other ways. For example, batteries
may be used to provide power to the well logging downhole tools
125. In one embodiment, the batteries may be rechargeable batteries
and may be recharged by turbines during fluid flow. The batteries
may be positioned within the housing of one or more of the well
logging tools 125. Other manners of powering the well logging tools
125 may be used including, but not limited to, one-time power use
batteries. A wireline may also power the downhole components.
[0026] As the well logging tools 125 are moved along the well 110
by moving the drill pipe 105, signals may be detected by various
devices, of which non-limiting examples may include a resistivity
measurement device, a bulk density measurement device, a porosity
measurement device, a formation capture cross-section measurement
device 170, a gamma ray measurement device 175 and a formation
fluid sampling tool 610, 710, 810 which may include a formation
pressure measurement device 6a and/or 6b. The signals may be
transmitted toward the surface of the earth along the drill string
105.
[0027] An apparatus and system for communicating from the drill
pipe 105 to the surface computer 185 or other component configured
to receive, analyze, and/or transmit data may include a second
adapter sub 190 that may be coupled between an end of the drill
string 105 and the top drive 155 that may be used to provide a
communication channel with a receiving unit 195 for signals
received from the well logging downhole tools 125. The receiving
unit 195 may be coupled to the surface computer 185 to provide a
data path therebetween that may be a bidirectional data path.
[0028] Though not shown, the drill string 105 may alternatively be
connected to a rotary table, via a Kelly, and may suspend from a
traveling block or hook, and additionally a rotary swivel. The
rotary swivel may be suspended from the drilling rig 101 through
the hook, and the Kelly may be connected to the rotary swivel such
that the Kelly may rotate with respect to the rotary swivel. The
Kelly may be any mast that has a set of polygonal connections or
splines on the outer surface type that mate to a Kelly bushing such
that actuation of the rotary table may rotate the Kelly.
[0029] An upper end of the drill string 105 may be connected to the
Kelly, such as by threadingly reconnecting the drill string 105 to
the Kelly, and the rotary table may rotate the Kelly, thereby
rotating the drill string 105 connected thereto.
[0030] Although not shown, the drill string 105 may include one or
more stabilizing collars. A stabilizing collar may be disposed
within or connected to the drill string 105, in which the
stabilizing collar may be used to engage and apply a force against
the wall of the well 110. This may enable the stabilizing collar to
prevent the drill pipe string 105 from deviating from the desired
direction for the well 110. For example, during drilling, the drill
string 105 may "wobble" within the well 110, thereby allowing the
drill string 105 to deviate from the desired direction of the well
110. This wobble action may also be detrimental to the drill string
105, components disposed therein, and the drill bit 116 connected
thereto. A stabilizing collar may be used to minimize, if not
overcome altogether, the wobble action of the drill string 105,
thereby possibly increasing the efficiency of the drilling
performed at the well site and/or increasing the overall life of
the components at the wellsite.
[0031] Referring to FIG. 1, in the non-limiting aspects described,
a sampling tool pump (not shown) is used to build pressure in the
flowline (pumping down) which extends a hydraulic piston 18 built
into a pump down jar 10. As the piston 18 extends, the piston 18
pushes a weight 20 against a spring 22. The device is used to
produce a jarring event that will unstuck a downhole device. A
burst of kinetic energy is used to break frictional forces and
allow the tool to be retrieved on further used downhole. The device
may be used with a wireline, as a non-limiting embodiment.
[0032] At a preset extension of the piston 18, the weight 20 and
the spring 22 are released and the spring 22 pushes the weight 20
back against the end of the jar 10, creating a jarring event,
consequently releasing the energy. Pressure can then be released
from the flowline by opening a valve 24 in the packer or probe and
the piston 18 returns to the starting position by a second, lower
force return spring 30 that has the purpose of pushing the piston
18 back to the start position. The second, lower force return
spring 30 is located inside a guide sleeve 31. A trigger mechanism
29 may be used to trigger motion in the jar 10. Such trigger
mechanisms 29 are to be considered non-limiting.
[0033] Once the piston 18 is returned to the start position, the
valve 24 in the packer and/or probe can be closed and pressure
built in the flowline again, extending the piston 18 and trigger
the jar 10 for a second actuation. The process can be repeated the
number of times required for freeing the tool string.
[0034] As provided in the FIGS. that follow, there are different
trigger mechanisms that may be used with the jar 10. In one
optional embodiment, pistons are used. In one embodiment, a
configuration is presented that prevents the jar from triggering
unintentionally during the normal operation (i.e. when inflating
packers). Additionally, a second flow line may be used in a
downhole testing apparatus to control the jarring force with the
pressure of a second flowline.
[0035] As provided in FIG. 1, a cross-sectional view (top) and in
an outside view, FIG. 2, (exterior partial view) a housing is
deleted for clarity of illustration. As will be understood, the
actual configuration would include a housing. In FIGS. 1 and 2, the
sampling tool pump pressures the flowline (by pumping down), the
piston 18 extends, pushing the weight 20 from the left side of the
drawing, to the right. This movement compresses the jar spring 22.
After extending a predetermined distance, and storing the desired
energy in the spring 22, the trigger mechanism 29 releases the
weight 20 which is accelerated until the weight impacts the
stationary portion of the device shown on the left side of the
drawing, causing a jarring force to free a stuck tool. After the
jar 10 is triggered, the pump is stopped and a valve in the tool,
most likely in the probe or packer, opened to release the pressure
on the piston, at which point the return spring 30 pushes the
piston 18 back to the start position.
[0036] This actuation effectively resets the trigger 29 for the
overall mechanism. The valve in the probe or packer can then be
closed and the pump started again to repeat jarring.
[0037] The spring 22, in one non-limiting embodiment, is a stiff
spring with a high spring constant. In one example embodiment, the
spring 22 has two hundred pounds of force per inch of compression.
The assembly of the tool is envisioned to be such that the jarring
spring is "pre-compressed" by some amount to preload the spring 22
with sufficient force to prevent movement of the piston/weight
until a pressure above the packer inflation pressure is applied to
the flowline.
[0038] The sampling tool builds pressure in the flow line as part
of the normal operation to "inflate" the packer. In order to
prevent unintentional jarring as a result of normal packer
inflation, the jarring spring would be pre-loaded as described
above. Typical inflation pressures for the packer are approximately
five hundred (500) pounds per square inch. In one non-limiting
example, a pre-load of the jar spring would entail a flowline
pressure of seven hundred fifty (750) pounds per square inch or
greater to begin moving the weight. The pressure required to
trigger the device can be designed to be variable as a function of
the "stroke" of the piston prior to the trigger mechanism releasing
the weight. A typical piston stroke length is, for example, six (6)
inches or less.
[0039] As provided in FIG. 3 a trigger mechanism 29 is illustrated.
In this embodiment, the trigger mechanism 29 is a ball bearing
mechanism is one that triggers actuation of the overall jar
mechanism. The ball bearings 302 push the weight 307 until reaching
the end of the piston stroke, at which point the portion that
supports the ball bearings shift, allowing the balls to move
"inward" relative to the piston, freeing the weight 307 to
consequently "jar" the tool. As provided in FIG. 3, the piston 310
is configured to move the weight 307 in the central section back
and forth, thereby allowing the ball bearing 302 to enter the
cavity 304 defined by the central section. In the illustrated
embodiment, the locked position is when the central section is
moving to the right. The free movement occurs when the central
section moves to the left striking portion 308. As provided, when
the piston 310 moves in the pumped condition to the right, the
spring 306 deflects, storing potential energy through Hooke's law.
When the ball bearings 302 move inward relative to the central axis
of the central section, the stored energy may be released by the
spring, causing the jarring effect.
[0040] As provided in FIG. 4, a ball bearing trigger mechanism 400
is illustrated that may be used for the trigger mechanism 29 in the
previous illustrated embodiments. In this embodiment, a piston may
move a weight 402 so that the weight 402 compresses against the
spring 404 that stores potential energy. The ball bearings 406
prevent the weight 402 from moving to the left in the illustrated
embodiment. The ball bearings 406 move out of the blocking position
for the weight through use of a twisting track. When the piston
reaches a fully extended position, the ball bearing may enter
precut grooves in the weight, allowing the weight to release and
travel to the left, causing a jarring effect.
[0041] Referring to FIG. 5, a trigger mechanism 600 alternate
embodiment is provided that may be used at element 29. In this
embodiment, the trigger mechanism 600 is a keyed, twisting track
trigger mechanism. The keyed twisting track trigger mechanism 600
triggers the overall jar effect and may be used instead of the ball
bearing mechanism. A weight 602 is keyed to the interior diameter
of the housing such that the weight 602 can translate axially but
cannot rotate about the guide sleeve/piston.
[0042] The piston 605 has a catch, which may be a three prong tip
of the piston 605. The three catches travel in slots 604 in the
guide sleeve 607 turn the catches 606 and the piston until they
align with openings in the weight 602, releasing the weight 602 and
triggering the jar. The alignment between the weight openings and
the piston catches 606 is performed through rotation of the tracks
in the guide sleeve arrangement 608. The piston 605 is returned and
the process is repeated as desired.
[0043] As will be understood, the above concepts will work for
either a one or two flowline tool. There are concepts specific to a
two flowline tool that allow the use of the second flowline to do
one or several of the following: [0044] 1. Activate or passivate
the jar 10--instead of depending on pre-load of the spring to
prevent unintentional jarring during packer inflation, the device
can be such that pressurizing both lines does not actuate the jar
10, but pressurizing only the sample line with the guard line open
to borehole allows actuation of the jar 10. If both lines are
pressurized while inflating the packer, the jar 10 will not
trigger, but if only one line is pressurized, the jar 10 will
actuate. [0045] 2. Varying the jarring force--the jar 10 may also
be designed such that applying pressure (positive or negative) to
one of the two lines, prior to actuating the jar with the other
flowline, would determine the jarring force. This allows downhole
control of the jarring force so that jarring activities may be
started with a low level of force with the least potential to
damage tools and increase the jarring force as needed until the
tools become free.
[0046] Referring to FIG. 6, a method 700 for conducting pump
actuated jar activities for downhole sampling tools is presented.
The method 700 may be used, for example, in downhole environments
in the oil field services industry. Jar activities may also be used
in other environments, thus the method 700 is merely an example. In
702, fluid is pumped to a downhole location. In 704, a piston is
expanded in the downhole location wherein the expansion of the
piston is caused by fluid entering the piston. In 706, a weight is
moved through expansion of the piston, the movement of the weight
compressing a spring from an uncompressed position to a compressed
position. In 708, the weight impacts upon a surface to deliver a
force to a downhole environment.
[0047] In one non-limiting embodiment, an apparatus configured to
impart a force on a downhole component is described, comprising a
piston configured to expand from a movement of a fluid, a weight
configured to move from a first position to a second position,
wherein the weight contacts the piston and the piston is configured
to move the weight from the first position to the second position
when the piston expands from movement of the drilling fluid, a
spring configured to contact a bearing surface and the weight,
wherein movement of the weight toward the second position
compresses the spring, a return spring configured to impart a force
on the weight to return the weight to the first position from the
second position and a trigger mechanism configured to actuate a
return of the weight from the second position to the first position
by the return spring.
[0048] In an alternative embodiment, the apparatus may be
configured such that the fluid is a drilling fluid.
[0049] In an alternative embodiment, the apparatus may be
configured wherein the component is a downhole component.
[0050] In an alternative embodiment, the apparatus may be
configured wherein the drilling fluid is in a downhole
environment.
[0051] In an alternative embodiment a method for creating a force
on a downhole tool, is described comprising pumping a fluid to a
downhole location, expanding a piston in the downhole location, an
expansion of the piston caused by the fluid entering the piston,
moving a weight through the expansion of the piston, the movement
of the weight compressing a spring from an uncompressed position to
a compressed position, triggering a mechanism such that the weight
is allowed to move and the spring returns from the compressed
position to the uncompressed position and impacting the weight upon
a surface to deliver a force to a downhole environment.
[0052] In another alternative embodiment, the method may be
accomplished wherein the force is delivered to a tool string.
[0053] In another alternative embodiment, the method may be
accomplished wherein the fluid is a drilling mud.
[0054] In an alternative embodiment, the method may be accomplished
wherein the mechanism used for triggering is a ball bearing
mechanism.
[0055] In an alternative embodiment, the method may be accomplished
wherein the mechanism used for triggering is a keyed, twisting
track trigger mechanism.
[0056] In an alternative embodiment, the method may be accomplished
wherein the pumped fluid expands the piston through one
flowline.
[0057] In an alternative embodiment, the method may be accomplished
wherein the pumped fluid expands the piston through one of two
flowlines.
[0058] While the aspects have been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of the disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the disclosure
herein.
* * * * *