U.S. patent application number 12/986637 was filed with the patent office on 2011-07-14 for wirelessly actuated hydrostatic set module.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Dinesh R. Patel.
Application Number | 20110168403 12/986637 |
Document ID | / |
Family ID | 44257624 |
Filed Date | 2011-07-14 |
United States Patent
Application |
20110168403 |
Kind Code |
A1 |
Patel; Dinesh R. |
July 14, 2011 |
WIRELESSLY ACTUATED HYDROSTATIC SET MODULE
Abstract
A hydrostatic set module configured with a wireless trigger
mechanism to allow wireless activation thereof from an oilfield
surface. The trigger mechanism includes a charge for exposing the
module to wellbore pressures and allowing it to behave as an
intensifier for actuation of a downhole device such as a production
packer. The mechanism also includes a sensor for detection of the
wireless communications along with a processor for analysis thereof
and to direct spending of the charge. Pressure pulse or other
wireless communication forms that are suitable for the downhole
environment may be transmitted from surface in a variety of
different signature patterns for responsive analysis by the trigger
mechanism.
Inventors: |
Patel; Dinesh R.; (Sugar
Land, TX) |
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
44257624 |
Appl. No.: |
12/986637 |
Filed: |
January 7, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61293355 |
Jan 8, 2010 |
|
|
|
Current U.S.
Class: |
166/373 ;
166/113; 166/244.1 |
Current CPC
Class: |
E21B 23/06 20130101;
E21B 34/08 20130101; E21B 23/065 20130101; E21B 41/00 20130101;
E21B 47/12 20130101 |
Class at
Publication: |
166/373 ;
166/244.1; 166/113 |
International
Class: |
E21B 34/10 20060101
E21B034/10; E21B 41/00 20060101 E21B041/00; E21B 43/00 20060101
E21B043/00 |
Claims
1. A downhole system for disposal in a well, the system comprising:
a hydraulically actuated downhole device; a hydrostatic set module
hydraulically coupled to said device for actuation thereof; and a
wirelessly responsive trigger mechanism coupled to said module and
having a charge for activating said module for the actuation of
said device.
2. The system of claim 1 wherein said mechanism further comprises a
pressure chamber disposed adjacent the charge for exposure to
wellbore pressure upon spending of the charge as directed by a
processor of said mechanism, the exposure to provide the activating
of said module.
3. The system of claim 1 wherein said hydraulically actuated
downhole device is one of a packer, a sliding sleeve and a
valve.
4. The system of claim 3 wherein the packer is a mechanical packer
for securing production tubing at a location in the well.
5. The system of claim 3 wherein the valve is a formation isolation
valve.
6. A wirelessly activated hydrostatic set module assembly for
disposal in a well at an oilfield, the assembly comprising: a
hydrostatic set module for hydraulically actuating a downhole
device in the well; and a wireless trigger mechanism coupled to
said module for initiating of the actuating, said mechanism having
a sensor for detection of wireless communications and a processor
for analysis thereof.
7. The assembly of claim 6 wherein the sensor is one of a pressure
sensor, an acoustic sensor, a flow meter, a strain gauge, a radio
frequency identification detector, a pip tag detector, and a
chemical detector.
8. The assembly of claim 7 wherein the chemical detector is a pH
detector.
9. The assembly of claim 7 wherein the pressure sensor is
configured for detection of wireless communications in the form of
pressure pulses propagated through the well from the oilfield.
10. The assembly of claim 9 wherein the pressure sensor and
processor are configured to distinguish different signature
patterns of pressure pulses from one another.
11. The assembly of claim 7 wherein the acoustic sensor is
configured for detection of wireless communications in the form of
sonic transmissions propagated through the well from the
oilfield.
12. The assembly of claim 7 wherein the flow meter is configured
for detection of wireless communications in the form of fluid flow
directed from the oilfield.
13. The assembly of claim 7 wherein the strain gauge is configured
for detection of wireless communications in the form of physical
tension imparted on the assembly from the oilfield.
14. The assembly of claim 7 wherein the radio frequency
identification detector is configured for detection of wireless
communications in the form of a radio frequency identification tag
fluidly transported through the well from the oilfield.
15. The assembly of claim 7 wherein the pip tag detector is
configured for detection of wireless communications in the form of
a radioactively marked pip tag fluidly transported through the well
from the oilfield.
16. The assembly of claim 7 wherein the chemical detector is
configured for detection of a chemical fluidly delivered through
the well from the oilfield.
17. An oilfield assembly comprising: a control unit disposed at an
oilfield surface to direct wireless communications downhole into a
well; a wireless signal regulator coupled to said unit for
disseminating the wireless communications into the well; and a
wirelessly activated hydrostatic set module disposed in the well,
said module having a wirelessly actuated trigger for detection of
the wireless communications and responsively activating said module
to actuate a downhole device coupled thereto.
18. The assembly of claim 17 wherein the trigger is a first
trigger, the assembly further comprising a second trigger of the
module to increase the likelihood of the detection.
19. The assembly of claim 16 wherein each trigger is responsive to
a different independently tailored signature pattern of the
wireless communications.
20. A method of wirelessly actuating a downhole device from an
oilfield surface, the method comprising: deploying a downhole
system into a well at the oilfield; sending wireless communications
downhole into the well from the oilfield surface; detecting the
communication with a sensor of a trigger mechanism of the system;
and actuating the device with a hydrostatic set module of the
system based on analysis of the detected communication by a
processor of the trigger mechanism.
21. The method of claim 20 wherein the wireless communications are
pressure pulses generated by a pressure pulse generator located at
the surface during said sending.
22. The method of claim 20 wherein the device is a packer, said
actuating further comprising setting the packer.
23. The method of claim 20 wherein the device is a sliding sleeve,
said actuating further comprising shifting the sliding sleeve.
24. The method of claim 20 wherein the device is a valve, said
actuating further comprising changing a position of the valve.
25. The method of claim 20 wherein said sending comprises sending
multiple wireless communication signatures downhole.
26. The method of claim 20 wherein the processor is programmed to
recognize multiple wireless communication signatures.
Description
PRIORITY CLAIM/CROSS REFERENCE TO RELATED APPLICATION(S)
[0001] This patent Document claims priority under 35 U.S.C.
.sctn.119 to U.S. Provisional App. Ser. No. 61/293,255, filed on
Jan. 8, 2010, and entitled, "Method and Apparatus for Setting a
Packer", incorporated herein by reference in its entirety.
FIELD
[0002] Embodiments described relate to hydrostatic setting modules
for use in downhole environments. In particular, equipment and
techniques for triggering a hydrostatic setting module are
described. More specifically, wireless equipment and techniques may
be utilized for such triggering without reliance on potentially
more costly or stressful hydraulic triggering modes.
BACKGROUND
[0003] Exploring, drilling and completing hydrocarbon and other
wells are generally complicated, time consuming, and ultimately
very expensive endeavors. As a result, over the years, a
significant amount of added emphasis has been placed on overall
well architecture, monitoring and follow on interventional
maintenance. Indeed, perhaps even more emphasis has been directed
at minimizing costs associated with applications in furtherance of
well construction, monitoring and maintenance. All in all, careful
attention to the cost effective and reliable execution of such
applications may help maximize production and extend well life.
Thus, a substantial return on the investment in the completed well
may be better ensured.
[0004] In line with the objectives of maximizing cost effectiveness
and overall production, the well may be of a fairly sophisticated
architecture. For example, the well may be tens of thousands of
feet deep, traversing various formation layers, and zonally
isolated throughout. That is to say, packers may be intermittently
disposed about production tubing which runs through the well so as
to isolate various well regions or zones from one another. Thus,
production may be extracted from certain zones through the
production tubing, but not others. Similarly, production tubing
that terminates adjacent a production region is generally anchored
or immobilized in place thereat by a mechanical packer,
irrespective of any zonal isolation.
[0005] A packer, such as the noted mechanical packer, may be
secured near the terminal end of the production tubing and equipped
with a setting mechanism. The setting mechanism may be configured
to drive the packer from a lower profile to a radially enlarged
profile. Thus, the tubing may be advanced within the well and into
position with the packer in a reduced or lower profile.
Subsequently, the packer may be enlarged to secure the tubing in
place adjacent the production region.
[0006] Once the production tubing is in place, activation of the
setting mechanism is often hydraulically triggered. For example,
the mechanism may be equipped with a trigger that is responsive to
a given degree of pressure induced within the production tubing.
So, for example, surface equipment and pumps adjacent the well head
may be employed to induce a pressure differential of between about
3,000 and 4,000 PSI into the well. Depending on the location of the
trigger for the setting mechanism, this driving up of pressure may
take place through the bore of the production tubing or through the
annulus between the tubing and the wall of the well.
[0007] Unfortunately, the noted hydraulic manner of driving up
pressure for triggering of the setting mechanism may place
significant stress on the production tubing. For example, where the
hydraulic pressure is induced through the tubing bore, the strain
on the tubing may lead to ballooning. Furthermore, the strain on
the tubing may have long term effects. That is to say, even long
after setting the packer, strain placed on the tubing during the
hydraulic setting of the packer may result in failure, for example,
during production operations. To avoid such a catastrophic event,
whenever pressure tolerances are detectably exceeded, the entire
production tubing string and packer assembly may be removed,
examined, and another deployment of production equipment
undertaken. Ultimately, this may eat up a couple of days' time and
upwards of $100,000 in expenses. Once more, even where such hazards
are avoided, the induction of sufficient pressure within the tubing
requires the installation and removal of a plug within the tubing
near its terminal end. Thus, the undesirable costs of additional
runs in the well are introduced along with the plugs' own failure
modes.
[0008] Alternatively, pressurization of the annulus as a means to
trigger the setting mechanism requires that the lower, generally
open-hole, completions assembly be isolated. Generally this would
involve the closing of a formation isolation valve or other barrier
valve above the lower completions. Unfortunately, such a valve may
not always be present. Once more, such valves come with their own
inherent expense, installation cost, and failure modes, not to
mention the activation time and techniques which must be dedicated
to operation of the valve.
[0009] In order to avoid the costly scenario of having to remove
and re-deploy the entire production string or rely on a lower
completion barrier valve, a setting mechanism may be employed that
is hydraulically wired to the surface. So, for example, a
hydrostatic set module may be utilized that includes a dedicated
hydraulic control line run all the way to surface. As a result,
exposure of the production tubing to dramatic pressure increases
for packer deployment is eliminated as is the need to rely on plug
placement or barrier valve operation.
[0010] Unfortunately, the utilization of a dedicated hydraulic line
for the setting mechanism only shifts the concerns over hydraulic
deployment from potential production tubing stressors, plug
placements, or barrier valve issues to issues with other downhole
production equipment. For example, a dedicated hydraulic line is
itself an added piece of production equipment. Thus, it comes with
its own added expenses and failure modes. Indeed, due to the fact
that a new piece of equipment is introduced, the possibility of
defective production string equipment is inherently increased even
before a setting application is run. Once more, where such
defectiveness results in a failure, the same amount of time and
expenses may be lost in removal and re-deployment of the production
string. Thus, the advantages obtained from protecting the
production tubing by utilization of a dedicated hydraulic line for
the setting mechanism may be negligible at best.
SUMMARY
[0011] A downhole system is provided that includes a hydraulically
actuated mechanism along with a hydrostatic set module. The module
is hydraulically coupled to the mechanism for its actuation.
Additionally, the module is outfitted with a wireless trigger to
initiate its own activation to attain the noted actuation of the
mechanism.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 depicts a front view of an embodiment of a wirelessly
triggered hydrostatic set module in conjunction with a packer
assembly.
[0013] FIG. 2 is an overview of an oilfield accommodating a well
with the module and assembly of FIG. 1 disposed therein.
[0014] FIG. 3A is an enlarged view of the module and assembly taken
from 3-3 of FIG. 2 and revealing wireless pressure pulse
communication through the well.
[0015] FIG. 3B reveals the module and assembly of FIG. 3A with the
packer of the assembly set in the well by the module in response to
the wireless communication.
[0016] FIG. 4A is a schematic view of an embodiment of a wirelessly
triggered hydrostatic set module and downhole actuatable tool such
as a packer assembly.
[0017] FIG. 4B is a schematic view of the module and assembly of
FIG. 4B following wireless actuation of the module.
[0018] FIG. 5 is a schematic view of an alternate embodiment of a
wirelessly triggered hydrostatic set module employing redundant
wireless triggering.
[0019] FIG. 6 is a flow-chart summarizing an embodiment of
employing a wirelessly triggered hydrostatic set module.
DETAILED DESCRIPTION
[0020] Embodiments herein are described with reference to certain
downhole setting applications. For example, embodiments depicted
herein are of a packer being set downhole as part of a production
assembly. However, a variety of alternate applications utilizing a
hydrostatic set module may employ wireless triggering and
techniques as detailed herein. Furthermore, as used herein, the
term "wireless" is meant to refer to any communication that takes
place without the requirement of an optical or electrical wire,
hydraulic line, or any other form of hard line substantially
dedicated to supporting communications.
[0021] Referring now to FIG. 1, a downhole system 100 is depicted
which includes an embodiment of a wirelessly triggered hydrostatic
set module 150. The module 150 is provided in conjunction with a
packer 175 which may be utilized in sealing and anchoring
production tubing 110 at a downhole location (see FIG. 2). Thus,
the packer 175 is outfitted with sealing elements 177 which may be
hydraulically set via a hydraulic line 160 running from the module
150. In alternate embodiments, however, this line 160 may lead to
hydraulically set devices other than packers.
[0022] As noted, the module 150 is wireless in nature. As shown in
FIG. 1, the module 150 is equipped with a wireless trigger
mechanism 130. With added reference to FIG. 2, the trigger 130 is
configured to detect a wireless communication from surface 200. The
communication may be in the form of a pressure pulse 201 or other
signal emanating from surface 201 and transmitted downhole through
the well 280. Regardless, the trigger mechanism 130 is configured
to actuate the hydrostatic set module 150 in response to the
detection of the wireless signal.
[0023] With added reference to FIG. 2, in an embodiment where
pressure pulse 201 is employed, often referred to as e-firing, the
trigger mechanism 130 may include a pressure sensor 480 as depicted
in FIGS. 4A and 4B. In this embodiment a host of different
signature types may be utilized in communicating with a processor
470 of the trigger mechanism 130 as described below. Further, given
the downhole environment, a low pressure signature may be most
suitable for communications. However, in other embodiments, the
trigger mechanism 130 may be equipped with different types of
sensors. For example, an acoustic sensor, flow meter or strain
gauge may be utilized for respective detection of sonic
transmission, fluid flow, or physical tension directed at the
system 100 from the oilfield surface 200. By the same token, a
radio frequency identification (RFID) or pip tag detector may be
utilized for detection of an RFID or radioactively marked
projectile, respectively. Again, such a projectile may be dropped
downhole from the oilfield surface 201 for activation of the
trigger mechanism 130, once detected by the sensor thereof.
[0024] Referring specifically now to FIG. 2, an overview of an
oilfield 201 accommodating a well 280 is shown. The above noted
system 100, with module 150 and packer 175, is disposed within the
well 280 providing isolation above a production region 287. The
well 280 is defined by a casing 285 traversing various formation
layers 290, 295 eventually reaching an uncased production region
287 with perforations 289 to encourage production therefrom.
Although in certain embodiments, the production region 287 may be
cased, for example with casing perforations also present.
Regardless, a hydrocarbon production flow may ultimately be
directed through production tubing 110 of the system 100 and
diverted through a line 255 at the well head 250.
[0025] A host of surface equipment 225 is disposed at the oilfield
surface 200. Indeed, a rig 230 is even provided to support
additional equipment for well interventions or other applications
beyond the packer setting described herein. As to packer setting, a
control unit 260 is provided along with a pulse generator 265 to
direct communications with the triggering mechanism 130 as
described below. In the simplest form the pulse generator may be a
pump. In other embodiments, however, alternate forms of wireless
signal regulators may be employed as alluded to above.
[0026] Continuing with reference to FIG. 2, the sealing elements
177 of the packer 175 are shown in an expanded state as directed by
the hydrostatic set module 150 in response to actuation by the
trigger mechanism 130. As described above, the trigger mechanism
130 may be responsive to a wireless signal such as the noted
pressure pulses 201, thereby actuating the module 150 until the
packer 175 is set. Indeed, as the packer 175 is set, wireless
communication with the trigger mechanism 130 are eventually cut
off. Of course, this only takes place once the trigger mechanism
130 and module 150 are no longer needed due to the completion of
the setting application. The wireless communication signal may be
sent through casing annulus as depicted between tubing 110 outside
diameter and casing 285 inside diameter or alternately through the
bore of the tubing 110 itself.
[0027] Referring now to FIG. 3A, an enlarged view of the system 100
is shown taken from 3-3 of FIG. 2 with focus on the hydrostatic set
module 150 and packer 175. In this view, the packer 175 is not yet
set by the module 150. This is apparent as the sealing elements 177
of the packer 175 are shown in an undeployed state and displaying
no sealing engagement with the casing 285 of the well 280.
[0028] With added reference to FIG. 2, the noted lack of sealing
engagement means that wireless communications from the oilfield
surface 200 may reach the trigger mechanism 130 of the module 150
for actuation. More specifically, the pulse generator 265 may be
directed by the control unit 260 to transmit a particular signature
of pressure pulses 201 downhole. These pulses 201 may be detected
and evaluated by the pressure sensor 480 and processor 470 of the
trigger mechanism 130, respectively (see FIG. 4A). Thus, once the
proper signature is detected, the module 150 may be triggered as
described above.
[0029] Referring now to FIG. 3B, the system 100 is now shown with
the packer 175 set following the above-noted activation of the
module 150 by the trigger mechanism 130. As shown, the sealing
elements 177 are now in full sealing engagement with the well
casing 285 and the pulses 201 apparent in FIG. 3A have ceased. In
an alternate embodiment the triggering mechanism 130 may be located
uphole of the isolated location, perhaps along with the module 150
as well.
[0030] In addition to a packer setting application, other
applications may take advantage of a wirelessly triggered
hydrostatic set module 150. For example, the module 150 with
wireless triggering mechanism 130 may be utilized for shifting
sliding sleeves. For example, this may be done to expose or close
perforations 289 such as those shown in FIG. 2. or for opening
and/or closing of a circulating valve for displacement of fluids.
Indeed, multiple modules 150 may be employed such that shifting
open or closed may be undertaken, for example, depending upon the
particular wireless signature employed by the regulator as directed
by the control unit 260. Similarly, a valve, such as a formation
isolation valve, may be linked to wirelessly triggered hydrostatic
set modules 150 for opening or closing thereof according to the
techniques described hereinabove.
[0031] Referring now to FIG. 4A, a schematic view of the system 100
detailed hereinabove is shown. In this view, particular attention
is drawn to the inner workings of the trigger mechanism 130.
However, its hydraulic connection 420 to the hydrostatic set module
150 is also shown along with the hydraulic line 160 disposed
between the module 150 and the packer 175 as referenced above.
Indeed, as also noted above, production tubing 110 is centrally
disposed relative to the overall system 100. Further, the entire
system 100 is disposed within a well 280 such as that of FIG. 2
which is defined by casing 285. In the view of FIG. 4A,
illustration of the casing 285 is limited to portions located
adjacent the packer 175. However, the casing 285 defines a
substantial majority of the well 280 as shown in FIG. 2.
[0032] Continuing with reference to FIG. 4A, the trigger mechanism
130 includes a sensor 480. As detailed above, the sensor 480 may be
a pressure sensor configured to detect pressure pulses directed
from an oilfield surface 201 and/or pressure pulse generator 265.
However, as also noted, a variety of alternate sensor types may be
utilized for detection of surface directed communications. These
may include acoustic sensors, flow meters, strain gauges, and RFID
or pip tag detectors, to name a few. In one embodiment, a pH or
more chemical specific detector may even be employed for detection
of an introduced fluid of a given characteristic. Such detectable
fluid may even consist of the present wellbore fluid that is
altered by the introduction of a pH altering or chemical
presentation slug.
[0033] Regardless of the particular type of sensor 480, its
detection data may be acquired and interpreted by a processor 470
coupled thereto. Indeed, the processor 470 may immediately initiate
triggering as described below upon detection of any surface
directed communication. However, the processor 470 may also be
programmed to initiate triggering upon the detection of a
particular pattern or signature of surface communications. Thus,
the odds of accidental triggering, for example, due to a false
positive detection, may be reduced. Furthermore, the processor 470
may be employed to record and store data from the sensor 480 for
later usage, perhaps unrelated to the triggering detailed
below.
[0034] The processor 470 and any other electronics of the trigger
mechanism 130 are powered by a conventional power source 460 such
as an encapsulated lithium battery suitable for downhole use. More
notably, however, the processor 470 is ultimately wired to a charge
400 that may be fired by the processor 470 as a means of
triggering. In FIG. 4A, the charge 400 remains unfired and isolated
at one side of charge barrier 450. However, upon direction by the
processor 470, the charge 400 is configured to break this bather
450 along with a chamber bather 440, ultimately exposing a chamber
430 to wellbore pressure thereby actuating the hydrostatic set
module 150 as described below.
[0035] Referring now to FIG. 4B, a schematic view of the system 100
is shown in which the charge 400 of FIG. 4A has been set off. Thus,
the trigger of the trigger mechanism 130 has been pulled, so to
speak. That is, based on analysis by the processor 470 of data
obtained from the sensor 480, the charge 400 of FIG. 4A has been
directed to go off, either upon being obtained or perhaps following
a predetermined period of time. As noted above, this data obtained
by the processor 470 relates to wireless surface communications
detected by the sensor 480.
[0036] Once the charge 400 goes off as noted above, the bathers
440, 450 between the charge 400 and the chamber 430 of FIG. 4A are
eliminated. As a result, a port 480 between the chamber 430 and the
wellbore is opened, thereby exposing the chamber 430 to wellbore
pressures. Ultimately, through the hydraulic connection 420, this
leads to actuation of the setting mechanism 150 and hydraulic
expansion of the packer 175 through the line 160. Note, the
schematically depicted sealing engagement between the packer 175
and the casing 285 which is depicted in FIG. 4B.
[0037] The operation of the setting mechanism 150 as described
above is that of an intensifier as would likely be the case for a
conventional packer setting assembly. That is, aside from
modifications for accommodating and coupling to the wireless
trigger mechanism 130, as described above, the setting mechanism
150 may otherwise be a conventional off-the-shelf hydrostatic set
module, for example. Such a module is detailed in U.S. Pat. No.
7,562,712, Setting Tool for Hydraulically Actuated Devices, to Cho,
et al., incorporated herein by reference in its entirety.
[0038] Referring now to FIG. 5, an alternate embodiment of a
wirelessly triggered HSM system 100 is shown in schematic form. In
this embodiment, redundancy has been built into the system 100 with
the addition of a second trigger mechanism 535, a second hydraulic
connection 520 to the HSM 150 and perhaps even a second line 560
therefrom to the packer 175. This added redundancy may be employed
to help ensure that complete triggering and packer setting takes
place. For example, wireless communications through the wellbore
may face interference challenges such as the presence of air in the
case of pressure pulses 201 (see FIG. 2). Nevertheless, the
presence of multiple trigger mechanisms 130, 530 increases the
likelihood of wireless communication detection.
[0039] In one embodiment, wireless communications may take the form
of different signature patterns, independently tailored to each of
the mechanisms 130, 530 to further increase the likelihood of
processed detection. That is to say, the initial sensor 480 and
processor 470 may be tuned to pick up a particular signature of
wireless communications for analysis that differs from another
signature geared toward the second sensor 580 and processor 575.
Thus, where the initial signature fails to fully propagate downhole
to its respective sensor 480 and processor 470, the other signature
may nevertheless reach the second sensor 580 and processor 575 (or
vice versa). Thus, another port 590 may be formed, chamber 530
exposed and the HSM 150 actuated.
[0040] Referring now to FIG. 6, a flow-chart summarizing an
embodiment of employing a wirelessly triggered hydrostatic set
module is shown. As indicated at 615, a downhole system may be
deployed into a well. For embodiments detailed hereinabove, a
production tubing system is described. However, other types of
systems may utilize wirelessly triggered hydrostatic set modules,
such as completion systems utilizing sliding sleeves. Regardless,
once fully deployed, a variety of wireless communication
signatures, such as pressure pulses, may be directed downhole as
indicated at 635 and 655. Thus, a sensor of a trigger mechanism
incorporated into the system may detect downhole communications as
indicated at 675. Ultimately, therefore, a hydrostatic set module
of the system may be triggered by the mechanism based on processing
of the wireless detection (see 695). This in turn may result in
setting of a packer, shifting of a sliding sleeve or any number of
downhole actuations as detailed herein.
[0041] Embodiments described hereinabove reduce the likelihood of
having to remove and re-deploy an entire production string as a
result of hydraulic strain induced on tubing due to packer setting.
This is achieved in a manner that does not require the presence of
a dedicated hydraulic line run from surface to the hydrostatic set
module. As a result, concern over the introduction of new failure
modes is eliminated. Furthermore, techniques detailed herein
utilize wireless communications in conjunction with a hydrostatic
set module that may be employed for a variety of applications
beyond packer setting. Therefore, the value of the systems and
techniques detailed herein may be appreciated across a variety of
different downhole application settings.
[0042] The preceding description has been presented with reference
to presently preferred embodiments. Persons skilled in the art and
technology to which these embodiments pertain will appreciate that
alterations and changes in the described structures and methods of
operation may be practiced without meaningfully departing from the
principle, and scope of these embodiments. For example, redundancy
may be provided by providing an additional triggering mechanisms
and HSM as noted hereinabove. However, redundancy for sake of
ensuring triggering may also be provided to the system by
programming each individual processor to recognize multiple
different types of wireless communication signatures. Furthermore,
the foregoing description should not be read as pertaining only to
the precise structures described and shown in the accompanying
drawings, but rather should be read as consistent with and as
support for the following claims, which are to have their fullest
and fairest scope.
* * * * *