U.S. patent application number 13/188269 was filed with the patent office on 2013-01-24 for downhole fluid-flow communication technique.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is STEFAN I. MOISE, GARY M. ODDIE, ANTHONY F. VENERUSO, JOHN R. WHITSITT. Invention is credited to STEFAN I. MOISE, GARY M. ODDIE, ANTHONY F. VENERUSO, JOHN R. WHITSITT.
Application Number | 20130020097 13/188269 |
Document ID | / |
Family ID | 47554987 |
Filed Date | 2013-01-24 |
United States Patent
Application |
20130020097 |
Kind Code |
A1 |
VENERUSO; ANTHONY F. ; et
al. |
January 24, 2013 |
DOWNHOLE FLUID-FLOW COMMUNICATION TECHNIQUE
Abstract
A method of wireless communication with a downhole assembly in
absence of pressure pulse or hard wired communications. Tools and
techniques for achieving such wireless communications are directed
fluid-flow communication which may be utilized in circumstances
where a completions assembly is open to the well in a pressure
sense. Notably, a trigger is included with detection equipment
which may be utilized to detect fluid-flow generated by surface
equipment. In certain embodiments, such equipment may even be
mounted exterior of completions equipment tubing through which
fluid-flow communication is directed. Thus, wireless downhole
communication capacity may even be provided without the need for
obstructing tubing with such detection equipment.
Inventors: |
VENERUSO; ANTHONY F.; (SUGAR
LAND, TX) ; WHITSITT; JOHN R.; (Houston, TX) ;
ODDIE; GARY M.; (Cambridgeshire, GB) ; MOISE; STEFAN
I.; (CLAMART, FR) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
VENERUSO; ANTHONY F.
WHITSITT; JOHN R.
ODDIE; GARY M.
MOISE; STEFAN I. |
SUGAR LAND
Houston
Cambridgeshire
CLAMART |
TX
TX |
US
US
GB
FR |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
47554987 |
Appl. No.: |
13/188269 |
Filed: |
July 21, 2011 |
Current U.S.
Class: |
166/386 ;
166/72 |
Current CPC
Class: |
E21B 33/127 20130101;
E21B 47/18 20130101; E21B 34/10 20130101; E21B 41/00 20130101 |
Class at
Publication: |
166/386 ;
166/72 |
International
Class: |
E21B 33/12 20060101
E21B033/12; E21B 34/16 20060101 E21B034/16 |
Claims
1. A downhole completions assembly for installation in a well at an
oilfield, the assembly comprising: an application tool for
performing an application at a downhole location in the well; an
actuation tool coupled to said application tool for driving the
performing; and; a trigger coupled to said actuation tool to
initiate the driving and responsive to fluid-flow communication
transmitted through the well from a surface of the oilfield.
2. The assembly of claim 1 wherein said actuation tool is a
hydrostatic set module.
3. The assembly of claim 1 wherein said trigger is a first trigger,
the assembly further comprising an additional trigger responsive to
the communication for redundancy.
4. The assembly of claim 1 further comprising: a pump disposed at
the surface for generating the fluid-flow; and a control unit
coupled to the pump for directing said pump.
5. The assembly of claim 1 wherein said application tool is one of
a packer, a valve, a sliding sleeve, a fluid sampler, a measurement
recorder, and a pyrotechnic device.
6. The assembly of claim 5 wherein the pyrotechnic device is a
perforator.
7. The assembly of claim 5 further comprising production tubing
with the packer disposed thereabout for downhole zonal
isolation.
8. A trigger of a downhole assembly deployed from a surface of an
oilfield, the trigger configured for initiating driving of an
application by an actuation tool of the assembly and comprising
detection equipment for sensing fluid-flow communication from the
surface for the initiating.
9. The trigger of claim 8 wherein the assembly comprises: tubing
accommodating the actuation tool, the trigger coupled thereto; and
an application tool coupled to the actuation tool for the
application.
10. The trigger of claim 9 wherein the fluid-flow communication is
directed through an interior of said tubing and the trigger is
disposed at an exterior location of said tubing.
11. The trigger of claim 10 wherein said detection equipment is one
of calorimetric, acoustic, ultrasonic and electromagnetic.
12. The trigger of claim 8 wherein said detection equipment is one
of calorimetric, acoustic, ultrasonic, electromagnetic,
Venturi-based and flow-based tracer detection equipment.
13. The trigger of claim 12 wherein the calorimetric detection
equipment comprises a heat source in the form of a thermal
resistor.
14. The trigger of claim 13 wherein the resistor is configured to
maintain a pre-determined temperature, a power level required to
maintain the pre-determined temperature indicative of the
fluid-flow communication.
15. The trigger of claim 13 wherein the detection equipment further
comprises: a first temperature sensor disposed uphole of the
resistor; and a second temperature sensor disposed downhole of the
resistor, a flow induced temperature gradient therebetween
indicative of the fluid-flow communication.
16. The trigger of claim 15 wherein said sensors are one of
platinum resistor temperature devices and thermocouples.
17. A method of actuating a downhole tool at a location in a well
from an oilfield surface, the method comprising: initiating a
fluid-flow signal at the surface with equipment thereat; and
detecting the fluid-flow signal at a flow-meter of a trigger in the
well coupled to an actuator.
18. The method of claim 17 further comprising utilizing the trigger
to actuate the tool at the location with the actuator based on said
detecting.
19. The method of claim 17 wherein said detecting further
comprises: sampling periodic detections with the trigger in a sleep
mode; and activating a listening mode of the trigger for actuating
the tool at the location with the actuator based on detections
reaching a pre-determined substantially stable level.
20. The method of claim 19 further comprising: employing a
time-delay between said detecting and the actuating; and sending a
fluid-flow cancellation communication with the equipment to
terminate the actuating.
21. The method of claim 17 further comprising circulating fluid
including the fluid-flow signal downhole and uphole within the well
following said initiating to substantially avoid a net addition of
fluid to the well.
22. The method of claim 17 further comprising discarding detections
from said detecting which measure flow rate below a few centimeters
per second.
23. The method of claim 17 further comprising discarding detections
from said detecting which are substantially discontinuous.
24. The method of claim 17 wherein said initiating is of a first
fluid-flow signal directed at the trigger, the method further
comprising sending a second fluid-flow signal into the well with
the equipment.
25. The method of claim 24 wherein the trigger is a first trigger,
said sending comprising directing the second fluid-flow signal at a
second trigger in the well.
26. The method of claim 17 wherein the surface is a seabed and the
fluid-flow signal is initiated by equipment coupled to a well head
thereat.
Description
FIELD
[0001] Embodiments described relate to tools and techniques for
wireless actuation of a downhole tool. In particular, equipment and
techniques for fluid-flow communication and actuation in a
substantially "open-hole" or non-pressurizable environment relative
to the tool's downhole pressure environment are described. Packers,
hydrostatic set modules, and zonal isolation are detailed in this
regard. However, communication to and/or actuation of a variety of
alternative tools and downhole circumstances may be applicable.
BACKGROUND
[0002] Exploring, drilling and completing hydrocarbon and other
wells are generally complicated, time consuming, risky 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 minimize risks, maximize production and
extend well life. Thus, a substantial return on the investment in
the completed well may be better ensured.
[0003] Completions assemblies, which govern production through the
well, are generally outfitted with fairly standard equipment in
line with the objectives of maximizing cost effectiveness and
overall production. For example, the well may be tens of thousands
of feet deep and traverse a variety of different formation layers.
Therefore, the completions assembly may be outfitted with a host of
different sliding sleeves, packers and other location specific
equipment for aiding and directing production. In a more specific
example, 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.
[0004] Setting of packers and other actuations may be directed over
a power data cable running from surface to a downhole setting tool.
However, in circumstances where such a cable serves no significant
other useful purpose, efforts are generally undertaken to avoid
cable use in directing one-time actuations such as packer setting.
Alternatively, wireless pressure pulse communication between
surface and a downhole setting tool may be employed. In this
manner, use of dedicated, non-ergonomic cabling may be avoided. As
a practical matter, this may be a significant benefit given the
expense, risks and nature of installing and working around several
thousand feet of cumbersome cabling.
[0005] Unfortunately, pressure pulse communication is not always
available or effective. This is because in order for such
communications to take place, a substantially closed completions
assembly is required. That is, in a pressure sense, in order to
effectively propagate a pressure pulse signal from surface
equipment, throughout the assembly, and toward an actuator tool, a
substantially closed fluidic system is required. However, in many
circumstances, such a system is not available or effective. For
example, the completions assembly may be completely open to the
well at its terminal end or perhaps outfitted with a slotted liner.
In fact, even the presence of a significant number of perforations
running along the assembly as it traverses different formation
layers may provide enough `openness` to the system to render
pressure pulse communication ineffective because such pressure
pulses are dissipated, attenuated or absorbed by those opened
layers' permeable formations and natural pressure sources.
[0006] Most completions assemblies don't require long-term power
supply or dedicated monitoring. Therefore, as a matter of cost and
ergonomics, cabling as described above is generally avoided.
However, with a dedicated power data cable unavailable, options for
actuating a downhole tool are limited. This is particularly true
where wireless pressure pulse communication is unavailable due to
openness of the completions assembly in circumstances such as those
described above.
[0007] Alternatively, other wireless communications methods, based
on either electromagnetic or acoustic techniques, may also be
unavailable or ineffective for communications. For example, in deep
water or sub-sea well completions applications the communications
media may absorb or dissipate the electromagnetic or acoustic
signal's power to the extent that such communications are rendered
indistinguishable from noise or require an unacceptable number of
expensive or complex repeaters.
[0008] Indeed, in situations where cable, pressure pulse and
wireless electromagnetic and acoustic communications are
unavailable or ineffective, a separate, mechanically based
interventional application is required for actuation of a downhole
tool. So, for example, rig operations may be halted, surface
equipment rigged up for a new intervention, and one or more packer
setting applications carried out. This would then be followed by
retrieval of interventional tools followed by re-establishing of
production equipment and operations. Of course, all of this may
halt operations for anywhere between hours and days, thereby
driving costs up by tens if not hundreds of thousands of dollars.
Nevertheless, where cable and pressure pulse communications are
either unavailable or ineffective, operators are presently left
with no viable alternative to such costly single shot
interventions.
SUMMARY
[0009] A method of actuating a downhole tool at a location in a
well is detailed. The method is directed from the oilfield surface
and includes sending a fluid-flow signal therefrom. The fluid-flow
signal is detected at a flow meter in the well which is coupled to
an actuator via appropriate signal processing, control and power
circuitry. A tool disposed at the noted location may thus be
actuated by the actuator. A completions assembly is also detailed
which utilizes an application tool for performing an application in
the well as driven by an actuation tool of the assembly. Thus, a
trigger that is responsive to fluid-flow communication from the
oilfield surface is also provided which is coupled to the actuation
tool in order to initiate the driving of the application.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] FIG. 1 depicts a front view of an embodiment of a
completions assembly with a tool in the form of a packer configured
for fluid-flow actuation.
[0011] FIG. 2 is an overview of an oilfield with a well
accommodating the assembly of FIG. 1 with the packer therein and
set via fluid-flow actuation.
[0012] FIG. 3A is an enlarged view of an embodiment of a flow-meter
taken from 3-3 of FIG. 2, shown disposed adjacent a setting tool
for the packer.
[0013] FIG. 3B is an enlarged view of an alternate embodiment of a
flow-meter shown disposed adjacent the setting tool.
[0014] FIG. 4A is an enlarged view of the assembly positioned at a
location in the well for isolation.
[0015] FIG. 4B is an enlarged view of the assembly of FIG. 4A with
the packer deployed via fluid-flow communication to achieve the
isolation.
[0016] FIG. 5 is a partially cross-sectional schematic of the
assembly of FIG. 4B revealing fluid-flow and setting tool mechanics
utilized in the packer deployment.
[0017] FIG. 6 is a flow-chart summarizing an embodiment of
actuating a downhole tool via fluid-flow communication as directed
from an oilfield surface.
[0018] FIG. 7 is a block diagram summarizing an embodiment of a
downhole electronic system that implements the functions
illustrated in FIG. 6.
DETAILED DESCRIPTION
[0019] Embodiments herein are described with reference to certain
downhole completions assemblies and operations. For example,
assemblies are depicted herein that make use of packers for
downhole isolation. However, a variety of alternate applications
may take advantage of embodiments of actuating tools and techniques
detailed herein. For example, actuations may relate to opening and
closing barrier valves or shifting sliding sleeves. Furthermore,
control over downhole fluid samplers or measurement recording
devices may be exercised through such actuations. Even pyrotechnic
devices such as perforators may be actuated according to techniques
described herein. Regardless, the particular application, however,
fluid-flow communication directed from surface may be utilized to
initiate the actuation thereof.
[0020] Referring now to FIG. 1, a front view of an embodiment of a
completions assembly 100 is shown. The assembly 100 includes
production tubing 110 outfitted with a packer 175 having a host of
seals 177 to provide downhole isolation as described below.
However, in other embodiments, the completions assembly 100 may
take a variety of different forms utilizing a host of different
downhole actuatable tools aside from, or in addition to, the
depicted packer 175.
[0021] In the embodiment shown, the completions assembly 100 is
also equipped with an actuation tool in the form of a hydrostatic
set module 150. The hydrostatic set module 150 uses hydrostatic
pressure from the well relative to atmospheric pressure to displace
a piston and perform work. However, alternative forms of actuation
tools may be employed. Perhaps more notably, the assembly is also
equipped with a fluid-flow trigger 137. That is to say, the trigger
137 is activated by way of fluid-flow communication which is
generated at surface as detailed hereinbelow. Indeed, the trigger
137 includes a flow meter mechanism 135 along with an electronics
and power housing 130 which are coupled to the module 150. The
module 150 is in turn coupled to the packer 175 via a hydraulic
line 160.
[0022] Referring now to FIG. 2 an overview of an oilfield 200 is
shown revealing the manner in which the assembly 100 is able to
take advantage of fluid-flow communication for single shot
actuations such as setting of its packer 175. Indeed, in FIG. 2,
the oilfield 200 is shown with a well 280 accommodating the
assembly 100 of FIG. 1 with the noted packer 175 therein having
been set via fluid-flow actuation. Note the actual fluid-flow 201
travelling from surface, through production tubing 110 and past the
trigger 137 to direct packer setting as described further below. In
the embodiment of FIG. 2, the oilfield 200 it terrestrial. However,
in other circumstances, the oilfield 200 may be subsea with
equipment 225 coupled to a well head 250 at the seabed.
[0023] Continuing with reference to FIG. 2, the well 280 is shown
traversing various formation layers 290, 295. The well 280 is
defined by a casing 285 until reaching a production region 287 with
a host of perforations 289 into one of the layers 295. Thus, in a
pressure sense, the well 280 may be considered `open` relative to
the pressure of the production region 287. Nevertheless, the seals
177 of the packer 175 are shown in a fully deployed or set state,
triggered without necessity of pressure pulse communication from
surface. Further, as noted, fluid-flow actuation of packer setting
is employed so as to avoid the need for cumbersome cabling running
from surface to the packer 175. More specifically, the indicated
fluid-flow 201 is utilized to direct a trigger 137 to initiate
packer setting through the hydrostatic set module 150 adjacent the
packer 175.
[0024] Setting of the packer 175 via the fluid-flow 201 may be
initiated by a pump 265 as directed by a control unit 260 disposed
at the surface of the oilfield 200. Indeed, a host of surface
equipment 225 may be disposed at surface for directing packer
setting along with a variety of other oilfield operations. As
shown, a rig 230 is provided to support initial completions
operations as well as any number of subsequent interventions and
related equipment. Further, the noted control unit 260 and pump 265
are coupled to a well head 250 which not only mediates the
fluid-flow 201 but also plays a role in recovery of production
fluid. Note the production line 255 also emerging from the well
head 250. Alternatively, for deepwater or subsea applications, the
pump 265 may be coupled to a well head 250 situated at the
seabed.
[0025] As detailed further below, the fluid-flow 201 may be made to
occur in detectable rates or signature patterns that allow for the
directing of downhole equipment such as the module 150 via the
indicated trigger 137. Indeed, additional triggers and equipment
may be provided downhole such that multiple uniquely different
fluid-flow commands may be separately utilized to direct a host of
different downhole actuations of the same assembly 100. Similarly,
multiple triggers 137 may be provided to direct the same actuation,
such as setting of the packer 175 as depicted. Thus, a degree of
fail-safe redundancy may easily be added to the system.
[0026] Referring now to FIGS. 3A and 3B, enlarged views of
different embodiments of flow-meter detection equipment 335, 350
are depicted. That is, the flow-meter mechanism 135 may incorporate
different types of detection equipment 335, 350 such as these and
others. Ultimately, this detection equipment 335, 350 provides the
trigger 137 with the capacity to responsively trigger the module
150 upon detection of certain fluid-flow 201. More specifically,
the flow meter detection equipment 335 of FIG. 3A is of a
calorimetric variety whereas the flow meter detection equipment 350
of FIG. 3B is piezo-electric based. However, a variety of
alternative flow-meter types may also be effectively utilized.
[0027] Referring specifically to FIG. 3A, the enlarged view of the
flow-meter 135 shown is taken from 3-3 of FIG. 2. The detection
equipment 335 of this flow-meter 135 is incorporated into the
larger trigger 137 for disposal adjacent the setting module 150 to
set the packer 175 of FIGS. 1 and 2. In the embodiment of FIG. 3A,
the detection equipment 335 includes a heat source 339 such as a
thermal resistor. Further, temperature sensors 337, 338 are
disposed at either side, uphole and downhole, of the source 339.
These sensors 337, 338 may be conventional thermocouples, platinum
resistors or other suitable resistor temperature devices
(RTD's).
[0028] As shown in FIG. 3A, with added reference to FIG. 2, the
detection equipment 335 is disposed exterior of the tubing 110 of
the assembly 100. Nevertheless, due to thermal functionality, the
detection equipment 335 is able to conductively drive heat to the
interior of the tubing 110 such that flow 201 therein may be
tracked. More specifically, the heat source 339 may form a heated
region 300 within the tubing 110. The profile of this region 300
may be affected by downward moving fluid-flow 201, for example,
such that a hotter portion 301 of the region, or its gradient, may
be distinguishingly detected by the downhole sensor 338. Such a
detection, at only the downhole sensor 338, may be communicated
through the flow-meter 135 to electronics 130 thereof to allow
detailed analysis of the flow 201. That is, changes in flow rate
directed from the control unit 260 and pump 265 at surface may be
detected as fluctuating changes in temperature by the detection
equipment 335.
[0029] The calorimetric-based flow-meter 135 of FIG. 3A provides
unique advantages in evaluating the flow 201 due to the comparative
detections available from multiple sensors 337, 338. Once more, due
to the thermal nature of how the flow-meter 135 operates, it may be
disposed exterior of the tubing 110. In this regard, the structure
of the flow-meter 135 may be embedded into the wall of the tubing
110 to a degree so as to ensure adequate thermal contact as shown.
Regardless, due to the non-intrusive location of the flow-meter
135, any tubing intervention or intentional flow through the tubing
110 is unaffected by the presence of the flow-meter 135. By the
same token, in another embodiment, the detection equipment may be
externally disposed acoustic, ultrasonic or electromagnetic
equipment.
[0030] In terms of accuracy, a flow-meter 135 utilizing
calorimetric detection equipment 335 may effectively detect the
rate of fluid-flow 201 to within about 10% accuracy for
conventional downhole fluids such as water, brine and acid. Once
more, in an alternate embodiment, a degree of accuracy may be
attained even where the calorimetric detection equipment 335
includes a heat source 339 without the presence of sensors 337,
338. That is, electronics 130 of the trigger 137 or elsewhere may
be utilized to monitor the amount of power required to maintain the
heat of the thermal resistor source 339 at a predetermined level.
For example, this may be achieved by supplying the resistor source
339 with a constant voltage while measuring the current maintaining
that voltage. Thus, such power data may be translated to provide
information regarding the rate of fluid-flow 201 within the tubing
110.
[0031] Referring now to FIG. 3B, an enlarged view of an alternate
embodiment of flow-meter detection equipment 350 is shown disposed
within the tubing 110. In this case, a piezo element 357 is
suspended by support structure 355 within the tubing 110 for
detection of fluid-flow 201. Data regarding vibrations of the
element 357 may be carried, via wiring 359, to the flow-meter 135
and electronics 130 of the trigger 137. Indeed, where interference
with the internal diameter of the tubing is of negligible concern,
a host of other types of detection equipment may also be employed.
For example, the equipment may be a venturi type of detector or
flow-based tracer detection equipment.
[0032] Referring to both FIGS. 3A and 3B, accuracy for any type of
detection equipment 335, 350 may be enhanced by utilization of
notably decipherable flow-rates. For example, there may be a
tendency for the heated region 300 or piezo element 357 to
fluctuate slightly even without the introduction of fluid-flow 201.
Therefore, detected flow rates that are discontinuous or below a
few centimeters per second may be discarded as noise.
[0033] Continuing with reference to FIGS. 3A and 3B, the fluid-flow
201 is shown internal to the tubing 110. However, the trigger 137
may be configured and oriented as necessary to detect fluid-flow
201 external to the tubing 110. Once more, where desired, the
fluid-flow 201 may be circulated such that no net addition of fluid
is provided in order to activate the trigger 137. Further, in
addition to avoiding a net add of fluid to the system, the
magnitude of the fluid-flow 201 may be kept to a minimum so as to
also avoid interferences such as temporary discrete pressure
increases.
[0034] Referring now to FIGS. 4A and 4B enlarged views of the
assembly 100 are depicted at a location in the well 280 for
isolation. More specifically, FIG. 4A depicts the packer 175 of the
assembly 100 positioned but not deployed at the location whereas
FIG. 4B depicts the full isolating deployment of the packer seals
177 at the location. Indeed, the fluid-flow 201 detailed above is
shown travelling through the cross-sectionally depicted tubing 110
of FIG. 4A, ultimately resulting in fluid-flow actuation of the
packer 175 shown in FIG. 4B.
[0035] With specific reference to FIG. 4A, the completions assembly
100 is located in the well 280 with the packer 175 positioned
immediately above the production region 287 of FIG. 2. Thus, the
open ended production tubing 110 may be well located for receiving
and carrying away of production fluids upon isolation. Therefore,
in order to initiate the isolation of the well 280 via the packer
175, a signature or pattern of fluid-flow 201 is directed from
surface past the trigger 137. Where calorimetric detection
equipment 335 is employed as depicted in FIG. 3A, this may involve
the inducing of a substantial thermal variance between the sensors
337, 338. Regardless, the signaling mechanism, the trigger 137 may
ultimately direct the hydrostatic set module 150 to initiate packer
setting via a hydraulic line 160.
[0036] With reference to both FIGS. 4A and 4B, and with added
reference to FIG. 3A, as a matter of power savings, the trigger 137
may switch between sleep and listening modes. For example,
detection equipment 335 may take periodic temperature samples in
sleep mode. This may be followed by switching to a more active
`listening` mode only once pre-determined substantially stable
temperature readings, indicative of proper positioning at the
downhole location, are detected. Thus, drain on a dedicated
downhole power source (e.g. of the power housing 130) may be kept
to a minimum.
[0037] Additionally, triggering of the setting may require that the
fluid-flow 201 employed be of a particular signature. Thus, the
odds of accidental misfiring may be reduced. Indeed, in one
embodiment, detection of the unique flow signature may result in a
delayed actuation. In this manner, an operator may be provided with
the opportunity to send a cancellation flow signature downhole.
[0038] Ultimately, with particular reference to FIG. 4B, the packer
375 is shown with seals 177 deployed into isolating engagement with
the casing 285 which defines the well 280. This is achieved by way
of the hydrostatic set module 150 as directed by the trigger 137
which is set off by fluid-flow communication sent from surface.
Thus, no pressure pulse or hard wired communication is
required.
[0039] Referring now to FIG. 5, a partially cross-sectional
schematic of the assembly of FIG. 4B is shown. In this depiction,
fluid-flow 201 and hydraulics from the hydrostatic set module 150
are more specifically illustrated. For example, the signature of
fluid-flow 201 for detection by the trigger 137 as described above
is shown making its way downhole within the production tubing 110.
It is worth noting that uphole travelling fluids may also be
present in the annulus outside of the tubing 110, prior to setting
the packer 175. Regardless, these fluids are prevented from further
uphole travel outside of the tubing 110 after the packer 175 is
actuated. This is due to isolation by the set seals 177 of the
packer 175 (also, cross-sectionally depicted as an isolation zone
577).
[0040] Continuing with reference to FIG. 5, a piston 525 is shown
moving in an uphole direction (see arrow 500). Thus, compression on
the packer 175 sufficient to achieve isolating engagement of the
seals 177 with the casing 285 may be provided. Thus, the noted
isolation zone 577 is depicted. More specifically, as alluded to
above the trigger 137 may play a role in initiating a dramatic
increase in hydrostatic pressure within a chamber 510. This chamber
510 is in dynamic communication with a head of the indicated piston
525 so as to affect its shift in the uphole direction 500, thereby
resulting in setting of the packer 175 as described.
[0041] Referring now to FIG. 6, a flow-chart summarizing an
embodiment of actuating a downhole tool via fluid-flow
communication as directed from an oilfield surface is depicted.
Notably, the techniques of this embodiment allow for downhole
signaling and communication to be achieved over an assembly that is
pressurably open to a well as indicated at 610 without the need for
the use of hard wired communications. That is, a fluid-flow
communication may be utilized as indicated at 620 that is
detectable by a downhole trigger of the assembly as indicated at
630.
[0042] For sake of power savings, the trigger may initially be
utilized in a sleep mode with flow detections being periodic as
noted at 650. However, as indicated at 660, a listening mode may be
utilized upon encountering a predetermined set of criteria. Thus,
fluid-flow activation as communicated from surface may be
identified by the trigger (see 670). Ultimately, this
identification may result in the initiating of a downhole actuation
as indicated at 680, for example, the setting of a packer as
detailed hereinabove.
[0043] In another embodiment, a built-in delay in advance of the
actuation may be utilized in conjunction with the noted
identification. In this manner, time may be allotted for an
operator at surface to send a fluid-flow cancellation signal as
indicated at 640. Thus, the pending downhole actuation may actually
be terminated as indicated at 690. Of course, with such fluid-flow
signaling available, any number of such communicative measures and
countermeasures may be undertaken.
[0044] Referring now to FIG. 7, a functional block diagram
summarizing an embodiment of a downhole electronic system that
implements the functions illustrated in FIG. 6 and described in the
above paragraphs. Following the novel concepts herein described the
detailed design, production and operation of such a system for a
specific application can be carried out by those skilled in the
art.
[0045] Embodiments described hereinabove allow for downhole
actuations to be directed from surface even in circumstances where
physical cables or fiber optics from surface are lacking and
pressure pulse, electromagnetic or acoustic communication methods
are unavailable or ineffective. These fluid-flow based
communications also obviate the need for separate interventional
applications in order to actuate downhole tools for particular
applications. As a result, interruption of downhole operations is
avoided along with the delays, risks and expenses of added rig-up
time and the positioning of added large scale equipment. Thus,
countless hours and dollars may be saved through use of the
embodiments detailed herein.
[0046] 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. 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.
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