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.

Description

FIELD

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

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.

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.

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.

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.

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.

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.

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

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

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.

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.

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.

FIG. 3B is an enlarged view of an alternate embodiment of a flow-meter shown disposed adjacent the setting tool.

FIG. 4A is an enlarged view of the assembly positioned at a location in the well for isolation.

FIG. 4B is an enlarged view of the assembly of FIG. 4A with the packer deployed via fluid-flow communication to achieve the isolation.

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.

FIG. 6 is a flow-chart summarizing an embodiment of actuating a downhole tool via fluid-flow communication as directed from an oilfield surface.

FIG. 7 is a block diagram summarizing an embodiment of a downhole electronic system that implements the functions illustrated in FIG. 6.

DETAILED DESCRIPTION

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.

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.

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.

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.

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.

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.

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.

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.

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).

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

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.

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.

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.

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.

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.

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.

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.

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.