System and method for detection of actuator launch in wellbore operations

A system and method are provided for confirming the launch of an actuator for delivery downhole into a wellbore for engagement with a downhole tool such as a packer, sliding sleeve and the like. A wellhead assembly has an axial wellbore in communication with the wellbore. An actuator launcher is located above the wellhead assembly for selectively releasing actuators into the axial wellbore. At least one waypoint is located in the axial bore. A detection device is mounted on the wellhead assembly capable of detecting receipt of a released actuator at the waypoint and generating a confirmation signal in response. A control system receives the confirmation signal, distinguishing between a successful launch and a non-successful launch of the actuator, and producing an output indicating whether introduction of the actuator was successful, the size and material of the actuator, and other pertinent information.

FIELD

Embodiments disclosed herein generally relate to a method and apparatus for detecting the launch of actuators, such as drop balls, frac balls, packer balls, darts, sleeves, and other downhole valve actuation mechanisms, to be injected into a wellbore for interacting with downhole tools, and determining their size.

BACKGROUND

It is known to conduct fracturing or other stimulation procedures in a wellbore by isolating zones of interest or intervals within a zone) in the hydrocarbon-bearing locations of the wellbore, using packers and the like, and subjecting each isolated zone to treatment fluids, including liquids and gases, at treatment pressures. For example, in a typical fracturing procedure for a cased wellbore, the casing of the well is perforated or otherwise opened to admit oil and/or gas into the wellbore and fracturing fluid is then pumped into the wellbore and through the openings. Such treatment forms fractures and opens and/or enlarges drainage channels in the formation, enhancing the producing ability of the well. For open holes that are not cased, stimulation is carried out directly in the zones or zone intervals.

It is typically desired to stimulate multiple zones in a single stimulation treatment, typically using onsite stimulation fluid pumping equipment and a plurality of downhole tools, including packers and sliding sleeves, each of the packers located at intervals for isolating one zone from an adjacent zone. Sliding sleeves can be located between packers and are selectively actuable through introduction of an actuator into the wellbore to selectively engage one of the sleeves in order to block fluid flow thereby whilst opening the wellbore to the isolated zone uphole from the actuator for subsequent treatment or stimulation. Once the isolated zone has been stimulated, a subsequent ball is dropped to block off a subsequent sleeve, uphole of the previously blocked sleeve, for isolation and stimulation thereabove. The process is continued until all the desired zones have been stimulated. Typically, the actuators are balls that range in diameter from a smallest ball, suitable to travel past uphole sleeves to engage and block the most downhole sleeve, to the largest diameter, suitable for blocking the most uphole packer.

Once the isolated zone has been stimulated, a subsequent ball is dropped to block off a subsequent packer, uphole of the previously blocked packer, for isolation and stimulation thereabove. The process is continued until all the desired zones have been stimulated. Current methods and apparatus typically employ a launcher containing a plurality of actuators to be injected into the wellbore. In typical configurations, actuators are stored in a magazine or several magazines and, when injection of an actuator is desired, introduced into an axial bore axially aligned with the wellbore and pumped down with fracturing fluid.

Using actuator balls for example, while the launcher may have all the sizes of balls need for all the zones, a large and potentially expensive area of risk is the successful selection of the appropriate ball size, successful launch, and actual arrival of the ball at the downhole sleeve. While selection of the correct ball size is typically managed by proper surface procedures, e.g. ball size and launch indicators, an actuator may, once launched, fail to be successfully introduced into the wellbore. Such failures can be due to a variety of reasons, including the actuator becoming stuck in the launcher or the wellhead. The majority of instances where an actuator becomes stuck typically occur before the actuator reaches the wellbore, such as in equipment bores, including those of remote valves, blocks, wellhead components, or other components. For example, at low temperatures, an actuator can become stuck due to moisture in an auxiliary line, remote valve, actuator injector, or other components freezing and obstructing the movement of either the actuator or the mechanisms that move the actuator into the axial bore.

In typical treatment operations, successful transit of a dropped actuator, and actuation of a sleeve, packer, or other downhole tool, is confirmed by monitoring fluid pressure in the tubing string. A pressure spike is indicative of successful actuation by a dropped actuator. A lack of a pressure spike or a pressure spike of lower magnitude than expected is indicative of failed or partial engagement. The actuator can travel kilometers before reaching its target downhole tool. Confirming whether an actuator was successfully launched by waiting for a fluid pressure spike is inefficient, as it requires time and the unnecessary expenditure of fracturing or treatment fluid before failure or success can be determined. There is still a need to more expeditiously and reliably confirm successful actuator release to the wellbore.

SUMMARY

When injecting actuators, such as balls, during treatment operations using actuator injectors, it is advantageous to determine that an actuator was successfully launched from an actuator injector, through the wellhead components, and into the fluid stream pumped into the wellbore soon after a launch is initiated, thereby saving time and avoiding unnecessary expenditure of treatment fluids to obtain confirmation of successful actuation via a fluid pressure spike.

In one broad aspect, a system for confirming the launch of an actuator for delivery downhole into a wellbore, comprises: a wellhead assembly having an axial bore in communication with the wellbore below; a launcher above the wellhead for selectively releasing an actuator to the axial bore below; a waypoint in the axial bore; a detection device for generating confirmation signals related to receipt of a released actuator at the waypoint; and a control system for receiving the confirmation signals and distinguishing between a successful launch and a non-successful launch of the actuator.

In embodiments, the detection device is acoustically coupled to the waypoint directly or through the wellhead assembly.

In another embodiment, the waypoint can be a protrusion into the axial bore or a gate valve, and in another embodiment, the detection device is acoustically coupled to the gate.

In another embodiment, the waypoint comprises two or more waypoints spaced along the axial bore, each waypoint acoustically coupled to the detection device; and the control system receives the confirmation signals related to the two or more waypoints. The locational relationship of the two or more waypoints can be known and the control system compares the timing of the confirmation signals at each waypoint for confirmation of receipt of the actuator.

In another embodiment, the confirmation signal is an electric signal.

In another embodiment, the wellhead assembly further comprises at least a first gate valve located above a fracturing header; and the first gate valve forms the waypoint, and the detection device is in vibrational communication with a stem or gate of the first gate valve.

In another embodiment, a vibration conductor extends between the stem and the gate of the first gate valve.

In another embodiment, the detection device is a piezoceramic sensor or an ultrasonic sensor.

In another embodiment, the receipt of a released actuator at the waypoint creates vibrations, such as sound.

In one broad aspect, a method of confirming the launch of an actuator into a wellbore, comprises: introducing an actuator into the axial bore of a wellhead assembly in fluid communication with the wellbore; and detecting receipt of the actuator at a waypoint located in the axial bore.

In an embodiment, detecting receipt of the actuator at the waypoint further comprises detecting vibration at the waypoint.

In another embodiment, detecting vibration at the waypoint further comprises distinguishing said vibration from background vibration.

In another embodiment, the method of confirming the launch of an actuator further comprises: recording a first time of launch; recording a second time of detection of the vibration at the waypoint; and comparing the first and second times to distinguish successful launch of the actuator.

Confirmation of the introduction of an actuator into the wellbore also allows for more accurate estimation of when the actuator is expected to reach the intended downhole tool. Time accuracy is preferred so that the rate of fluid flow into the wellbore can be slowed just prior to the actuator engaging with the downhole tool, increasing the likelihood of successful engagement between the actuator and the downhole tool.

DETAILED DESCRIPTION OF THE EMBODIMENTS

In embodiments described herein, a system and method is disclosed for detecting the successful introduction of an actuator10, of a plurality of actuators, into a wellbore12for actuation of downhole tools such as valves. A wellhead assembly20, comprising at least an actuator launcher22and a frac header24therebelow is secured to the wellbore12and having a common axial bore30therewith.

The axial bore30is fit with one or more actuator waypoints32and one or more detection and control devices34,36are connected to the system for confirmation of launch of an actuator.

Each detection device34is configured to detect arrival of the actuator10at the waypoint32. While cooperative actuators10and waypoints32could be provided, such as RFID technology, typically the actuators are dumb, and herein, detection is based on one sided detection, such as vibrations generated by receipt of the actuator at the waypoint. The detectors34are mounted at suitable locations on a fracturing system to detect receipt of the actuator10such as through vibrations generated at the waypoint32and detected through a vibration or acoustic path from the waypoint32to a sensor of the detection device34for confirmation of receipt.

For example, an actuator10can be received at a waypoint32in the axial bore30, which can be an obstruction such as a gate40of a closed gate valve42. Vibrations from said receipt are transmitted to a detection device34in the gate40, or through the gate valve42or wellhead assembly20to a detection device34remote from the waypoint32. Similarly, as shown below (FIG. 2), a waypoint can be a protrusion52located in the common axial bore30of the fracturing system or within the wellbore12.

Vibrations are converted by the detection device34for generation of confirmation signals54, which can in turn be converted into a binary signal, for example “received” or “not received”, or a time-based signal. The signal is indicative of whether an actuator30was successfully introduced into the wellbore. If confirmation signals are received, the operator can have a high expectation that the launch was successful.

Actuators10can be balls, darts, sleeves, and any other device known in the art for actuating downhole valves. References herein to balls, darts, sleeves, and similar devices refer to all such devices and variants known in the art. Vibrations can be physical vibrations, acoustic vibrations, or other vibrations suitable for determining whether an actuator has been introduced into the wellbore.

In an embodiment, as shown inFIGS. 1A to 2, wellhead/fracturing system100can comprise a fracturing header (frac header)24and an actuator launcher22located above, and connected to, the frac header24. All the fracturing system components can have a common axial bore30and be fluidly connected to the wellbore12for launching actuators10into the wellbore12during fracturing operations. At least one actuator waypoint32can be located in the bore30, such as the gate40of a gate valve34.

The waypoint32is a feature in the wellhead assembly20that interacts with the actuator10as it moves through the connected bores from the launcher22and the balance of the wellhead assembly to the wellbore12. The actuator10stops at or passes the waypoint32, and its passage is noted. The detection of the actuator passage thereby is distinguishable over the background energy and matter, including the flow of fluids thereby, or elsewhere in the system. The detector34establishes signals54that meet a detection threshold or detection characteristic that can be isolated from non-actuator events including fluid flow, connected equipment vibration, and the like.

Each waypoint32is an identifying feature for actively and/or passively identifying the actuator10as it passes thereby. Examples of passive detectors include Hall effect sensors and electronically coupled identification (RFID). Active identification includes a transfer of energy by the actuator10moving through the bore and the components of the wellhead assembly, to the waypoint32. Energy transfer can include contact between the actuator10and one or more components, including a stop, such as at a closed gate valve42, or passing by a diverting projection or protrusion52in the axial bore30. As shown inFIG. 2, one or more protrusions52can extend radially inwards from the wall of the bore30, each protrusion shaped and sized to impinge on the path of actuator10as it passes thereby. Protrusions52do not stop the actuator10.

Distinguishing actuator passage from the background energy or matter can be accomplished through a detection signal54greater than a threshold, or a pattern from two or more detection thresholds. A pattern could include two or more interactions of the actuator10, or an event and an actuation interaction. For example, as shown inFIG. 3Ain one embodiment, a control system36comprising one or more output devices60can be configured to process the signals from one more of detection devices34detecting the interaction of the actuator10with two or more axially spaced waypoints32,32. Alternatively, a first time can be at the time of the signal to release an actuator10, and a second time is at the time of detection of the actuator's passage at a waypoint32at a pre-determined time or delay. The time elapsed between the first time and second time can be analyzed. If the elapsed time is within an expected range, then the detected signal54can be considered as indicative of actuator receipt as opposed to background signal.

In embodiments, multiple detection devices34can be mounted at about the same axial location on the wellhead assembly20to provide a measure of redundancy. The multiple detection devices34can be the same or different types, for example an ultrasonic detection device and a vibrational knock sensor. The signals54generated by the axially coinciding detection devices34can also be used to distinguish vibrations generated by an actuator10interacting with waypoint32from background noise. For example, if a first detection device34detects a signal greater than a threshold, but a second detection device34does not, diagnostic processes can be performed on the signals detected by the detection devices34,34to determine whether the first detection device returned a false reading or if the second detection device is faulty.

Launcher22can be a component for manually introducing one actuator10at a time, such as a T-valve, or for storing a plurality of actuators10,10,10. . . and remotely and sequentially introducing the actuators10into the bore30. Frac header24can have fluid inlets26,26for the introduction of fracturing fluid. The wellhead assembly20can include other equipment known in the art for providing safe and controlled access to the wellbore12.

A detection device34can be connected to the fracturing system to detect vibrations generated by a dropped actuator10interacting with waypoint32. Detection device34can comprise a transducer56or other component configured to detect the vibration caused by actuator10and generate an electrical confirmation signal54as a response. A transducer56can be incorporated into detection device34or be a discrete component connected to detection device34such as by a wire or through wireless communication. References herein to attaching detection device34to components refer to attaching the detection device34containing an integrated transducer56and/or attaching a discrete transducer56to said components. In embodiments, multiple detection devices34or transducers56can be mounted or embedded at various locations of the fracturing system100.

The electrical confirmation signal54from detection device34can be converted by the detection device34or one or more output devices60, which can comprise part of a control system36, into an output61,62, which can be analyzed to determine whether an actuator10has reached, interacted, or been received by, the waypoint32. Output device60can be integral with detection device34or be a separate component. The output can be a simple binary indicator, such as a light61which illuminates when vibrations, generated from the actuator10impacting waypoint32, exceed a threshold. The output can also be more complex, such as a time-based waveform62, for example, indicating the amplitude of the detected vibration displayed on a monitor of output device60. Amplitude and other more complex signal analysis can aid in distinguishing the event from background noise conducted to the detection devices, or information related to the actuator itself or its arrival. Waveforms or other outputs which provide information regarding the characteristics of the detected vibration can be further analyzed to provide information such as the size of the launched actuator, either in absolute terms or relative to a previously dropped actuator or a known reference waveform, as well as the weight, material, and other properties of the actuator detected. This can be useful to allow the operator to determine whether the correct actuator10was launched, for example in embodiments where multiple actuators10,10. . . are to be injected into the wellbore12in a sequence.

Such analyses can be performed by an operator or by a computing or control device36, which can be integral with output device60or a discrete component.

Waypoints32can be located at a point in the axial bore30below launcher22. Further, with reference toFIGS. 3A and 3B, detection devices34can be fit to any location on the fracturing system100where it is able to detect vibrations generated from actuator10striking waypoint32to determine successful introduction of an actuator10. The form and position of each waypoint32is allocated to transmit a reliable, detectable vibration from the actuator10impacting obstruction32and for providing the operator with the confirmation and aiding in the decision process. For process management, it is useful for a waypoint32to be located immediately adjacent the frac header24, as the receipt of the actuator10at waypoint32just before introduction into the fracturing fluid flow provides a reliable confirmation of successful launch downhole. Such a configuration reduces the number of potential locations between the waypoint32and wellbore12where the actuator10could subsequently become lodged or otherwise hung up after having already been detected by the detection device34. The energetic flow environment of the frac header24ensures an actuator10entering the frac header24will flow into the wellbore12below. Additionally, such a configuration allows for more accurate estimation of when the actuator10is expected to reach the intended downhole tool, as it will be known at about what time the actuator10was confirmed to have been introduced into the fracturing fluid flow. Such time accuracy is preferred so that the rate of fluid flow into the wellbore can be slowed just prior to the actuator engaging with the downhole tool, increasing the likelihood of successful engagement between the actuator and the downhole tool.

In use, with reference toFIG. 1A, a selected actuator10, to be introduced into the wellbore12, can be launched into the bore30of the fracturing system100from launcher22.

As shown inFIG. 1B, actuator10falls through bore30until it strikes waypoint32, which in the depicted embodiment is the gate40of gate valve42. The impact generates vibrations in gate valve42which are transmitted through components of the wellhead assembly20and are detected and converted to an electrical confirmation signal by detection device34. Detection device34then sends the electrical signal54to output device60which converts the electrical signal to an output61,62, which can be analyzed to determine whether the actuator10has successfully reached waypoint32, and whether the correct actuator10was launched, as described above.

If the outputs61,62indicate that no significant vibration was detected after the launching of actuator10, appropriate measures can be taken to determine the cause of the failure. If the outputs61,62confirm that there was a successful launch of actuator10, then the operator could have a high confidence to move to the next actuator10. The confirmation signal could also provide added information including whether the correct actuator10was launched into the bore30.

As shown inFIG. 1C, the actuator10, now confirmed as having been launched, can be allowed to proceed past waypoint obstruction32into the wellbore12. In embodiments where waypoint32comprises one or more protrusions52or other components which do not stop the actuator from falling, such as the embodiment shown inFIG. 2, no further action needs to be taken after the successful launch of actuator10is confirmed by the output60as the actuator10continues downhole through the frac header24and into the wellbore12.

In embodiments where waypoint32selectively blocks the bore30, such as using a gate valve42, the waypoint32can be actuated to open and allow the detected actuator10continue to fall into the wellbore12.

In another embodiment, as shown inFIG. 3A, fracturing system100is configured to launch ball-type actuators10into the wellbore12. The system comprises at least a frac header24, a staging block68, and a ball launcher22, having common bore30and fluidly connected to a wellhead12for the launching of balls30into the wellbore12for fracturing operations. Isolation gate valves42,72,82can interconnect each of the frac header24, staging block68, launcher22, and wellhead12and can selectively isolate each component from the others. In the depicted embodiment, gate valve #142can interconnect the launcher22and the staging block68, gate valve #272can interconnect the staging block68and the frac header24, and gate valve #382can interconnect the frac header24and the wellhead12. The wellhead assembly20typically includes other equipment for providing safe and controlled access to the wellbore12.

The gate70of gate valve #272functions as a waypoint32b, that ball10impacts the gate70to generate a vibration to be detected by detection device34b. Detection device34bcan be fit to gate valve #272in a manner so as to enable detection of the impact of a launched ball10with the gate70of gate valve #272. As gate valve #272is located immediately above frac header24, successful receipt of the ball10at gate valve #272predisposes a successful delivery to the wellbore, as the flow environment of the next component, the frac header24, ensures a ball10entering the frac header24will flow into the wellbore12below. In an embodiment, detection device34bcan be connected to the fracturing system by fitting the detection device34bto the stem or the body of gate valve #272so as to detect and analyze vibrations emanating therefrom. Alternatively, detection device34bcan be fixed to a location in the proximity of the gate valve #272, so long as the detection device is capable of detecting vibrations generated at the gate valve #272.

With reference toFIG. 3A, at the start of ball launch operations, immediately before the launch of a ball10, gate valve #142is in the open position to permit communication between the launcher22and staging block68, gate valve #272is closed to prevent communication between staging block68and the frac head24, and gate valve #382is open to permit flow of treatment fluids into the wellbore12. A ball10is introduced into the bore30from launcher22such that it travels downwards through the common axial bore30and lands onto gate valve #272. The vibrations from the impact are detected and converted to an electrical confirmation signal by detection device34band sent to output device60, which translates the electrical signal into an output61,62and displays said output. Output61,62can comprise a light array61, that illuminates a green light if vibrations generated by ball10striking gate valve #272are detected, and continues to illuminate a red light otherwise.

As shown inFIG. 3B, if the output61,62indicates that ball10was successfully dropped, the ball10can be introduced into the wellbore12by closing gate valve #142, pumping fluid into the staging block68to equalize pressure with the wellbore pressure, and opening gate valve #272to allow fluid communication between the staging block68and wellbore12. The fracturing system100is then reset for a subsequent ball launch by closing gate valve #272, pumping fluids out of the staging block68through fluid line76, and opening gate valve #142. If the output60indicates that ball10was not successfully dropped, action can be taken to determine and correct the cause of the failure.

In an alternative embodiment, as shown inFIGS. 3A and 3Bin dotted lines, detection device84can be connected to the body of the staging block68, or a spool or neck of the flange78connecting gate valve #272to the staging block68. In such an embodiment, during treatment operations, the staging block68is filled with fluid, such as residual fluid from previous launch operations, from gate valve #272up to at least a fluid line76. The ball launch procedure is the same as above, and detection device84can detect acoustic vibrations transmitted at least in part through the fluid to determine whether a ball10has been successfully launched. Specifically, when ball10is dropped from the launcher22and lands on gate valve #272, the acoustic vibrations generated by the impact of the ball10on gate valve #272propagate through the fluid in axial bore30above the gate valve72and the wall of the launch block22, and is detected by detection device84. As this embodiment also utilizes a liquid medium to aid vibration propagation, for the first ball launch, when the staging block68is typically free of fluid, fluid may be pumped into the staging block through fluid line76to fill the axial bore30above gate valve #272up to about the height of the detection device84.

One embodiment of the procedure for confirming the successful introduction of a downhole actuator10into the wellbore12is shown inFIG. 4. The process begins at200when it is determined that an actuator10is to be introduced into the wellbore12. At210, a signal for launch is sent to the launcher, such as a signal to an operator to manually launch an actuator10, or an electrical signal where the actuator launcher22is remotely controlled. At220, the launcher22releases the desired actuator10into the common bore30of the wellhead assembly20. At230, it is determined whether actuator10has been received at waypoint32using the detection methods described above. If no actuator10was received by waypoint32, then the process proceeds to235, wherein steps are taken to diagnose and correct the cause of the actuator injection failure. Once the problem has been corrected, the process returns once again to230. If the actuator10has been received by waypoint32, at240the process proceeds to250and opens the gate if waypoint32is a gate valve, and otherwise proceeds directly to260and confirms that an actuator10has entered wellbore20. Once the injection of actuator10is confirmed, the process returns to200and a new actuator10can be injected.

The detection device34generally can be a vibrational sensor, for example a knock sensor for automobiles such as the KS4-P knock sensor by Bosch®, an ultrasonic detection device or sensor, such as the EPOCH 600 Nondestructive Testing device from Olympus Corporation®, or another type of suitable vibration detection device. Detection devices34vary in their abilities; some are designed for direct connection to a component to measured, and others are capable of measuring vibrations generated from a source at a distance. The use of an internal combustion engine knock sensor includes advantages for severe service including: pressure insensitivity for consistent results in a changing environment, excellent ambient noise cancellation for distinguishing background noises and reducing the incidence of false positives, excellent direct vibration contact and transmission and a wide range of operational temperatures. The Bosch® knock sensor is secured to the vibrating mass. Due to the inertia of the seismic mass, the sensor moves with the wellhead establishing a voltage signal via piezoceramic sensor element. Upper and lower voltage thresholds are related to an acceleration magnitude.

Detection device34may be mounted at a suitable location of the fracturing system100by securing the device34to a mounting point which will sufficiently conduct vibrations from waypoint32using bolts, straps, or other means of physical securement. The detection device34can be fit to a location proximate waypoint32and suitable for detecting vibrations generated by actuator10reaching, the obstruction32.

As shown inFIG. 3B, detection device34can include sensor86and be directly mounted on, or incorporated into, the stem or gate of a gate valve, or a component of the fracturing system from which protrusion52extends into bore30, thus providing a more direct acoustic path for measurement of vibrations. The detection device or control system can be configured to filter out other noises so that vibrations generated by the actuator10striking or otherwise arriving at the waypoint32are distinguishable. Such filtering can be done through hardware or software.

Additionally, interfaces between components can attenuate or otherwise distort vibrations detected by the detection device34. For example, the interface between the stem and gate of a gate valve can attenuate vibrations as they travel from the gate, through the stem, to the detection device34. Likewise, an interface between protrusion52and the housing of the component that the protrusion is formed, can attenuate vibrations. As an alternative to locating the detection device34closer to the waypoint32, the vibrational conductive path can be improved, such as through insertion of a conductive rod, wire, or other vibration conductor88, installed or run through between components, such as through the gate and stem of a gate valve, in order to provide a contiguous, direct path for vibrations to travel from the waypoint32to the detection device34. Acoustic path improvement mitigates signal disruption due to the various surface interfaces, enhancing signal quality.

When detection device34is mounted on the exterior of a component of the fracturing system100, vibrations may be less distinguishable than those detected by direct connection to waypoint32. Detectors34mounted exterior to the bore30receive vibrations only after transmission through the fluids as well as the housing of the component before reaching the detection device34. Accordingly, it is preferred to mount detection device50so that there is a direct connection to waypoint32, either by mounting/embedding detection device34directly in the waypoint32or through a vibration conductor88.

In embodiments, one or more gate valves42,72,82are equipped with sensors86coupled to the gate itself. In such cases, gate valve includes a flow body, a stem, a gate and a sensing bore. A bonnet is affixed to the flow body for securing the gate operably within. At least the stem, and optionally the gate, incorporate the sensing bore for receipt of the detector34.

In an alternative embodiment, detector device34can be configured to detect the acoustic vibrations of an actuator10engaging with a downhole valve (not shown) in the wellbore. The magnitude of the receipt is necessarily greater due to the distance between the generation of the vibration and detection at the wellhead assembly. Actuation of the downhole tool can add to the energy for detection.

As will be appreciated by a person of skill in the art, the above are examples of particular embodiments of the system and method for detecting an actuator launch using a detection device. The method can be used in any system wherein actuators are introduced into wellbores, so long as there is a waypoint between the wellbore and the actuator source that an actuator can interact with, either passively or actively, and a detection device to identify said actuator interacting with said waypoint.