Patent Application
20250027407
The present disclosure is generally directed to systems for monitoring wellbore operations. More specifically, the present disclosure is directed to improving how data is transmitted from wellbore equipment to computing devices that help control the wellbore equipment.
When managing oil and gas drilling and production environments (e.g., wellbores, etc.) and performing operations in such production environments, sensor data is often collected and evaluated to make determinations on how to manage a wellbore. Such sensor data may be used to understand downhole conditions, materials that are located in a wellbore, or to control how a wellbore operation. For example, sensor data can be used to receive data from tools that are deployed in a wellbore such that operations of those tools can be controlled. Conditions associated with a wellbore operation can create significant challenges in receiving data collected by sensors for various reasons.
In order to describe the manner in which the features and advantages of this disclosure can be obtained, a more particular description is provided with reference to specific implementations thereof which are illustrated in the appended drawings. Understanding that these drawings depict only exemplary implementations of the disclosure and are not therefore to be considered to be limiting of its scope, the principles herein are described and explained with additional specificity and detail through the use of the accompanying drawings in which:
Various aspects of the disclosure are discussed in detail below. While specific implementations are discussed, it should be understood that this is done for illustration purposes only. A person skilled in the relevant art will recognize that other components and configurations may be used without parting from the spirit and scope of the disclosure.
Additional features and advantages of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or can be learned by practice of the principles disclosed herein. The features and advantages of the disclosure can be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features of the disclosure will become more fully apparent from the following description and appended claims or can be learned by the practice of the principles set forth herein.
It will be appreciated that for simplicity and clarity of illustration, where appropriate, reference numerals have been repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the methods and apparatus described herein. However, it will be understood by those of ordinary skill in the art that the methods and apparatus described herein can be practiced without these specific details. In other instances, methods, procedures, and components have not been described in detail so as not to obscure the related relevant feature being described. The drawings are not necessarily to scale and the proportions of certain parts may be exaggerated to better illustrate details and features. The description is not to be considered as limiting the scope of the present disclosure.
Described herein are systems, apparatuses, processes (also referred to as methods), and computer-readable media (collectively referred to as “systems and techniques”) for receiving data from or associated with apparatus (e.g., tools) deployed down a wellbore at speeds not previously possible. Information or data sent from a downhole tool for receipt by computers located at the surface of the Earth is often bandwidth limited for various reasons. Systems and techniques of the present disclosure allow for disposable fiber optic cables to be deployed into a wellbore that may be dedicated to sending data or sensed information uphole to a computer. This allows for additional amounts of data or sensed information to be sent to the computer when other communication mechanisms or pathways associated with a wellbore are bandwidth limited.
Conventionally, data sent from a downhole tool for receipt by computers located at the surface of the Earth either requires communications to be sent via a wire or fiber optic cable that connects wellbore equipment to these computers or be sent via a non-contact communication where acoustic (e.g., sub-sonic, sonic, or ultrasonic) waves that are transmitted through drilling mud or other fluids located in the wellbore over long distances. When a wire or fiber optic cable is used to transmit such communications, it may be protected by a tube that covers the wire or cable. In certain instances, a protected wire or cable may itself have a limited bandwidth or may be impractical to use. Furthermore, when data is sent to the surface via a protected cable, that cable is at risk of being damaged by conditions that exist in the wellbore or that are associated with strata of the wellbore. As such, protected cables or wires may not be able to provide data at data rates sufficient to improve operating efficiency of a wellbore operation.
When acoustic waves are used to transmit data via wellbore fluids, rates at which this data is transmitted are limited to no more than 20 bits per second, or more practically to about 7-10 bits per second because of the physics associated with transmitting acoustic signals over a length of the wellbore. Such low data rates can constrain wellbore operations because computers or operators at the surface that monitor and/or control a wellbore operation must wait for data to be transmitted to the surface before evaluations can be performed that are necessary for controlling a wellbore operation. Telemetry in oil and gas drilling operations is a system that allows the transmission of data collected downhole (at the drill bit) to the surface in real time or near real time. This data is crucial in making key decisions about drilling direction, adjusting drilling parameters, and understanding the geological formations being drilled through. Operations controlled by telemetry include: 1) Directional Drilling: This is the practice of controlling the direction and deviation of the wellbore to a predetermined underground target or location. The telemetry system provides real-time updates on the angle and direction of drilling, which allows operators to adjust the drilling direction as needed. 2) Measurement While Drilling (MWD): This is a type of well logging that incorporates the measurement tools into the drill string and provides real-time information to help with steering the drill. 3) Logging While Drilling (LWD): These are measurements about the geological formation made while drilling that include natural gamma ray, electrical resistivity, neutron porosity, density, and others. These measurements can help operators understand the type and value of the resources they're drilling through. 4) Drilling Optimization: Telemetry also provides real-time information about drilling parameters such as weight on bit, torque, and rotation speed, which can be used to optimize the drilling process and prevent any drilling dysfunctions. Types of measurements that are pulsed for decision-making include: 1) Directional Measurements: These include inclination (the angle between the tool's axis and a line vertical to the Earth's surface) and azimuth (the compass direction of the tool's axis). These measurements are key for directional drilling operations. 2) Drilling Parameter Measurements: Parameters like weight on bit, torque, drill string rotation speed, and downhole pressure and temperature are also transmitted. These are important for drilling optimization and for preventing common drilling problems like stuck pipe or excessive wear on the bit. 3) Formation Evaluation Measurements: This includes resistivity (which can indicate the presence of hydrocarbons), natural gamma radiation (which provides information about the type of rock being drilled), and porosity and density (which can indicate the potential for oil or gas in the formation). 4) Tool Status Measurements: Some telemetry systems also transmit data about the status of downhole tools, such as battery voltage or internal temperature. This helps operators understand the health of their downhole equipment. Another reason that limited bandwidth constrains wellbore operations relates to generating images from sensed data. For example, a piece of wellbore equipment may be an imaging device that emits acoustic waves that propagate into Earth formations or into structures built in the wellbore. Reflections from these emitted acoustic waves may be sensed by a sensor and data from that sensor may be sent to a computer at the surface that generates images from that sensed data. When the computer does not receive enough data, because of limited transmission bandwidth, the computer will not be able to generate images that clearly show features or structures of the wellbore.
Systems and techniques of the present disclosure overcome limitations of both deploying cables in protective tubes and using low data rate acoustic transmissions by using disposable fiber optic cables that may have a capability of transmitting data at higher data rates as compared to other solutions. Fiber optic cables of the present disclosure may be deployed in the wellbore during virtually any phase of wellbore operation or during virtually any type of wellbore operation. As such, cables may be deployed when a wellbore is drilled, when a casing or tubing is deployed in the wellbore, during a cementing operation, during a production phase, or during a carbon sequestration process.
Commonly, fiber optic cables include a core transmission line, cladding, a coating that covers the cladding, a strength member that covers the coating, and an outer jacket that covers the strength member. The core has a high refractive index such that light signals can easily propagate through the fiber optic cable. The cladding is typically intended to keep the light signals from escaping from the sides of the core. The coating covers and protects the cladding. The strength member supports other elements in the cable and the outer jacket provides extra stability to the cable. The fiber optic cables of the present disclosure may have areas of the cable where the core of the cable is exposed to external elements. Fiber optic cables may not include all of the layers discussed above. In certain instances, a bare core or a cable that includes a core and cladding, or a partial cover may be deployed in the wellbore. Portions of the fiber optic cable may be bare and include an exposed core section of the cable that acts as a sensing element. Fiber optic cables that include fewer than a standard number of parts or layers may be referred to as an unarmored fiber optic cable.
When unarmored fiber optic cables are used in a wellbore, they may have a limited useful lifespan because of stresses that the cable is exposed to in the wellbore. Heat, pressure, turbulent flow, stretching, and abrasion that the cable is exposed to will over time degrade the cable. Once the cable is degraded or after a period of time, the cable may be cut off and discarded in the wellbore. The cut cable may then be chopped up by a drill bit that is drilling the wellbore or may be passed through or destroyed by pumps that pump drilling fluids (e.g., drilling mud). Unarmored may refer to a cable that is mechanically or chemically unprotected such that the fiber would degrade over the course of a drilling run. A drilling run may be the time from when the drill is placed in hole and then subsequently pulled out of the hole. This time typically could be a few days to a few weeks.
Fiber optic cables deployed in a wellbore may act as a sensor without any additional sensing elements being added to or incorporated into the fiber optic cables. Alternatively or additionally, sensing elements may be added to or incorporated into a fiber optic cable. Such sensing elements may enhance the sensing capabilities of a fiber optic cable that does not include these sensing elements. An example of a sensing element that may be incorporated into a fiber optic cable is a fiber Bragg grating.
For these reasons, fiber optic cables deployed in a wellbore may include sensing areas or sensing elements. By deploying a fiber optic cable in a wellbore using techniques of the present disclosure, these sensing areas or sensing elements allow the fiber optic cables to receive energy or signals transmitted from other apparatus deployed in the wellbore. As such, a wellbore apparatus may transmit a signal that is received by the sensing areas or sensing elements of the cable. This signal may include encoded data that is received by the sensing areas or elements of the fiber optic cable. Such transmitted signals may be transmitted as acoustic (e.g., subsonic, sonic, or ultrasonic) or electromagnetic waves. This encoded data may be data that is received based on operation of an ultrasonic tomographic imaging device, for example, or reflections of transmitted ultrasonic energy may be sensed by the sensing areas or elements of the fiber optic cable. In either instance, information associated with the operation of the imaging device may be received by a computer such that the computer can be used to control wellbore equipment or to generate images from information received via the fiber optic cable.
Logging tools 126 can be integrated into the bottom-hole assembly 125 near the drill bit 114. As drill bit 114 extends into the wellbore 116 through the formations 118 and as the drill string 108 is pulled out of the wellbore 116, logging tools 126 collect measurements relating to various formation properties as well as the orientation of the tool and various other drilling conditions. The logging tool 126 can be applicable tools for collecting measurements in a drilling scenario, such as the electromagnetic imager tools described herein. Each of the logging tools 126 may include one or more tool components spaced apart from each other and communicatively coupled by one or more wires and/or other communication arrangement. The logging tools 126 may also include one or more computing devices communicatively coupled with one or more of the tool components. The one or more computing devices may be configured to control or monitor a performance of the tool, process logging data, and/or carry out one or more aspects of the methods and processes of the present disclosure.
The bottom-hole assembly 125 may also include a telemetry sub 128 to transfer measurement data to a surface receiver 132 and to receive commands from the surface. In at least some cases, the telemetry sub 128 communicates with a surface receiver 132 by wireless signal transmission (e.g., using mud pulse telemetry, EM telemetry, or acoustic telemetry). In other cases, one or more of the logging tools 126 may communicate with a surface receiver 132 by a wire, such as wired drill pipe. In some instances, the telemetry sub 128 does not communicate with the surface, but rather stores logging data for later retrieval at the surface when the logging assembly is recovered. In at least some cases, one or more of the logging tools 126 may receive electrical power from a wire that extends to the surface, including wires extending through a wired drill pipe. In other cases, power is provided from one or more batteries or via power generated downhole.
Collar 134 is a frequent component of a drill string 108 and generally resembles a very thick-walled cylindrical pipe, typically with threaded ends and a hollow core for the conveyance of drilling fluid. Multiple collars 134 can be included in the drill string 108 and are constructed and intended to be heavy to apply weight on the drill bit 114 to assist the drilling process. Because of the thickness of the collar's wall, pocket-type cutouts or other type recesses can be provided into the collar's wall without negatively impacting the integrity (strength, rigidity and the like) of the collar as a component of the drill string 108.
The illustrated wireline conveyance 144 provides power and support for the tool, as well as enabling communication between data processors 148A-N on the surface. In some examples, the wireline conveyance 144 can include electrical and/or fiber optic cabling for carrying out communications. The wireline conveyance 144 may be sufficiently strong and flexible to tether the tool body 146 through the wellbore 116, while also permitting communication through the wireline conveyance 144 to one or more of the processors 148A-N, which can include local and/or remote processors. In instances, when wireline tool 146 is a fiber optic cable, that cable may be deployed near a drilling assembly when the wellbore is drilled. The processors 148A-N can be integrated as part of an applicable computing system, such as the computing device architectures described herein.
When tool 146 is deployed in the wellbore using bobbin 155 of wireline conveyance 144, sealing mechanism 150 may be used to seal the wellbore. This means that the wellbore may be pressurized when sensors (e.g., a fiber optic cable or other sensors) receive acoustic data transmitted from a downhole apparatus. In certain instances, wireline conveyance 146 and bobbin 155 may be contained within a sealed environment even though this is not shown in
In operation, laser 210 may provide a light signal to coupler 220 that sends or directs the light signal along fiber optic cable 230. This light signal propagates through fiber optic cable 230 and then this light signal may reflect off sensing elements 240 and/or off a lower end of fiber optic cable 230 before traveling back to coupler 220. Portions of this light signal may exit out of the lower end of the fiber optic cable. The light signal transmitted to the cable may include many individual periods or cycles of light. A period of such a light signal may be in the nanometer range.
Communication signal 280 transmitted from well tool 260 via transmitting element 270 may be received by sensing areas or elements 240. As signal 280 impacts sensing areas or elements 240, the light signal traveling up and/or down fiber optic cable 230 may be modulated. Data may be transmitted using any encoding technique. Examples of possible encoding techniques include frequency shift key encoding, frequency modulation, binary on/off based on the presence or absence of signal, or another encoding technique. When communication signal 280 impacts sensing elements or areas 240, data will be encoded onto the light signal carried by fiber optic cable 230. In one example, a light signal could be modulated at a frequency of 100 thousand Hertz (KHz). This 100 KHz signal may be an ultrasonic signal that includes time shifts that encode data into the 100 KHz signal. In another example. In other instances, frequencies of 5 KHz, 10 KHZ, or 20 KHz may be used. In an instance when frequency shift key is used, several different frequencies may be shifted between. The choice of a frequency or an encoding technique used may depend on the mode of operation of laser 210.
Laser 210 may be configured to operate in or more operational modes, such as in a pulse mode or in a continuous wave (CW) mode. In the pulse mode, the laser may transmit a light signal for a period of time and that light signal may migrate along fiber optic cable 230 until that light signal is reflected off of sensing elements 240 and/or the end of fiber optic cable 230. Many cycles or periods of the light may be included in the light signal. When the light signal travels along fiber optic cable, data may be transmitted from wellbore tool 260 via transmitting element 270. Then, after the reflected light signal travels back up fiber optic cable 230, coupler 220 may direct that signal to receiver/demodulator 290 and then another light signal may be transmitted by laser 210 along fiber optic cable 230 when laser 210 operates in the pulse mode such that additional data may be encoded onto this second light signal. Such a configuration may be chosen when the fiber optic cable itself is used as a sensing element or when a single sensing element 240 is included in the fiber optic cable deployed in a wellbore. A pulsed configuration may use a data rate that corresponds to physical limitations associated with a length of time it takes for a wavelength of a light signal that to travel a round trip distance from a first end of the fiber optic cable to a distal end of the fiber optic cable and back to the first end of the fiber optic cable. This may be done to avoid aliasing effects.
When laser 210 operates in a continuous mode, laser 210 may continually provide the light signal that travels down and then back up fiber optic cable 230. Data may be continuously transmitted by wellbore tool 260 and that data may be modulated into the light signal where it travels to receiver/demodulator 290 via coupler 230. Such a configuration may be chosen when pairs of sensors 240 are included in a fiber optic cable deployed in a wellbore.
Depending on a mode of operation, an appropriate data rate may be selected and an appropriate data modulation or encoding technique may be selected. One type of encoding technique may include transmitting different frequencies of acoustic signals, where one frequency represents a digital one and another frequency represents a digital zero. Other encoding techniques could include pulse width modulation, for example. In other instances, the frequency of a transmitted acoustic signal may be varied to encode data onto a light signal using a frequency modulation technique.
In some instances, Fiber Bragg Gratings (FBGs), cable splices, Fabry-Perot cavities, or Fizeau optical cavities could be placed along a fiber optic cable when those FBGs, splices, or cavities act as sensors. Signals associated with those sensors could be interrogated optically. This could be done by using either a broadband or swept laser optical source. Reflected spectra could be detected from these sensors may be used to monitor reflected resonant wavelength shifts or optical frequency shifts that may be associated with dynamic strain on the remote FBGs, splices, or cavities. To increase sensitivity even more, pairs of sensing elements could be used to create weak interferometric signals. As such, FBG-pairs, splice pairs, or pairs of Fabry-Perot or Fizeau optical cavities may be used. In such an instance, a few meters of fiber length may separate each of a set of FBGs. For example, FBG-pairs could be located along the last distal portions of the pumped fiber during a wellbore operation such as a drilling operation. This would give the ability to demodulate acoustic signals in the ultrasound range, thus, providing telemetry rates approaching upwards of 1 mega-bits per second (Mb/sec) due to the short cavity lengths between the FBG-pairs. Alternatively or additionally, other pairs of sensing elements (splice pairs, or pairs of Fabry-Perot or Fizeau optical cavities) may be used. In such instances, receiver/demodulator 290 may act as an interferometer that demodulates data from signals reflected by a set or pair of sensing elements. Data rates associated with techniques of the present disclosure may allow computer 250 to control a wellbore operation more efficiently than is possible today. This could allow the computer to more effectively control the direction of a drill bit, pause a wellbore operation, or initiate a corrective action.
Any data included in signal 280 may be modulated into the light signal traveling up and/or down fiber optic cable 230 to coupler 220. Once the reflected signals are received at coupler 220, they may be passed to receiver/demodulator 290 that may separate data from a signal provided to receiver/demodulator 290. This data may then be received by computer 250 such that computer 250 may evaluate this data. Alternatively or additionally, as mentioned above, information associated with the operation of the imaging device may be received by computer 290 such that the computer can be used to control wellbore equipment or to generate images from information received via the fiber optic cable. Techniques for evaluating received signals may be selected from the group of Rayleigh, Raman, or Brillouin scatter or backscatter effects. For example, Raleigh scattering techniques may be employed to detect data and possibly Raman scattering techniques may be used to identify temperature.
Fiber optic cable 230 may be an unarmored cable, meaning that cable 230 may not include all structures or layers commonly included in a fiber optic cable and may not include a rigid casing. As mentioned above, by using an unarmored cable, fiber optic cables that are used may be cut off and allowed to pass by a drill bit or through a pump that pumps a fluid without worrying about the fiber optic cable damaging the drill bit or the pump. As such, an unarmored fiber optic cable may only include a core along which signals propagate and a coating that coats an external surface of the core. Signals 280 may be acoustic (subsonic, sonic, or ultrasonic) signals or electromagnetic signals that can be received by sensing areas or elements 240 of
When fiber optic cable 230 is deployed in a wellbore and once sensing areas or elements 240 of that cable 230 are within a threshold distance separating transmitting element 270 of wellbore tool 260, data may be transmitted from transmitting element 270 to sensing areas or elements 240. The sensing elements may be located near the wellbore tool based on these sensors being placed near or at the distal (far) end of the fiber optic cable. When sensing areas or elements 240 are within the threshold distance from transmitting element 270, fiber optic cable may be able to receive transmitted data in a manner that maintains a strength of signal received by sensing areas or elements 240. When sensing areas or elements 240 are located at distances greater than the threshold distance, fiber optic cable may not be able to effectively receive signals transmitted by transmitting element 270 because frequencies of these signals may be absorbed by drilling muds or other substances in the wellbore.
In certain instances, a pattern associated with a particular type of reflection may be received when a sensing area or element of a fiber optic cable approaches transmitting element 270. The double pulse, discussed above, may be created at the source and may be induced directly from the source such as the laser, by optics attached to the source, or by optics subsequent to the source either before the fiber or integrated with the fiber. The double pulse may be actively controlled or passively inherent to the optics. Note that an identifying sequence need not be a double pulse, yet may include some unique pattern that can be identified (e.g., a pattern of shifting/changing frequency or a pattern of digital ones and zeros). Dual optical pulses may be used to allow use of remote FBGs between lengths of fiber to time separate or time multiplex multiple FBGs channels near the distal end of the fiber optic cable. Such a dual pulse approach or dual sensor approaches allow for more sensitive coherent interrogation of received signals using hetero/homodyning techniques with compensating interferometers.
One reason why the sensing areas or elements must be within the threshold distance from the transmitter is that a strength of a transmitted signal varies with distance according to the inverse square law. The farther away a transmitter is from a receiver, energy transmitted by the transmitter that is received by the receiver reduces in a manner that is inversely proportional to the square of the distance that separates the transmitter and the receiver. This effect may be exacerbated by densities of fluids through which the transmitted signal must travel and may be increased by noise associated with particular types of drilling operations. As such, effects of the inverse square law, fluid density, and external noise may be referred to dampening effects or effects that reduce a signal to noise ratio. Dampening effects associated with wellbore conditions and separation distances may result in higher bit error rates. Such bit error rates may increase further with transmission data rates. Such dampening effects may be mitigated by placing sensing areas or elements 240 within a threshold distance from transmitting element 270. Multiple frequency redundancy and the use of algorithmic error checking such as but not limited to check sum error detection may be used to mitigate higher error rates.
While
When sound waves impinge upon the fiber optic cable, strain from these sound waves may result in the length and index of refraction of the fiber optic cable changing. Such changes may be measured using various established optical intensity, frequency, wavelength, or optical phase changes (e.g., interferometric methods). In more subtle contexts a modulation may include intermediate values for higher bit transmission. In certain instances, an acoustic source (subsonic, sonic, or ultrasonic) may be used to encode data onto the fiber optic cable by transmitting signals that induce strain into the fiber optic cable. Such changes may be monitored to identify data that has been encoded onto a light signal carried by the fiber optic cable. In the simplest of contexts, the amplitude could be binary as a series of pulses (i.e., on and off). In more subtle contexts it may include intermediate values for higher bit transmission.
A signal may be applied to the fiber optic cable at block 320. This signal may be provided by a laser, such as laser 210 of
When the light signal is provided to a fiber optic cable, characteristics of the cable may change based on stress that the cable is experiencing, based on whether a sensing area or element of the cable is receiving communication signal 280 of
While the actions performed in
A set of wellbore equipment may be configured to transmit specific signals or sets of signals based on other signals received from a computer used to control wellbore operations via a secondary communication pathway. Commands may be sent from a computer to the wellbore equipment via a set of communication lines deployed along the wellbore (e.g., via a permanently deployed wire or cable) or may be initiated by sending wireless (e.g., acoustic) transmissions that travel through wellbore fluids. In the context of oil and gas drilling operations, using both fiber optic cable (for uplink) and mud pulse telemetry (for downlink) can provide a complete communication system for transmitting data and instructions to and from the bottom-hole assembly (BHA). Uplink (Fiber Optic Cable): The uplink is primarily used to transmit data from downhole sensors in the BHA to the surface. This real-time data can include measurements of downhole pressure, temperature, formation resistivity, acoustic readings, strain, and more. Fiber optic cables can transmit large amounts of data at high speeds, which makes them well-suited to the high data rates required for these measurements. The data transmitted via the uplink may be used to make informed decisions about drilling operations, such as adjusting drilling parameters and direction. Downlink (Mud Pulse Telemetry): The downlink is used to send commands from the surface to the BHA. These commands can include instructions to adjust the drilling direction, change drilling parameters, or activate/deactivate certain tools in the BHA. Mud pulse telemetry can provide a reliable means of downlink communication in environments where electromagnetic communication may not be reliable due to the depth or geology of the well. By using both fiber optic cable for uplink and mud pulse telemetry for downlink, drilling operations can effectively control and monitor the BHA in real time. The high data rate of fiber optics allows for a detailed understanding of the downhole environment and drilling parameters, while the reliability of mud pulse telemetry ensures that commands can be accurately transmitted to the downhole tools, even in challenging drilling environments. Mud pulsed telemetry is the most common method for establishing a downlink. Alternatively, under some circumstances a downlink may be created through the fiber itself if the fiber property is altered by the laser pulse. The fiber may be doped with a material that aligns or anti-aligns with the pulse and is also sensitive to an electric field. Yet a third way that the downlink can be completed may be through the use of flowed signals. For instance, fine balls of known magnetic properties may be injected into the flow stream. Although slower than a pulse in latency, the bandwidth may be much higher than a mud pulse. This may include sending the command wirelessly at a data at a rate of less than 20 bits per second. As such, an acoustic signal of a first frequency may be used to transmit a command to the wellbore equipment such that data may be received from the wellbore equipment via transmissions of a second frequency at a data rate that is higher than 20 bits per second. As such, methods of the disclosed method are superior to conventional mud pule transmissions that have a theoretical maximum data rate of 20 bits per second. The command transmitted to the wellbore equipment may instruct the wellbore equipment to transmit a set of location detection signals. Such location detection signals may include sending data at different data rates at different times. This may include sending data at a data rate of 100 thousand Hertz (100 KHz) for a first time period, then at 1 million Hertz (1 MHz) for a second time period, and then at 10 MHz for a third time period as part of a location detection operation.
At block 440, received signals may be monitored such that a determination can be made as to whether a data reception metric has been met. Determination block 450 may then identify whether the data reception metric corresponds to a reception requirement. Examples of reception metrics include yet are not limited to the presence or absence of a signal with a frequency in the acoustic range, one or more bit error rates, or received signal amplitudes. Rules may identify or be associated with bit error rates that meet or exceed a threshold level or a minimum signal amplitude of received signals. A unique pattern may be used to modulate the fiber in such a way that the fiber is “seen” to pass the telemetry module. The modulation will be observed on light that is traveling down the fiber, and reflected against the bottom of the fiber to reach the surface and the unmodulated reflected signal upon it's return will also be modulated. This creates a time delay based on the distance between the telemetry point and the end of the fiber. Such a double pulse may be used to measure the distance past the telemetry unit that the fiber has traversed.
Types of metrics used may vary depending on characteristics of the fiber optic cable deployed in a wellbore, may vary depending on a type of sensor attached to the fiber optic cable, or both. As mentioned above, one type of sensor that may be built into or attached to a fiber optic cable is a Fiber Bragg Grating (FBG). A FBG operates by reflecting particular wavelengths of light and allowing other frequencies to pass, FBG sensors may be located in different areas of a fiber optic cable. Each respective sensor may reflect a particular wavelength based on a distances between the reflection points of the respective sensors. When a FBG is stressed, distances between the reflection points in the sensor change and this change in distance causes the wavelength of the reflected signal to change. This means that a particular FBG may be sensitive to particular frequencies. Since distances between reflection points of a FBG also change with temperature, a wavelength reflected by a particular FBG will also change with temperature.
While FBG sensors may be used when methods of the present disclosure are performed, a portion of a fiber optic cable may itself be act as a sensor or another type of sensor may be connected to the fiber optic cable. For example, a sensor sensitive to magnetic fields may be used to convert changes in a magnetic field into a strain that affects the fiber optic cable. This may include converting electromagnetic energy from a radio frequency (RF) signal to movement. This may be similar to the way radial or linear inductive actuator works—where a magnetic field applied to a coil induces a voltage into the coil that results in movement of the coil.
Different portions of a fiber optic cable or different sensors attached to or integrated into a fiber optic cable may be used to receive data from different transmitters that may be located at different locations along a set of wellbore equipment. Each different sensor may be sensitive to a different frequency and because of this, signals associated with each of these different sensors may be distinguished from each other and data encoded into each respective signal of these signals may be decoded. Particular sensors may be sensitive to specific frequencies or wavelengths. Wavelengths and frequency of a particular signal are inversely proportional to each other. This means that vibrations from acoustic signals of a particular frequency can affect a FBG sensor or that RF signals could affect a sensor sensitive to electromagnetic fields of a particular sensor. Changes in phase or timing of these signals may result in data being modulated onto a light signal when a sensing element is exposed to an acoustic signal or an RF signal. Alternatively or additionally, information from specific sensors may be identified based on timing when data from those specific sensors is received.
When the data reception metric does not correspond to the reception requirement, program flow may move back to block 440 where the received signals are once again monitored to identify the reception metric. Blocks 440 and 450 may be performed iteratively as a sensing element or area of the fiber optic cable moves closer to the transmitting element that was configured at block 420. An error rate of data received from the transmitting element may reduce until at least a particular bit error rate is observed. Such a bit error rate threshold may correspond to one error for every ten to the ninth (1 in 109) bits. A bit error rate lower than this may indicate that sensing elements of the fiber optic cable are within a threshold distance and any bit error rate lower than this (e.g., 1 in 1010) bits would correspond to this threshold distance. In certain instances, bit error rates at different transmission frequencies (e.g., different acoustic or RF frequencies) may be measured and each of a set of bit error rates may be required by a reception requirement of determination block 450. When the data reception metric does correspond to the reception requirement, program flow may move to block 460 where an operational mode may be initiated at a set of wellbore equipment. The operational mode initiated at block 460 may result in a transmitting element transitioning from a location detection mode to a data transfer or sensing mode. Bit error rates (BER) are a critical concern in fiber optic telemetry, and there are a variety of techniques used to mitigate their effects, including error detection and correction codes, redundancy, and signal quality enhancement: 1)Forward Error Correction (FEC): FEC is a technique used to detect and correct a limited number of errors in the transmitted data without needing to retransmit the data. FEC adds redundancy to the data by encoding it using an algorithm that generates error correction codes. When the data is received, the algorithm is used to check for errors and correct them. Reed-Solomon and Turbo codes are examples of FEC codes often used in fiber optic communications. 2) Cyclic Redundancy Check (CRC): CRC is a popular method for detecting errors in transmitted data. It involves calculating a checksum for the data at the transmitter and sending this checksum along with the data. At the receiver, the checksum is recalculated, and if it doesn't match the received checksum, an error is detected 3) Automatic Repeat Request (ARQ): While not as commonly used in fiber optic communications due to the high data rates and low latency requirements, ARQ is a technique where the receiver sends an acknowledgment to the transmitter for each block of data it receives. If the acknowledgment is not received within a certain time, the transmitter re-sends the data. 4) Signal Quality Enhancement: Techniques such as optical amplification (e.g., erbium-doped fiber amplifiers), dispersion compensation (to correct for the spreading of signal pulses in the fiber), and wavelength division multiplexing (to increase the data capacity of the fiber) can help to maintain a high-quality signal, which reduces the likelihood of bit errors. 5) Redundancy: This involves sending multiple copies of the data or sending the data over multiple paths (if available) to ensure that it is received correctly. This can be effective but is usually more costly due to the increased data volume. 6) Modulation Techniques: Advanced modulation techniques, such as Quadrature Phase Shift Keying (QPSK) and Quadrature Amplitude Modulation (QAM), can also be used to increase the robustness of the communication against errors.
When the fiber optic cable is deployed in the wellbore and before the sensing elements of the fiber optic cable are located within the threshold distance from the transmitting element, the transmitting element may transmit numerous different bit patterns. Some of the bit patterns used may be classified as worst-case bit patterns based on these bit patterns having a tendency to have a higher error rate than other bit patterns. As mentioned above, the transmitting elements may be configured to transmit data at different frequencies. As soon as the sensing elements of the fiber optic cable are within the threshold distance from the transmitting element, a second command may be sent to the wellbore equipment that results in the transmitting element transmitting data associated with the wellbore operation or with the wellbore equipment. This means that the operation mode initiated at block 420 may include initiating a data communication mode or sensing mode of the transmitting element. This second command could also set the frequency of the signal transmitted by the transmitting element. A selected frequency may be a frequency that has a minimum bit error rate, a maximum energy that can provides at least a minimum data transfer rate. As such, the actions performed in
While not illustrated in
The operational mode initiated at block 460 may allow a computer or an operator that controls the wellbore operation to adjust the wellbore operation. For example, based on received data, a drill bit may be steered in a different direction or a production flow may be changed. Commands sent to the wellbore equipment may be sent via a different communication pathway as mentioned above. This may include sending a command via a protected cable or via a type of non-contact data transmission.
Telemetry in oil and gas drilling operations is a system that allows the transmission of data collected downhole (at the drill bit) to the surface in real time or near real time. This data is crucial in making key decisions about drilling direction, adjusting drilling parameters, and understanding the geological formations being drilled through. Operations controlled by telemetry include: 1) Directional Drilling: This is the practice of controlling the direction and deviation of the wellbore to a predetermined underground target or location. The telemetry system provides real-time updates on the angle and direction of drilling, which allows operators to adjust the drilling direction as needed. 2) Measurement While Drilling (MWD): This is a type of well logging that incorporates the measurement tools into the drill string and provides real-time information to help with steering the drill. 3) Logging While Drilling (LWD): These are measurements about the geological formation made while drilling that include natural gamma ray, electrical resistivity, neutron porosity, density, and others. These measurements can help operators understand the type and value of the resources they're drilling through. 4) Drilling Optimization: Telemetry also provides real-time information about drilling parameters such as weight on bit, torque, and rotation speed, which can be used to optimize the drilling process and prevent any drilling dysfunctions. Types of measurements that are pulsed for decision-making include: 1) Directional Measurements: These include inclination (the angle between the tool's axis and a line vertical to the Earth's surface) and azimuth (the compass direction of the tool's axis). These measurements are key for directional drilling operations. 2) Drilling Parameter Measurements: Parameters like weight on bit, torque, drill string rotation speed, and downhole pressure and temperature are also transmitted. These are important for drilling optimization and for preventing common drilling problems like stuck pipe or excessive wear on the bit. 3) Formation Evaluation Measurements: This includes resistivity (which can indicate the presence of hydrocarbons), natural gamma radiation (which provides information about the type of rock being drilled), and porosity and density (which can indicate the potential for oil or gas in the formation). 4) Tool Status Measurements: Some telemetry systems also transmit data about the status of downhole tools, such as battery voltage or internal temperature. This helps operators understand the health of their downhole equipment.
Determination block 470 may identify whether the fiber optic cable should be cut. A determination may be made to cut the cable once a task has been completed, after a period of time (e.g., an expected degradation time), or when data is no longer being effectively received by a computer. Determinations regarding knowing when data is no longer being effectively received may be based on a current bit error rate or an amplitude of received signal reducing below a threshold level. In certain instances, the tuning processes discussed above may be repeated in order to maintain some minimal performance for as long as possible. In certain instances, an operational mode may be updated or changed based on bit error rates or received signal amplitude, this may include slowing down a drill bit or flow, for example.
When determination block 470 identifies that the fiber optic cable should not be cut, program flow may move to block 460 where the operational mode is continued or updated. Decisions regarding whether to cut the cable or not may be made automatically by a computer or may be made by an operator. This may include sending messages to the operator or computer that indicates a cable cut condition has been met. When determination block 470 identifies that the fiber optic cable should be cut, the cutting of the cable may be initiated at block 480 either automatically or based on input from an operator. After the cable is cut, another cable may be deployed and the process may be repeated again at any point in time.
When the FBG is influenced by acoustic (e.g., subsonic, sonic, or ultrasonic) signals or other signals of a particular frequency, curve 530 may move back and forth near the wavelength XB that the FBG reflects. This back-and-forth movement is a form of frequency modulation of the light frequency at wavelength XB. Data encoded onto this reflected signal may be decoded after it travels back up the fiber optic cable.
As mentioned above, depending on various factors that may include a mode of operation or bit error rates, data rates used to transmit data may be varied. In an instance when a pulsed mode of operation is used data rates may be selected to avoid aliasing effects one must sample a signal at a frequency that conforms to the Nyquist sampling rate. The Nyquist sampling rate, first described by Harry Nyquist, refers to a minimal sample rate that is needed to sample a Sine wave signal by a digital sampled system in order for the digital sampled system to represent or recreate that Sine wave signal. Simply put, a Sine wave signal must be sampled using a frequency that is at least two times the frequency of the Sine wave signal. Data rates used during a pulsed mode of operation may be limited as a light signal transmitted down a fiber optic cable may be allowed to travel from a first end of the fiber optic cable to a distal end of the fiber optic cable and back before another pulse of light signals is transmitted. Data rates used in the pulsed mode may have to be reduced as cable length is increased. Since the light requires about 5 nanoseconds (ns) time delay to travel one meter, it would take 100 microseconds (μs) for the light signal to travel down and back up a fiber optic cable that has a length of 10 thousand meters (km). It would take 10 μs for the light signal to travel down and back up a fiber optic cable that has a length of 1 thousand meters. This means that a data rate that could effectively be used for the 10 km cable would be ten times less than an effective data rate used when the cable had a 1 km length in a pulsed mode of operation. As mentioned above, the pulsed mode of operation may be used when the fiber optic cable does not include sensors like Fiber Bragg Gratings (FBGs). One reason for this is that such fiber optic cables have very low sensitivity (low signal amplitudes) due to limited backscatter and low signal to noise ratio (SNR) as compared to fiber optic cables that have sensors incorporated into them. Sensitivity differences of fiber optic cables that do not use sensors as compared to those that do use sensors may have backscatter strengths that are much as 80 decibels or more below a transmitted signal level. Furthermore, techniques used to demodulate data from received signals when the pulse mode is used may be different than techniques used to demodulate data from received signals when a continuous wave (CW) mode is used. When the pulsed mode is used, the coherent Rayleigh backscatter technique may be employed to convey signals back to instruments at the surface.
The CW mode of operation discussed above may be used to transmit data at rates that exceed data rates associated with the pulsed mode of operation for the reasons discussed above. This CW mode may transmit data continuously at higher data rates because of greater sensitivity and higher SNR inherent in fiber optic cables that have incorporated sensors. The CW mode of operation may be used when one or more sensors are used. When one sensor is used (e.g., a single FBG, Fabry-Perot cavity, or Fizeau optical cavity) is used, changes in phase caused by an acoustic signal may be used to demodulate data associated with that acoustic signal using a technique that may be referred to as remote interferometric sensing. In instances when multiple sensors are used, for example when a pair of FBGs, splices, Fabry-Perot cavities, or Fizeau optical cavities are used a technique that interrogates interference from signals reflected off of different sensors may be used by surface instruments to demodulate data from a signal. Sensing zones associated with the use of pairs of sensors, like the zones discussed in respect to
The sensing zones (Z1, Z2, and or Z3) may span any desired distance, for example, 1 meter. This would mean that a pair of sensors 620 could be separated by 1 meter and an area of the fiber optic cable between sensors 620 could act as sensing zone Z1 that has a length of 1 meter. As such, sensors 620 could act as dual sensors such that coherent interrogation of received signals using hetero/homodyning techniques with compensating interferometers may be used to detect encoded data. Here again, techniques for evaluating received signals may be selected from the group of Rayleigh, Raman, or Brillouin scatter or backscatter effects. As mentioned above, Raleigh scattering techniques may be employed to detect data and possibly Raman scattering techniques may be used to identify temperature. In such instances, one or more sensors may be used to receive data based on Raleigh effects and another sensor may be used to identify temperature based on Raman effects.
The computing device architecture 700 can include a cache of high-speed memory connected directly with, in close proximity to, or integrated as part of the processor 710. The computing device architecture 700 can copy data from the memory 715 and/or the storage device 730 to the cache 712 for quick access by the processor 710. In this way, the cache can provide a performance boost that avoids processor 710 delays while waiting for data. These and other modules can control or be configured to control the processor 710 to perform various actions. Other computing device memory 715 may be available for use as well. The memory 715 can include multiple different types of memory with different performance characteristics. The processor 710 can include any general purpose processor and a hardware or software service, such as service 1 732, service 2 734, and service 3 736 stored in storage device 730, configured to control the processor 710 as well as a special-purpose processor where software instructions are incorporated into the processor design. The processor 710 may be a self-contained system, containing multiple cores or processors, a bus, memory controller, cache, etc. A multi-core processor may be symmetric or asymmetric.
To enable user interaction with the computing device architecture 700, an input device 745 can represent any number of input mechanisms, such as a microphone for speech, a touch-sensitive screen for gesture or graphical input, keyboard, mouse, motion input, speech and so forth. An output device 735 can also be one or more of a number of output mechanisms known to those of skill in the art, such as a display, projector, television, speaker device, etc. In some instances, multimodal computing devices can enable a user to provide multiple types of input to communicate with the computing device architecture 700. The communications interface 740 can generally govern and manage the user input and computing device output. There is no restriction on operating on any particular hardware arrangement and therefore the basic features here may easily be substituted for improved hardware or firmware arrangements as they are developed.
Storage device 730 is a non-volatile memory and can be a hard disk or other types of computer readable media which can store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, solid state memory devices, digital versatile disks, cartridges, random access memories (RAMs) 725, read only memory (ROM) 720, and hybrids thereof. The storage device 730 can include services 732, 734, 736 for controlling the processor 710. Other hardware or software modules are contemplated. The storage device 730 can be connected to the computing device connection 705. In one aspect, a hardware module that performs a particular function can include the software component stored in a computer-readable medium in connection with the necessary hardware components, such as the processor 710, connection 705, output device 735, and so forth, to carry out the function.
For clarity of explanation, in some instances the present technology may be presented as including individual functional blocks including functional blocks comprising devices, device components, steps or routines in a method implemented in software, or combinations of hardware and software.
In some instances, the computer-readable storage devices, mediums, and memories can include a cable or wireless signal containing a bit stream and the like. However, when mentioned, non-transitory computer-readable storage media expressly exclude media such as energy, signals, electromagnetic waves, and signals per se.
Methods according to the above-described examples can be implemented using computer-executable instructions that are stored or otherwise available from computer readable media. Such instructions can include, for example, instructions and data which cause or otherwise configure a general purpose computer, special purpose computer, or a processing device to perform a certain function or group of functions. Portions of computer resources used can be accessible over a network. The computer executable instructions may be, for example, binaries, intermediate format instructions such as assembly language, firmware, source code, etc. Examples of computer-readable media that may be used to store instructions, information used, and/or information created during methods according to described examples include magnetic or optical disks, flash memory, USB devices provided with non-volatile memory, networked storage devices, and so on.
Devices implementing methods according to these disclosures can include hardware, firmware and/or software, and can take any of a variety of form factors. Typical examples of such form factors include laptops, smart phones, small form factor personal computers, personal digital assistants, rackmount devices, standalone devices, and so on. Functionality described herein also can be embodied in peripherals or add-in cards. Such functionality can also be implemented on a circuit board among different chips or different processes executing in a single device, by way of further example.
The instructions, media for conveying such instructions, computing resources for executing them, and other structures for supporting such computing resources are example means for providing the functions described in the disclosure.
In the foregoing description, aspects of the application are described with reference to specific examples and aspects thereof, but those skilled in the art will recognize that the application is not limited thereto. Thus, while illustrative examples and aspects of the application have been described in detail herein, it is to be understood that the disclosed concepts may be otherwise variously embodied and employed, and that the appended claims are intended to be construed to include such variations, except as limited by the prior art. Various features and aspects of the above-described subject matter may be used individually or jointly. Further, examples and aspects of the systems and techniques described herein can be utilized in any number of environments and applications beyond those described herein without departing from the broader spirit and scope of the specification. The specification and drawings are, accordingly, to be regarded as illustrative rather than restrictive. For the purposes of illustration, methods were described in a particular order. It should be appreciated that in alternate examples, the methods may be performed in a different order than that described.
Where components are described as being “configured to” perform certain operations, such configuration can be accomplished, for example, by designing electronic circuits or other hardware to perform the operation, by programming programmable electronic circuits (e.g., microprocessors, or other suitable electronic circuits) to perform the operation, or any combination thereof.
The various illustrative logical blocks, modules, circuits, and algorithm steps described in connection with the examples disclosed herein may be implemented as electronic hardware, computer software, firmware, or combinations thereof. To clearly illustrate this interchangeability of hardware and software, various illustrative components, blocks, modules, circuits, and steps have been described above generally in terms of their functionality. Whether such functionality is implemented as hardware or software depends upon the particular application and design constraints imposed on the overall system. Skilled artisans may implement the described functionality in varying ways for each particular application, but such implementation decisions should not be interpreted as causing a departure from the scope of the present application.
The techniques described herein may also be implemented in electronic hardware, computer software, firmware, or any combination thereof. Such techniques may be implemented in any of a variety of devices such as general purposes computers, wireless communication device handsets, or integrated circuit devices having multiple uses including application in wireless communication device handsets and other devices. Any features described as modules or components may be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques may be realized at least in part by a computer-readable data storage medium comprising program code including instructions that, when executed, performs one or more of the method, algorithms, and/or operations described above. The computer-readable data storage medium may form part of a computer program product, which may include packaging materials.
The computer-readable medium may include memory or data storage media, such as random access memory (RAM) such as synchronous dynamic random access memory (SDRAM), read-only memory (ROM), non-volatile random access memory (NVRAM), electrically erasable programmable read-only memory (EEPROM), FLASH memory, magnetic or optical data storage media, and the like. The techniques additionally, or alternatively, may be realized at least in part by a computer-readable communication medium that carries or communicates program code in the form of instructions or data structures and that can be accessed, read, and/or executed by a computer, such as propagated signals or waves.
Methods and apparatus of the disclosure may be practiced in network computing environments with many types of computer system configurations, including personal computers, hand-held devices, multi-processor systems, microprocessor-based or programmable consumer electronics, network PCs, minicomputers, mainframe computers, and the like. Such methods may also be practiced in distributed computing environments where tasks are performed by local and remote processing devices that are linked (either by hardwired links, wireless links, or by a combination thereof) through a communications network. In a distributed computing environment, program modules may be located in both local and remote memory storage devices.
In the above description, terms such as “upper,” “upward,” “lower,” “downward,” “above,” “below,” “downhole,” “uphole,” “longitudinal,” “lateral,” and the like, as used herein, shall mean in relation to the bottom or furthest extent of the surrounding wellbore even though the wellbore or portions of it may be deviated or horizontal. Correspondingly, the transverse, axial, lateral, longitudinal, radial, etc., orientations shall mean orientations relative to the orientation of the wellbore or tool.
The term “coupled” is defined as connected, whether directly or indirectly through intervening components, and is not necessarily limited to physical connections. The connection can be such that the objects are permanently connected or releasably connected. The term “outside” refers to a region that is beyond the outermost confines of a physical object. The term “inside” indicates that at least a portion of a region is partially contained within a boundary formed by the object. The term “substantially” is defined to be essentially conforming to the particular dimension, shape or another word that substantially modifies, such that the component need not be exact. For example, substantially cylindrical means that the object resembles a cylinder, but can have one or more deviations from a true cylinder.
The term “radially” means substantially in a direction along a radius of the object, or having a directional component in a direction along a radius of the object, even if the object is not exactly circular or cylindrical. The term “axially” means substantially along a direction of the axis of the object. If not specified, the term axially is such that it refers to the longer axis of the object.
Although a variety of information was used to explain aspects within the scope of the appended claims, no limitation of the claims should be implied based on particular features or arrangements, as one of ordinary skill would be able to derive a wide variety of implementations. Further and although some subject matter may have been described in language specific to structural features and/or method steps, it is to be understood that the subject matter defined in the appended claims is not necessarily limited to these described features or acts. Such functionality can be distributed differently or performed in components other than those identified herein. The described features and steps are disclosed as possible components of systems and methods within the scope of the appended claims.
Claim language or other language in the disclosure reciting “at least one of” a set and/or “one or more” of a set indicates that one member of the set or multiple members of the set (in any combination) satisfy the claim. For example, claim language reciting “at least one of A and B” or “at least one of A or B” means A, B, or A and B. In another example, claim language reciting “at least one of A, B, and C” or “at least one of A, B, or C” means A, B, C, or A and B, or A and C, or B and C, or A and B and C. The language “at least one of” a set and/or “one or more” of a set does not limit the set to the items listed in the set. For example, claim language reciting “at least one of A and B” or “at least one of A or B” can mean A, B, or A and B, and can additionally include items not listed in the set of A and B.
Illustrative aspects of the disclosure include:
Aspect 1. A method comprising: deploying a fiber optic cable into a wellbore, wherein a distal end of the fiber optic cable moves down the wellbore with a fluid as the fiber optic cable is deployed; and providing a light signal to a first end of the fiber optic cable; receiving reflections of the light signal by a sensor coupled to the first end of the fiber optic cable when the distal end of the fiber optic cable is located in the wellbore, wherein the reflections of the signal are shifted in time when a portion of the fiber optic cable is exposed to an acoustic signal transmitted from an acoustic transmitter of a tool deployed at the wellbore and a first set of data included in the acoustic signal is modulated into the reflections based on the reflections of the signal being shifted in time. Aspect 1 may also include demodulating the first set of data from the reflections of the light signal.
Aspect 2: The method of Aspect 1, further comprising identifying that the fiber optic cable has been deployed to within a threshold distance of the acoustic transmitter based on a change associated with the received reflections of the light signal.
Aspect 3: The method of Aspect 2, wherein the change in the reflected signal corresponds to a known pattern.
Aspect 4. The method of any of Aspects 1 through 3, further comprising initiating an operational mode of a laser that provides the light signal that corresponds to one of a pulsed mode or a continuous wave mode.
Aspect 5: The method of any of Aspects 1 through 4, wherein the first set of data is demodulated from the light signal based on operation of an interferometer.
Aspect 6. The any of Aspect 1 through 5, wherein the first set of data included in the acoustic signal is modulated into the reflections at a zone of the fiber optic cable located between two sensing elements that are separated by a known distance.
Aspect 7. The method of any of Aspects 1 through 6, further comprising demodulating a second set of data from the reflections of the light signal.
Aspect 8. The method of any of Aspects 1 through 7, wherein the first set of data is associated with a first set of sensing elements and a/the second set of data is associated with a second set of sensing elements.
Aspect 9: A system comprising: a fiber optic cable that is deployed into a wellbore, wherein a distal end of the fiber optic cable moves down the wellbore with a fluid as the fiber optic cable is deployed; a laser that provides a light signal to a first end of the fiber optic cable; and a receiver that receives reflections of the light signal by a sensor coupled to the first end of the fiber optic cable when the distal end of the fiber optic cable is located in the wellbore, wherein: the reflections of the signal are shifted in time when a portion of the fiber optic cable is exposed to an acoustic signal transmitted from an acoustic transmitter of a tool deployed at the wellbore and a first set of data included in the acoustic signal is modulated into the reflections based on the reflections of the signal being shifted in time; and wherein the receiver demodulates the first set of data from the reflections of the light signal.
Aspect 10: The system of Aspect 9, further comprising a memory; and a processor that executes instructions out of the memory to identify that the fiber optic cable has been deployed to within a threshold distance of the acoustic transmitter based on a change associated with the received reflections of the light signal.
Aspect 11: The system of Aspect 9 or 10, wherein a/the change in the reflected signal corresponds to a known pattern that was modulated into the light signal by the acoustic signal transmitted from the acoustic transmitter.
Aspect 12: The system of any of Aspects 9 through 11, wherein the processor executes the instructions to initiate an operational mode of the laser that provides the light signal that corresponds to one of a pulsed mode or a continuous wave mode.
Aspect 13: The system of any of Aspects 9 through 12, wherein the first set of data is demodulated from the light signal based on operation of an interferometer at the receiver.
Aspect 14. The system of any of Aspects 9 through 13, wherein the first set of data included in the acoustic signal is modulated into the reflections at a zone of the fiber optic cable located between two sensing elements that are separated by a known distance.
Aspect 15: The system of any of Aspects 9 through 14, wherein a second set of data is demodulated from the reflections of the light signal.
Aspect 16. The system of any of Aspects 9 through 15, wherein the first set of data is associated with a first set of sensing elements and the second set of data is associated with a second set of sensing elements.
Aspect 17. A non-transitory computer-related storage medium having embodied thereon instructions executable by one or more processors to: control deployment of a fiber optic cable into a wellbore, wherein a distal end of the fiber optic cable moves down the wellbore with a fluid as the fiber optic cable is deployed. The one or more processors may execute the instructions to initiate a light signal source to provide a light signal to a first end of the fiber optic cable; and analyze a first set of data modulated into reflections of the light signal that were received by a sensor coupled to the first end of the fiber optic cable when the distal end of the fiber optic cable is located in the wellbore, wherein the reflections of the signal are shifted in time when a portion of the fiber optic cable is exposed to an acoustic signal transmitted from an acoustic transmitter of a tool deployed at the wellbore and a first set of data included in the acoustic signal is modulated into the reflections based on the reflections of the signal being shifted in time.
Aspect 18: The non-transitory computer-related storage medium of Aspect 17, wherein the one or more processors execute the instructions to identify that the fiber optic cable has been deployed to within a threshold distance of the acoustic transmitter based on a change associated with the received reflections of the light signal.
Aspect 19: The non-transitory computer-related storage medium of Aspect 17 or 18, wherein a/the change in the reflected signal corresponds to a known pattern.
Aspect 20: The non-transitory computer-related storage medium of any of Aspects 17 through 19, wherein the one or more processors execute the instructions to initiate an operational mode of a laser that provides the light signal that corresponds to one of a pulsed mode or a continuous wave mode.
