Subterranean well torpedo distributed acoustic sensing system and method

Abstract

A method of distributed acoustic sensing in a subterranean well is provided in some embodiments. The method includes advancing a torpedo into a first portion of a wellbore of the subterranean well (the torpedo including a distributed acoustic sensing (DAS) fiber optic (FO) umbilical physically coupled to a surface component and adapted to unwind from the torpedo as the torpedo advances in the wellbore and an engine adapted to generate a thrust to propel the torpedo), and activating the engine to generate a thrust that propels the torpedo to advance within the second portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the second portion of the wellbore.

Description

[0001] This application is a divisional application of the patent application with application number 2020800456501, application date April 24, 2020, and invention name “Distributed acoustic sensing system and method for underground well torpedoes”. Technical Field

[0002] The present invention relates generally to developing hydrocarbon wells, and more particularly to deploying devices into hydrocarbon wells. Background Art

[0003] A well typically includes a wellbore (or "wellbore") drilled into the earth to provide access to geological formations (or "subsurface formations") below the ground. A well can facilitate the extraction of natural resources such as hydrocarbons or water from a subsurface formation, the injection of substances such as water or gas into a subsurface formation, or the evaluation and monitoring of a subsurface formation. In the petroleum industry, hydrocarbon wells are typically drilled to extract (or "produce") hydrocarbons such as oil and gas from subsurface formations. The term "oil well" is typically used to refer to a well designed to produce oil. Similarly, the term "gas well" is typically used to refer to a well designed to produce gas. In the case of an oil well, some natural gas is typically produced along with the oil. Wells that produce both oil and natural gas are sometimes referred to as "oil and gas wells" or "oil wells." The term "hydrocarbon well" is typically used to describe a well that facilitates the production of hydrocarbons, including oil wells and oil and gas wells.

[0004] The construction of hydrocarbon wells generally involves several stages, including the drilling stage, the completion stage, and the production stage. The drilling stage involves drilling a wellbore in an underground formation that is expected to contain recoverable hydrocarbon concentrations. The portion of the underground formation that is expected to contain hydrocarbons is generally referred to as a "hydrocarbon reservoir" or simply a "reservoir". The drilling process is generally assisted by a drilling rig located on the surface. The drilling rig may be provided for operating a drill bit to cut out the wellbore, lifting, lowering, and rotating drill pipe and tools, circulating drilling fluid in the wellbore, and generally controlling operations in the wellbore (generally referred to as "downhole" operations). The completion stage involves preparing the well for the production of hydrocarbons. In some cases, the completion stage includes installing casing tubing in the wellbore, cementing the casing tubing in place with cement, perforating the casing tubing and cement, installing production tubing, installing downhole valves for regulating the production flow, and pumping fluids into the wellbore to fracture, clean, or otherwise prepare the reservoir and the well for the production of hydrocarbons. The production stage involves producing hydrocarbons from the reservoir through the well. During the production phase, the drilling rig is typically removed and replaced with a batch of valves on the surface (commonly referred to as "surface valves" or "Christmas trees"), and valves are installed in the wellbore (commonly referred to as "downhole valves"). These surface valves and downhole valves can be operated to regulate the pressure in the wellbore, control the production flow from the wellbore, and provide access to the wellbore if necessary. Sensors are typically deployed on the surface or in the wellbore to monitor the characteristics of the well. For example, pressure and temperature sensors can be deployed in the wellbore to monitor the pressure and temperature in the wellbore. A pump jack or other mechanism can provide lift that helps extract hydrocarbons from the reservoir, particularly when the pressure in the well is so low that the produced hydrocarbons cannot flow freely to the surface. The flow from the outlet valve of the Christmas tree is typically connected to a distribution network of midstream facilities, such as storage tanks, pipelines, and transportation vehicles, which transport the produced product to downstream facilities, such as refineries and export terminals.

[0005] The various stages of building a hydrocarbon well typically include challenges faced by successfully developing wells and underground formations. During each stage, the well operator may need to monitor the condition of the wellbore to assess the current state of the well, and generate and execute a plan for developing the well or other nearby wells. For example, during the production phase of the well, the well operator may deploy devices such as pressure and temperature sensors in the wellbore to monitor the pressure and temperature of the produced fluid in the wellbore. Such measurements can be used to assess the current and historical production of the well, which in turn can be used to develop a field development plan (FDP) for the well and surrounding wells. The FDP can specify target production rates, injection rates, or other parameters for the well and surrounding wells. The well operator may operate the well or other wells in the same underground formation according to the FDP, such as adjusting the production rate, injection rate, or other parameters, in an effort to optimize the production from the underground formation. Summary of the invention

[0006] The applicant of the present application recognizes that deploying a device into a well may be critical for successfully operating a well and other wells in the same formation. When deciding how best to operate a well and develop an underground formation, a well operator may benefit from an understanding of the characteristics of a well extending into an underground formation. For example, when setting a recovery rate or injection rate for a well or other wells in the same underground formation to optimize recovery from an underground formation, it is critical for a well operator to know the current and historical bottom hole pressure (BHP) and bottom hole temperature (BHT) of the well. Therefore, placing sensors such as BHP sensors and BHT sensors at appropriate locations within the wellbore of a hydrocarbon well to obtain well data (including BHP and BHT of the well) of the well may be critical. As another example, it is critical for a well operator to know the characteristics of an underground formation to determine when and where to drill a well in an underground formation and how to operate a well in the formation. Therefore, placing a formation measurement device (such as a seismic logging device) to obtain formation data of an underground formation may be critical. A seismic logging device may, for example, include an acoustic sensor, such as a geophone.

[0007] The applicant of the present application also recognizes that there are various disadvantages in the prior art for deploying the device into the well. In some cases, the device is deployed into the well by means of gravity. For example, the device can be suspended on a cable that is unwound from the ground to lower the cable and the device into the wellbore. The cable can, for example, include an umbilical cable that provides power and communication with the device. Although this technology can be applicable to vertical wellbores, it may not be applicable to horizontal wellbores. For example, if the wellbore includes a horizontal portion, the device can travel down the vertical portion to the starting point of the horizontal portion by means of gravity, but may stop (or "bottom out") at the transition portion leading to the horizontal portion. As a result, the device and the cable may not advance into the horizontal portion of the wellbore. In some cases, a pulling device is used to further transport the device into the horizontal wellbore. For example, a pulling device may be suspended from a cable that is unwound from the ground to lower the pulling device and the trailing wireline into the wellbore, and the pulling device may be driven to pull the pulling device and the trailing wireline into the horizontal portion of the wellbore. Although this technique can increase access to the horizontal portion of the wellbore, it is generally limited by how far the pulling device can pull the trailing wireline. For example, in the case of a long horizontal portion, the pulling device may not be able to generate the power or pulling force necessary to advance the pulling device and the trailing wireline into the depth of the horizontal portion of the wellbore or completely through the horizontal portion of the wellbore. In addition, when the cable is dragged over the wellbore wall, the cable itself may be damaged due to friction. As a result, the cable may need to have a sturdy packaging, which will increase weight and thus reduce the effective range of the pulling device pulling the cable.

[0008] Recognizing these and other shortcomings of the prior art, the applicants of the present application have developed new systems and methods for deploying devices into a well using a thrust-propelled well torpedo (TPWT) system. In some embodiments, the TPWT system is used to deploy devices such as sensors into the wellbore of a hydrocarbon well such as an oil well. For example, a TPWT having an engine and carrying a payload such as a sensor or other device can be propelled deep into the wellbore of a hydrocarbon well using thrust-based propulsion.

[0009] In some embodiments, the TPWT includes a fiber optic (FO) umbilical that is unwound from the TPWT as the TPWT travels in the wellbore. For example, the TPWT may include a FO umbilical that includes a FO line that is wrapped (or "wound") around an integral reel of the TPWT and is unwound from the TPWT as the TPWT travels through the wellbore. The FO umbilical can provide communication between the TPWT and a control system, such as a well control system located on the surface. For example, the upper end (or "uphole end") of the FO umbilical of the TPWT can be coupled to a well control system of the well, and the lower end (or "downhole end") of the FO umbilical can be coupled to a control system (or "controller") of the TPWT. In such an embodiment, the FO umbilical can provide data communication between the well control system and the control system of the TPWT.

[0010] In some embodiments, the data includes commands related to controlling the operation of the TPWT. For example, the well control system may send commands indicating the operation of the TPWT to the controller of the TPWT by means of the FO umbilical cable. In such an embodiment, the controller may execute the command by controlling the corresponding operation of the TPWT. For example, the well control system may send commands to ignite or extinguish the engine of the TPWT to the controller of the TPWT by means of the FO umbilical cable, and the controller may control the fuel supply valve and igniter of the engine to ignite the engine. In some embodiments, the data includes TPWT operation data related to the operation of the TPWT. For example, the controller of the TPWT may monitor and collect data related to the operation of the engine, controller or payload (such as conditions sensed by sensors of the payload), and may send TPWT operation data corresponding to the collected data to the well control system by means of the FO umbilical cable. The TPWT data may, for example, include data indicating whether the engine is ignited, data indicating the state of the wings, rudders or directional thrust systems of the TPWT, data indicating the speed, orientation or position of the TPWT in the wellbore, or data indicating conditions sensed by sensors. In some embodiments, the well control system generates commands related to controlling the operation of the TPWT based on TPWT operational data received from the TPWT controller.

[0011] In some embodiments, deploying the TPWT into the wellbore includes a gravity-driven free fall of the TPWT in the wellbore, followed by a thrust-driven propulsion of the TPWT further into the wellbore. For example, the TPWT may be released to free fall through a first / upper portion of the wellbore (such as a vertical portion of the wellbore), and upon reaching a trigger point (such as a predetermined depth in the wellbore), an engine of the TPWT may be ignited to generate thrust that propels the TPWT in a second / lower portion of the wellbore (such as a horizontal portion of the wellbore). The TPWT may be parked in a deployed position in the second / lower portion of the wellbore.

[0012] In some embodiments, the body of the TPWT is formed of a material suitable for dissolving upon exposure to a wellbore environment. The material may, for example, include a magnesium alloy. In such embodiments, the TPWT may be parked at a deployment location within a wellbore, and the dissolvable body of the TPWT may dissolve (e.g., over the course of hours, days, or weeks), leaving behind the FO umbilical and any insoluble portions of the TPWT, such as an insoluble sensor payload.

[0013] In some embodiments, it is advantageous to use a soluble TPWT body. For example, a soluble TPWT body can eliminate the need to retrieve the TPWT. Conventional cable devices are typically lowered into a wellbore and later retrieved (e.g., pulled out) from the wellbore for reuse or to prevent the cable device from clogging the wellbore. In contrast, a soluble TPWT body can be produced more cheaply, eliminates the need for reuse, and can simply dissolve to reduce any clogging of the wellbore. Therefore, the use of a soluble TPWT body can eliminate the need for a retrieval operation, or at least simplify any associated retrieval operation. If a retrieval operation is performed, the retrieval operation can simply include pulling the relatively thin and light FO umbilical cable and any insoluble portion of the TPWT that remains connected to the FO umbilical cable, such as an insoluble sensor. In addition, considering that the body of the TPWT may not need to be retrieved, the FO umbilical cable can be relatively thin and light, which is advantageous at least for the reasons described herein, including extending the range of the TPWT, or facilitating cutting of the FO umbilical cable if necessary.

[0014] In some embodiments, it is advantageous to use a FO umbilical. For example, compared to relatively heavy lines such as traditional cable umbilicals, the FO umbilical can have a relatively light weight. This can help reduce the overall weight of the TPWT, thereby enabling the TPWT to travel farther into the wellbore or carry a heavier payload. As another example, compared to relatively thick lines such as traditional cable umbilicals, the FO umbilical can have a relatively small diameter and can be easily cut. This can enable the FO umbilical to pass through relatively small ports in the well system, such as valves passing through the wellhead, and the FO umbilical can be easily cut if necessary. For example, in the case where the FO umbilical has passed through a wellhead valve and an emergency operation of closing the wellhead valve is required, the valve can be simply closed so that the closing action cuts off the FO umbilical. In contrast, conventional cables may be too thick or too tough to be easily cut by the wellhead valve. Therefore, before closing the wellhead valve, the cable may need to be removed from the wellbore or cut in a separate operation. This can cause undesirable significant delays, especially in time-sensitive emergency operations.

[0015] In some embodiments, it is advantageous to unwind the FO umbilical from the TPWT because friction and drag on the FO umbilical during the deployment of the TPWT in the wellbore are reduced. For example, in the case where the line is extended from a reel at the surface and attached to a device to be lowered into the wellbore, the line can be unwound from the surface to lower the device into the wellbore. As a result, the line can be moved through the wellbore with the device and rub against the abrasive walls of the wellbore. The friction generated can physically wear the line and generate friction that prevents the device from advancing in the wellbore. In an effort to address these issues, such a line can be provided with a durable outer coating. Unfortunately, this will increase the weight and thickness of the line, which in turn will limit the range of travel of the device or inhibit the cutting of the line. In contrast, unwinding the FO umbilical from the TPWT as the TPWT travels through the wellbore can prevent significant movement of the FO umbilical within the wellbore. For example, the portion of the FO umbilical that is unwound from the TPWT when the TPWT passes a given depth can be maintained at that depth and the additional length of the FO umbilical can be unwound as the TPWT continues to travel down the wellbore. During deployment, the FO umbilical may rest against the wellbore wall, but it should not experience any significant movement or friction along the wellbore. As a result, the FO umbilical does not create friction that significantly impedes the advancement of the TPWT, and does not require a durable external coating, which can help reduce the weight and thickness of the FO umbilical. This in turn can extend the travel range of the device or facilitate cutting the FO umbilical.

[0016] The TPWT may include various features that facilitate deployment in a hydrocarbon well. In some embodiments, the TPWT includes an integral reel for housing a FO umbilical that is unwound from the TPWT as the TPWT travels through the wellbore of the well. For example, the body of the TPWT may include a recess in an outer surface of the body into which the FO umbilical may be wound. An integral reel may be provided for simple loading of the FO umbilical onto the TPWT, may protect the FO line during transport and travel in a wellbore environment, and may facilitate unwinding of the FO umbilical during travel in a wellbore environment.

[0017] In some embodiments, the TPWT includes navigation elements, such as wings, rudders, or directional thrust systems. The wings of the TPWT may include fixed stabilizers that reduce the aerodynamic sideslip of the TPWT. The rudder of the TPWT may include movable stabilizers that provide steering of the TPWT. The directional thrust system of the TPWT may include a device for directing the thrust generated by the engine of the TPWT. For example, the directional thrust system of the TPWT may include a gimbal-mounted exhaust nozzle that can be rotated to guide the direction of the forward thrust generated by the engine of the TPWT. As another example, the directional thrust system of the TPWT may include a reverse thrust system that includes a bypass duct (or "channel") that can be selectively engaged to direct the thrust generated by the engine of the TPWT in the forward direction. This can produce a "reverse thrust" that slows or stops the movement of the TPWT in the forward direction.

[0018] In some embodiments, the TPWT includes a jet pump engine. The jet pump engine of the TPWT can provide for the introduction of wellbore fluid into the combustion gases of the engine to enhance the thrust generated by the TPWT. For example, the TPWT can include a jet pump engine with a well fluid inlet that directs wellbore fluid into the hot combustion gases before the hot combustion gases are discharged through an outlet nozzle. The mixture of fluid and hot combustion gases can cause the wellbore fluid to expand, resulting in a relative increase in thrust for the amount of propellant burned to produce the gas. This can help to reduce the amount of propellant required or increase the effective range of the TPWT.

[0019] In some embodiments, the TPWT includes an integrated positioning device, such as a casing collar locator (CCL). The CCL may include a device for sensing the transition position between adjacent sections of casing, tubing, or other conduits. For example, the TPWT may include a CCL that includes a first electromagnetic coil and a second electromagnetic coil integrated into the body of the TPWT. The coils may be energized to generate an electromagnet that is capable of sensing changes in the magnetic field caused by changes in the thickness of the surrounding metal pipe (such as casing or tubing). As the TPWT travels through the wellbore and passes through a location where the thickness of the surrounding metal pipe changes, such as a connection between adjacent sections of the casing, the first and second electromagnetic coils may sequentially detect changes in the magnetic field, and the changes may be attributed to the TPWT being located at or passing through a changed location. The location of the well, such as the location of the connection, is typically known based on the construction documents of the well, and therefore, the associated magnetic flux changes may be used to determine the location of the TPWT in the wellbore of the well.

[0020] In some embodiments, the TPWT is used to deploy various types of sensors or other devices into a well. For example, the TPWT may include a payload of sensors, such as a BHP sensor or a BHT sensor. Deployment of the TPWT in the wellbore of the well may be provided for positioning the sensor at a deployment location within the wellbore where the sensor may be operated to acquire data of the well, such as BHP data and BHT data, respectively.

[0021] In some embodiments, the TPWT is used to deploy sensors, such as FO lines, for distributed acoustic sensing (DAS). DAS can be used, for example, for vertical seismic profiles of wells. A DAS FO umbilical may include an FO line capable of sensing seismic events along the length of the FO line. Such a DAS FO umbilical may extend into the wellbore of the well so that the FO line is distributed along the length of the wellbore, wherein the FO line may be operated to sense seismic events at discrete locations along the length of the wellbore. For example, a seismic event may be generated with the aid of an array of seismic sources that are located on the ground and are operated to transmit seismic signals to a portion of the formation around the wellbore. In some embodiments, the TPWT is wound with a DAS FO umbilical, which is unwound from the TPWT as the TPWT travels in the wellbore of the well, and the FO line is then distributed along the length of the wellbore. The use of the TPWT may enable the DAS FO umbilical to be distributed deep into the wellbore with a relatively low amount of friction and wear of the DAS FO umbilical. In some embodiments, the dimensions of the DAS FO umbilical are designed to facilitate contact between the DAS FO umbilical and the lining of the wellbore (such as a metal casing or tubing). For example, the length of the DAS FO umbilical can be about 125% of the length of the wellbore to be routed to facilitate radial expansion of the DAS FO to adhere (or "stick") to the pipe wall by means of surface tension. This extended length can cause the DAS FO umbilical to take a spiral or helical shape when attached to the inner wall. The resulting connection with the pipe wall can help reduce the attenuation of the seismic signal sensed by the DAS FO umbilical.

[0022] In some embodiments, the DAS FO umbilical cable includes a U-bend DAS FO line. The U-bend DAS FO line may include an FO line having a first DAS FO line segment, the first DAS FO line segment terminating in a FO U-bend coupled to a second DAS FO line segment. When deployed, the U-bend may be lowered downhole, with the first and second DAS FO line segments extending to the surface. The ends of the first and second DAS FO line segments may be coupled to other U-bend DAS FO line segments deployed in other wells to provide a continuous DAS FO line extending into multiple wells. An interrogator may be coupled to the continuous DAS FO line to monitor seismic events sensed by the DAS FO line disposed in one or more wells.

[0023] In some embodiments, the U-bend of the DAS FO line includes a circular bend in the DAS FO line connecting adjacent first and second segments of the DAS FO line. In some embodiments, the U-bend of the DAS FO line includes a "micro-bend" connection connecting adjacent first and second segments of the DAS FO line. In some embodiments, the U-bend DAS FO line is wrapped around an integral reel of the TPWT to maintain the curved shape of the U-bend of the FO line. For example, the U-bend DAS FO line can be wrapped around the periphery of the integral reel of the TPWT to maintain the curved shape of the U-bend of the FO line. As another example, the U-bend DAS FO line can be wrapped around the periphery of the integral reel of the TPWT to maintain the curved shape of the U-bend of the FO line with the U-bend being fixed to the surface of the integral reel (e.g., tucked under the wrapped portion of the U-bend DAS FO line) to maintain the curved shape of the U-bend of the FO line. In embodiments where the U-bend DAS FO line includes a micro-bend, the U-bend DAS FO line can be wrapped around the periphery of the integral reel of the TPWT with the micro-bend secured to the surface of the integral reel (e.g., tucked underneath the wrapped portion of the U-bend DAS FO line) to maintain and protect the micro-bend of the FO line.

[0024] In some embodiments, a method of deploying a DAS sensor in a subterranean well is provided. The method includes: releasing a torpedo for gravity-driven advancement within a first portion of a wellbore of the subterranean well (the torpedo including: a DAS FO umbilical cable physically coupled to a surface component and adapted to be unwound from the torpedo as the torpedo advances in the wellbore; and an engine adapted to generate thrust to propel the torpedo forward in the wellbore); determining that the torpedo has reached a trigger point within the wellbore; and in response to determining that the torpedo has reached the trigger point within the wellbore, activating the engine to generate forward thrust to propel the torpedo within a horizontal portion of the wellbore, such that at least some of the DAS FO umbilical cable is disposed in the horizontal portion of the wellbore, and the torpedo stops at a deployed position within the wellbore.

[0025] In some embodiments, a method of performing distributed acoustic sensing in a subterranean well is provided, the method comprising: advancing a torpedo into a first portion of a wellbore of the subterranean well (the torpedo comprising: a DAS FO umbilical cable, the DAS FO umbilical cable being physically connected to a surface component and being adapted to be unwound from the torpedo as the torpedo advances in the wellbore; and an engine, the engine being adapted to generate thrust to propel the torpedo); and activating the engine to generate thrust to propel the torpedo forward in a second portion of the wellbore, such that at least some of the DAS FO umbilical cable is disposed in the second portion of the wellbore.

[0026] In some embodiments, after the torpedo stops at the deployment position, the DAS FO umbilical extends from the surface component into the second portion of the wellbore. In some embodiments, the method further includes: after the torpedo stops at the deployment position in the wellbore, performing a seismic operation, the seismic operation comprising sensing a seismic event with the aid of the DAS FO umbilical unwinding in the wellbore. In some embodiments, the method further includes: positioning a plurality of seismic sources at the surface location, wherein the seismic operation further comprises operating the seismic sources to generate a seismic signal, and wherein the seismic event corresponds to the generated seismic signal. In some embodiments, the method further includes: after the torpedo stops at the deployment position in the wellbore, performing a fluid flow monitoring operation, the fluid flow monitoring operation comprising sensing fluid flow with the aid of the DAS FO umbilical unwinding in the wellbore. In some embodiments, the method further includes: after the torpedo stops at the deployment position in the wellbore, performing a leakage monitoring operation, the leakage monitoring operation comprising sensing leakage with the aid of an integrated acoustic sensor of the DAS FO umbilical unwinding in the wellbore. In some embodiments, the DAS FO umbilical comprises a single section of FO line. In some embodiments, the DAS FO line comprises a U-bend DAS FO line comprising a first segment of the DAS FO line and a second segment of the DAS FO line connected by a U-bend. In some embodiments, the torpedo comprises a cylindrical reel, and the method further comprises: wrapping the U-bend around the periphery of the reel, and wrapping the first segment and the second segment of the DAS FO line around the U-bend wrapped on the periphery of the reel. In some embodiments, the torpedo comprises a cylindrical reel, and the method further comprises: arranging the U-bend on a surface of the reel, and wrapping the first segment and the second segment of the DAS FO line around the U-bend arranged on the surface of the reel. In some embodiments, the U-bend comprises a micro-bend connector. In some embodiments, a first portion of a DAS FO umbilical including a first segment of the DAS FO, a second segment of the DAS FO line, and a U-bend is arranged in a wellbore using a torpedo, and the method further includes deploying a second portion of the DAS FO umbilical into a second wellbore using a second torpedo, the second portion of the DAS FO umbilical including a third segment of the DAS FO line and a fourth segment of the DAS FO line connected by a second U-bend. In certain embodiments, the method further includes performing a seismic operation including sensing a seismic event with the first portion of the DAS FO umbilical arranged in the wellbore and the second portion of the DAS FO umbilical arranged in the second wellbore. In some embodiments, the torpedo includes a body formed of a dissolvable material suitable for dissolving in the wellbore, and the method further includes leaving the torpedo at the deployment location such that the body of the torpedo dissolves at the deployment location within the wellbore.In some embodiments, the DAS FO umbilical is coupled to a well control system and is adapted to facilitate communication between the torpedo and the well control system, and the method further comprises: the well control system receiving data from the torpedo by means of the DAS FO umbilical. In some embodiments, the second portion of the wellbore comprises a horizontal portion of the wellbore. In some embodiments, the method further comprises: determining that the torpedo has reached a trigger point within the wellbore, wherein the engine is activated to generate thrust in response to determining that the torpedo has reached the trigger point within the wellbore. In some embodiments, the trigger point within the wellbore comprises a predetermined depth within the wellbore. In some embodiments, the first portion of the wellbore comprises a vertical portion of the wellbore and the second portion of the wellbore comprises a horizontal portion of the wellbore, and the trigger point within the wellbore comprises a transition point between the vertical portion of the wellbore and the horizontal portion of the wellbore.

[0027] In some embodiments, a non-transitory computer-readable storage medium is provided, including program instructions stored on the readable storage medium, and the program instructions can be executed by a processor to perform the above method operations.

[0028] In some embodiments, a subterranean well torpedo system is provided, the subterranean well torpedo system comprising: a control system; and a torpedo, the torpedo comprising: a DAS FO umbilical cable physically coupled to a surface component and adapted to be unwound from the torpedo as the torpedo advances in a wellbore; and an engine adapted to generate thrust to propel the torpedo. The control system is adapted to: advance the torpedo into a first portion of a wellbore of a subterranean well; and activate the engine to generate thrust to propel the torpedo within a second portion of the wellbore, such that at least some of the DAS FO umbilical cable is disposed in the second portion of the wellbore.

[0029] In some embodiments, after the torpedo stops at the deployment position, the DAS FO umbilical extends from the surface component into the second portion of the wellbore. In some embodiments, the control system is further adapted to perform a seismic operation after the torpedo stops at the deployment position within the wellbore, the seismic operation comprising sensing a seismic event by means of the DAS FO umbilical unwinding in the wellbore. In some embodiments, a plurality of seismic sources are located at the surface location, and the seismic operation further comprises operating the seismic sources to generate a seismic signal, and wherein the seismic event corresponds to the generated seismic signal. In some embodiments, the control system is further adapted to perform a fluid flow monitoring operation after the torpedo stops at the deployment position within the wellbore, the fluid flow monitoring operation comprising sensing fluid flow by means of the DAS FO umbilical unwinding in the wellbore. In some embodiments, the control system is further adapted to perform a leakage monitoring operation after the torpedo stops at the deployment position within the wellbore, the leakage monitoring operation comprising sensing leakage by means of the DAS FO umbilical unwinding in the wellbore. In some embodiments, the DAS FO umbilical comprises a single section of FO line. In some embodiments, the DAS FO line comprises a U-bend DAS FO line comprising a first segment of the DAS FO line and a second segment of the DAS FO line connected by a U-bend. In some embodiments, the torpedo comprises a cylindrical reel, and wherein the U-bend is wrapped around the periphery of the reel, and the first segment and the second segment of the DAS FO line are wrapped around the U-bend wrapped around the periphery of the reel. In some embodiments, the torpedo comprises a cylindrical reel, and wherein the U-bend is arranged on a surface of the reel, and the first segment and the second segment of the DAS FO line are wrapped around the U-bend arranged on the surface of the reel. In some embodiments, the U-bend comprises a micro-bend connector. In some embodiments, a first portion of the DAS FO umbilical includes a first section of the DAS FO, a second section of the DAS FO line, and a U-bend, the first section of the DAS FO line is arranged in a wellbore using a torpedo, and the second section of the DAS FO umbilical is arranged in a second wellbore, the second section of the DAS FO umbilical includes a third section of the DAS FO line and a fourth section of the DAS FO line connected by a second U-bend. In some embodiments, the control system is further adapted to perform seismic operations including sensing seismic events with the aid of the first section of the DAS FO umbilical arranged in the wellbore and the second section of the DAS FO umbilical arranged in the second wellbore. In some embodiments, the torpedo includes a body formed of a dissolvable material adapted to dissolve in the wellbore. In some embodiments, the DAS FO umbilical is coupled to a well control system and adapted to facilitate communication between the torpedo and the well control system. In some embodiments, the second section of the wellbore includes a horizontal portion of the wellbore.In certain embodiments, the control system is further adapted to determine that the torpedo has reached a trigger point within the wellbore, and in response to determining that the torpedo has reached the trigger point within the wellbore, activate the engine to generate thrust. In certain embodiments, the trigger point within the wellbore comprises a predetermined depth within the wellbore. In certain embodiments, the first portion of the wellbore comprises a vertical portion of the wellbore, and the second portion of the wellbore comprises a horizontal portion of the wellbore, and the trigger point within the wellbore comprises a transition point between the first wellbore portion and the second wellbore portion of the wellbore. In certain embodiments, the length of the DAS FO umbilical is at least 25% greater than the distance between the surface component and the target deployment location within the wellbore. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 is a diagram illustrating a well environment according to one or more embodiments.

[0031] Figure 2 is a diagram illustrating a thrust-propelled well torpedo (TPWT) according to one or more embodiments.

[0032] Figure 3 is a diagram illustrating a TPWT tree cap according to one or more embodiments.

[0033] Figure 4 is a diagram illustrating deployment of TPWTs according to one or more embodiments.

[0034] Figures 5 to 8 is a diagram illustrating an exemplary thrust-propelled well torpedo (TPWT) according to one or more embodiments.

[0035] Fig. 9 and Fig.10 is a diagram illustrating exemplary well distributed acoustic sensing (DAS) using TPWT according to one or more embodiments.

[0036] Fig.11 and Fig.12 is a diagram illustrating an exemplary coiling of a U-bend DAS optical fiber (FO) line according to one or more embodiments.

[0037] Fig.13 is a flow chart illustrating a method of DAS sensing using TPWT according to one or more embodiments.

[0038] Fig.14 is a flow chart illustrating a method of deploying a TPWT into a well according to one or more embodiments.

[0039] Fig.15 is a diagram illustrating an exemplary computer system in accordance with one or more embodiments.

[0040] Although the disclosure of the present invention is susceptible to various modifications and alternative forms, specific embodiments are shown by way of example in the drawings and will be described in detail. The drawings may not be drawn to scale. It should be understood that the drawings and detailed description are not intended to limit the disclosure of the present invention to the specific forms described, but rather to disclose modifications, equivalents, and alternatives that fall within the scope of the disclosure of the present invention as defined by the claims. DETAILED DESCRIPTION

[0041] Embodiments of novel systems and methods for deploying devices into a well (e.g., a hydrocarbon well) with the aid of a thrust-propelled well torpedo (TPWT) system are described. In some embodiments, the TPWT system is used to deploy devices, such as sensors, into the wellbore of a hydrocarbon well, such as an oil well. For example, a TPWT having an engine and carrying a payload, such as a sensor or other device, can be propelled deep into the wellbore of a hydrocarbon well with the aid of thrust-based propulsion.

[0042] In some embodiments, the TPWT includes a fiber optic (FO) umbilical that is unwound from the TPWT as the TPWT travels in the wellbore. For example, the TPWT may include a FO umbilical that includes a FO line that is wrapped (or "wound") around an integral reel of the TPWT and is unwound from the TPWT as the TPWT travels through the wellbore. The FO umbilical can provide communication between the TPWT and a control system, such as a well control system located at the surface. For example, the upper end (or "uphole end") of the FO umbilical of the TPWT can be coupled to a well control system of the well, and the lower end (or "downhole end") of the FO umbilical can be coupled to a control system (or "controller") of the TPWT. In such an embodiment, the FO umbilical can provide data communication between the well control system and the control system of the TPWT.

[0043] In some embodiments, the data includes commands related to controlling the operation of the TPWT. For example, the well control system may send commands indicating the operation of the TPWT to the controller of the TPWT by means of the FO umbilical cable. In such an embodiment, the controller may execute the command by controlling the corresponding operation of the TPWT. For example, the well control system may send commands to ignite or extinguish the engine of the TPWT to the controller of the TPWT by means of the FO umbilical cable, and the controller may control the fuel supply valve and igniter of the engine to ignite the engine. In some embodiments, the data includes TPWT operation data related to the operation of the TPWT. For example, the controller of the TPWT may monitor and collect data related to the operation of the engine, controller or payload (such as conditions sensed by sensors of the payload), and may send TPWT operation data corresponding to the collected data to the well control system by means of the FO umbilical cable. The TPWT data may, for example, include data indicating whether the engine is ignited, data indicating the state of the wings, rudders or directional thrust systems of the TPWT, data indicating the speed, orientation or position of the TPWT in the wellbore, or data indicating conditions sensed by sensors. In some embodiments, the well control system generates commands related to controlling the operation of the TPWT based on TPWT operational data received from the TPWT controller.

[0044] In some embodiments, deploying the TPWT into the wellbore includes a gravity-driven free fall of the TPWT in the wellbore, followed by a thrust-driven propulsion of the TPWT further into the wellbore. For example, the TPWT may be released to free fall through a first / upper portion of the wellbore (such as a vertical portion of the wellbore), and upon reaching a trigger point (such as a predetermined depth in the wellbore), the engine of the TPWT may be ignited to generate thrust that propels the TPWT in a second / lower portion of the wellbore (such as a horizontal portion of the wellbore). The TPWT may be stopped at a deployed position in the second / lower portion of the wellbore.

[0045] In some embodiments, the body of the TPWT is formed of a material that is suitable for dissolving when exposed to the wellbore environment. The material may, for example, include a magnesium alloy. In such an embodiment, the TPWT may be parked at a deployment location within the wellbore, and the dissolvable body of the TPWT may dissolve (e.g., over the course of hours, days, or weeks), leaving behind the FO umbilical and any insoluble portions of the TPWT, such as an insoluble sensor payload.

[0046] In some embodiments, it is advantageous to use a soluble TPWT body. For example, a soluble TPWT body can eliminate the need to retrieve the TPWT. Conventional wireline devices are typically lowered into a wellbore and later retrieved (e.g., pulled out) from the wellbore for reuse or to prevent the wireline device from clogging the wellbore. In contrast, a soluble TPWT body can be produced more cheaply, eliminates the need for reuse, and can simply dissolve to reduce any clogging of the wellbore. Therefore, the use of a soluble TPWT body can eliminate the need for a retrieval operation, or at least simplify any associated retrieval operation. If a retrieval operation is performed, the retrieval operation can simply include pulling the relatively thin and light FO umbilical cable and any insoluble portion of the TPWT that remains connected to the FO umbilical cable, such as an insoluble sensor. In addition, given that it may not be necessary to retrieve the body of the TPWT, the FO umbilical cable can be relatively thin and light, which is advantageous at least for the reasons described herein, including extending the range of the TPWT, or facilitating cutting of the FO umbilical cable if necessary.

[0047] In some embodiments, it is advantageous to use a FO umbilical. For example, compared to relatively heavy lines such as traditional cable umbilicals, the FO umbilical can have a relatively light weight. This can help reduce the overall weight of the TPWT, thereby enabling the TPWT to travel farther into the wellbore or carry a heavier payload. As another example, compared to relatively thick lines such as traditional cable umbilicals, the FO umbilical can have a relatively small diameter and can be easily cut. This can enable the FO umbilical to pass through relatively small ports in the well system, such as through a wellhead valve, and if necessary, the FO umbilical can be easily cut. For example, in the case where the FO umbilical has passed through a wellhead valve and an emergency operation of closing the wellhead valve is required, the valve can be simply closed, wherein the closing action cuts off the FO umbilical. In contrast, conventional cables may be too thick or too tough to be easily cut by the wellhead valve. Therefore, before closing the wellhead valve, it may be necessary to remove the cable from the wellbore or cut the cable in a separate operation. This can cause unexpected significant delays, especially in time-sensitive emergency operations.

[0048] In some embodiments, it is advantageous to unwind the FO umbilical from the TPWT because friction and drag on the FO umbilical during deployment of the TPWT in the wellbore is reduced. For example, in the case where the line is extended from a reel at the surface and attached to a device to be lowered into the wellbore, the line can be unwound from the surface to lower the device into the wellbore. As a result, the line can be moved through the wellbore with the device and rub against the abrasive walls of the wellbore. The friction generated physically wears the line and generates friction that prevents the device from advancing in the wellbore. In an effort to address these issues, such a line can be provided with a durable outer coating. Unfortunately, this increases the weight and thickness of the line, which in turn limits the range of travel of the device or inhibits the cutting of the line. In contrast, unwinding the FO umbilical from the TPWT as the TPWT travels through the wellbore can prevent significant movement of the FO umbilical within the wellbore. For example, the portion of the FO umbilical that is unwound from the TPWT when the TPWT passes a given depth can be maintained at that depth and the additional length of the FO umbilical unwound as the TPWT continues to travel down the wellbore. During deployment, the FO umbilical may rest against the wellbore wall, but it should not experience any significant movement or friction along the wellbore. As a result, the FO umbilical does not create friction that significantly impedes the advancement of the TPWT, and does not require a durable external coating, which can help reduce the weight and thickness of the FO umbilical. This in turn can extend the travel range of the device or facilitate cutting the FO umbilical.

[0049] The TPWT may include various features that facilitate deployment in a hydrocarbon well. In some embodiments, the TPWT includes an integral reel for housing a FO umbilical that is unwound from the TPWT as the TPWT travels through the wellbore of the well. For example, the body of the TPWT may include a recess in an outer surface of the body into which the FO umbilical may be wound. An integral reel may be provided for simple loading of the FO umbilical onto the TPWT, may protect the FO line during transport and travel in a wellbore environment, and may facilitate unwinding of the FO umbilical during travel in a wellbore environment.

[0050] In some embodiments, the TPWT includes navigation elements, such as wings, rudders, or directional thrust systems. The wings of the TPWT may include fixed stabilizers that reduce the aerodynamic sideslip of the TPWT. The rudder of the TPWT may include movable stabilizers that provide steering of the TPWT. The directional thrust system of the TPWT may include a device for directing the thrust generated by the engine of the TPWT. For example, the directional thrust system of the TPWT may include a gimbal-mounted exhaust nozzle that can be rotated to guide the direction of the forward thrust generated by the engine of the TPWT. As another example, the directional thrust system of the TPWT may include a reverse thrust system that includes a bypass duct (or "channel") that can be selectively engaged to direct the thrust generated by the engine of the TPWT in the forward direction. This can produce a "reverse thrust" that slows or stops the movement of the TPWT in the forward direction.

[0051] In some embodiments, the TPWT includes a jet-pump engine. The jet-pump engine of the TPWT can provide for the introduction of wellbore fluid into the combustion gases of the engine to enhance the thrust generated by the TPWT. For example, the TPWT can include a jet-pump engine with a well fluid inlet that directs wellbore fluid into the hot combustion gases before the hot combustion gases are discharged through an outlet nozzle. The mixture of fluid and hot combustion gases can cause the wellbore fluid to expand, resulting in a relative increase in thrust for the amount of propellant burned to produce the gas. This helps to reduce the amount of propellant required or increase the effective range of the TPWT.

[0052] In some embodiments, the TPWT includes an integrated positioning device, such as a casing collar locator (CCL). The CCL may include a device for sensing the transition position between adjacent sections of casing, tubing, or other conduits. For example, the TPWT may include a CCL that includes a first electromagnetic coil and a second electromagnetic coil integrated into the body of the TPWT. The coils may be energized to generate an electromagnet that is capable of sensing changes in the magnetic field caused by changes in the thickness of the surrounding metal pipe (such as casing or tubing). As the TPWT travels through the wellbore and passes through a location where the thickness of the surrounding metal pipe changes, such as a connection between adjacent sections of the casing, the first and second electromagnetic coils may sequentially detect changes in the magnetic field, and the changes may be attributed to the TPWT being located at or passing through a changed location. The location of the well, such as the location of the connection, is typically known based on the construction documents of the well, and therefore, the associated magnetic flux changes may be used to determine the location of the TPWT in the wellbore of the well.

[0053] In some embodiments, the TPWT is used to deploy various types of sensors or other devices into a well. For example, the TPWT may include a payload of sensors, such as a BHP sensor or a BHT sensor. Deployment of the TPWT in the wellbore of the well may be provided for positioning the sensor at a deployment location within the wellbore where the sensor may be operated to acquire data of the well, such as BHP data and BHT data, respectively.

[0054] In some embodiments, the TPWT is used to deploy sensors, such as FO lines, for distributed acoustic sensing (DAS). DAS can be used, for example, for vertical seismic profiles of wells. A DAS FO umbilical may include an FO line capable of sensing seismic events along the length of the FO line. Such a DAS FO umbilical may extend into the wellbore of the well so that the FO line is distributed along the length of the wellbore, wherein the FO line may be operated to sense seismic events at discrete locations along the length of the wellbore. For example, a seismic event may be generated with the aid of an array of seismic sources that are located on the ground and are operated to transmit seismic signals to a portion of the formation located around the wellbore. In some embodiments, the TPWT is wound with a DAS FO umbilical, which is unwound from the TPWT as the TPWT travels in the wellbore of the well, and the FO line is then distributed along the length of the wellbore. The use of the TPWT may enable the DAS FO umbilical to be distributed deep into the wellbore with a relatively low amount of friction and wear of the DAS FO umbilical. In some embodiments, the dimensions of the DAS FO umbilical are designed to facilitate contact between the DAS FO umbilical and the lining of the wellbore (such as a metal casing or tubing). For example, the length of the DAS FO umbilical can be about 125% of the length of the wellbore to be routed to facilitate radial expansion of the DAS FO to adhere (or "stick") to the pipe wall by means of surface tension. This extended length can cause the DAS FO umbilical to take a spiral or helical shape when attached to the inner wall. The resulting connection with the pipe wall can help reduce the attenuation of the seismic signal sensed by the DAS FO umbilical.

[0055] In some embodiments, the DAS FO umbilical cable includes a U-bend DAS FO line. The U-bend DAS FO line may include an FO line having a first DAS FO line segment, the first DAS FO line segment terminating in a FO U-bend coupled to a second DAS FO line segment. When deployed, the U-bend may be lowered downhole, with the first and second DAS FO line segments extending to the surface. The ends of the first and second DAS FO line segments may be coupled to other U-bend DAS FO line segments deployed in other wells to provide a continuous DAS FO line extending into multiple wells. An interrogator may be coupled to the continuous DAS FO line to monitor seismic events sensed by the DAS FO line disposed in one or more wells.

[0056] In some embodiments, the U-bend of the DAS FO line includes a circular bend in the DAS FO line connecting adjacent first and second segments of the DAS FO line. In some embodiments, the U-bend of the DAS FO line includes a "micro-bend" connection connecting adjacent first and second segments of the DAS FO line. In some embodiments, the U-bend DAS FO line is wrapped around an integral reel of the TPWT to maintain the curved shape of the U-bend of the FO line. For example, the U-bend DAS FO line can be wrapped around the periphery of the integral reel of the TPWT to maintain the curved shape of the U-bend of the FO line. As another example, the U-bend DAS FO line can be wrapped around the periphery of the integral reel of the TPWT to maintain the curved shape of the U-bend of the FO line with the U-bend being fixed to the surface of the integral reel (e.g., tucked under the wrapped portion of the U-bend DAS FO line) to maintain the curved shape of the U-bend of the FO line. In embodiments where the U-bend DAS FO line includes a micro-bend, the U-bend DAS FO line can be wrapped around the periphery of the integral reel of the TPWT with the micro-bend secured to the surface of the integral reel (e.g., tucked underneath the wrapped portion of the U-bend DAS FO line) to maintain and protect the micro-bend of the FO line.

[0057] Although certain embodiments are described with respect to hydrocarbon wells for purposes of illustration, embodiments may be used with other types of subterranean wells, such as water wells.

[0058] Figure 11 is a diagram illustrating a well environment 100 according to one or more embodiments. In the illustrated embodiment, the well environment 100 includes a reservoir ("reservoir") 102 located in a subsurface formation ("formation") 104, and a well system ("well system") 106. In some embodiments, the well system 106 includes a TPWT system 110. As described herein, in some embodiments, the TPWT system 110 is used to deploy a device such as a BHT sensor, a BHP sensor, or a DAS sensor into a wellbore of the well system 106.

[0059] The formation 104 may include a porous or fractured rock formation located underground below the ground ("surface") 112. The reservoir 102 may be a hydrocarbon reservoir defined by a portion of the formation 104 that contains (or is at least determined to contain or expected to contain) underground pools of hydrocarbons (such as oil and gas). The formation 104 and the reservoir 102 may each include different rock layers with different properties (such as different degrees of permeability, porosity, and fluid saturation). In the case where the well system 106 is operated as a production well, the well system 106 may facilitate the extraction (or "production") of hydrocarbons from the reservoir 102. In the case where the well system 106 is operated as an injection well, the well system 106 may facilitate the injection of substances such as water or gas into the formation 104 or reservoir 102. In the case where the well system 106 is operated as a monitoring well, the well system 106 may facilitate the monitoring of various properties of the formation 104 or reservoir 102, such as reservoir pressure.

[0060] The well system 106 may include a hydrocarbon well (or "well") 114 and a well operating system 116. The well operating system 116 may include components for developing and operating the well 114, including a well control system 118 and the TPWT system 110. The well control system 118 may control various operational aspects of the well system 106, such as drilling operations, completion operations, well recovery operations, or well and formation monitoring operations. As described above, in some embodiments, the well control system 118 controls the operation of the TPWT system 110 to deploy devices such as BHT sensors, BHP sensors, or DAS sensors into the wellbore of the well 114. In some embodiments, the well control system 118 includes components related to at least Fig.15 The computer system 2000 described herein is the same as or similar to a computer system.

[0061] Well 114 may include a wellbore (or "wellbore") 120. Wellbore 120 may include a borehole extending from the surface 112 to a target area of ​​formation 104, such as reservoir 102. The upper end of wellbore 120 at or near the surface 112 may be referred to as the "uphole" end of wellbore 120. The lower end of wellbore 120 that terminates in formation 104 may be referred to as the "downhole" end of wellbore 120. For example, wellbore 120 may be formed by drilling through formation 104 and reservoir 102 with a drill bit. The wellbore 120 may be provided for circulating drilling fluids during drilling operations, for flowing hydrocarbons (such as oil or gas) from the reservoir 102 to the surface 112 during production operations, for injecting substances (such as water and gas) into the formation 104 or the reservoir 102 during injection operations, or for communicating monitoring devices (such as sensors or logging tools) with one or both of the formation 104 and the reservoir 102 during monitoring operations (such as in-situ sensing or logging operations). The wellbore 120 may include a main bore 122 and one or more lateral bores 124.

[0062] The well 114 may include completion elements, such as casing 126, installed in the wellbore 120. The casing 126 may, for example, include a tubular section of steel casing tubing that lines the inner diameter of the wellbore 120. In some embodiments, the casing 126 includes a fill material, such as casing cement, sunk in an annular region between the exterior of the casing tubing of the casing 126 and the wall of the wellbore 120. In some embodiments, the casing 126 includes a casing collar 128 defined by a thickness variation of the casing tubing or a joint between adjacent casing tubing sections that form the casing 126. As described above, the casing collar 128 or collars of other elements disposed in the wellbore 120 may be detected by the casing collar locator (CCL) device as it passes through the wellbore 120. The portion of the wellbore 120 where the casing 126 is installed may be referred to as a "cased" portion of the wellbore 120. The portion of the wellbore 120 that is not installed with the casing 126 may be referred to as the "open hole" or "uncased" portion of the wellbore 120. For example, in the illustrated embodiment, the upper portion of the wellbore 120 that is installed with the casing 126 may be referred to as the "cased" portion of the wellbore 120, and the lower portion of the wellbore 120 below the lower end of the casing 126 (or "downhole" relative to the lower end) may be referred to as the "uncased" (or "open hole") portion of the wellbore 120. In some embodiments, "downhole" devices are positioned in the wellbore 120 to monitor conditions in the wellbore 120 or to perform operations in the wellbore 120. For example, a BHP sensor and a BHT sensor may be arranged in the wellbore 120 to measure BHP and BHT in the wellbore 120.

[0063] The well 114 may include surface components, such as a wellhead 130. The wellhead 130 may include a device disposed at the uphole end of the wellbore 120 to provide a structural and pressure-bearing interface between the wellbore 120 and the drilling and production equipment of the well system 106. For example, the wellhead 130 may include a structure having a passage that provides access to the wellbore 120 and supports the weight of the casing 126 or other downhole components suspended in the wellbore 120. The wellhead 130 may include seals and valves that restrict access to the wellbore 120. During drilling operations, a blowout preventer may be coupled to the wellhead 130 to control the pressure in the wellbore 120. During production operations, a Christmas tree may be coupled to the wellhead 130 to control the production flow and pressure. As described herein, in some embodiments, a TPWT tree cap is coupled to the wellhead 130 to facilitate deployment of the TPWT into the wellbore 120.

[0064] In some embodiments, the well control system 118 stores or otherwise accesses well data 132. The well data 132 may include data indicating various characteristics of the well 114, the formation 104, or the reservoir 102. The well data 132 may include, for example, a well location, a well trajectory, a well log, or well and formation characteristics. The well location may include coordinates defining the location where the upper end of the wellbore 120 penetrates the ground 112. The well trajectory of the well may include coordinates defining the wellbore path of the well. For example, Figure 1 The well trajectory of the wellbore 120 may include coordinates of the paths of the main hole 122 and the lateral hole 124. In some embodiments, the well data 132 of the well includes casing collar locations that define the depths at which the casing collars are located in the wellbore of the well.

[0065] In some embodiments, the well control system 118 stores or otherwise accesses TPWT parameters 134. The TPWT parameters 134 may, for example, specify parameters for deploying a TPWT into a wellbore 120 of the well 114. In some embodiments, the TPWT parameters 134 specify a predetermined trigger point. The trigger point may define a location such as a depth in the wellbore 120, or a moment after the TPWT is released into free fall when it should transition from free fall to a propulsive operation. In some embodiments, the TPWT parameters 134 specify a predetermined route. The route may define a path within the wellbore 120 that will be traversed by the TPWT in the wellbore 120, such as a path through a vertical section of the main bore 122 and extending into a horizontal section of the main bore 122 or a side bore 124. The TPWT parameters 134 may be predefined, for example, by a well operator.

[0066] In some embodiments, the TPWT system 110 includes a thrust-propelled torpedo (TPWT) 140, a TPWT umbilical ("umbilical") 142, and a TPWT tree cap ("tree cap") 144. As described above, the TPWT system 110 can be used to deploy devices such as BHT sensors, BHP sensors, or DAS sensors into the wellbore 120 of the well 114. In some embodiments, the umbilical 142 is an optical fiber (FO) umbilical formed by an FO line. The FO line can be provided for FO data communications between the TPWT 140 and the well control system 118. In some embodiments, the umbilical 142 does not include a conduit for delivering electrical power. For example, the umbilical 142 may not provide communication of operating power from the well control system 118 to the TPWT 140. As described above, in some embodiments, the umbilical 142 includes a DAS FO line capable of sensing seismic events along the length of the DAS FO line, and deploying the umbilical into the well 114 using the TPWT 140 may provide for positioning the FO line along the length of the wellbore 120 of the well 114.

[0067] Figure 2 is a diagram illustrating a TPWT 140 according to one or more embodiments. In some embodiments, the TPWT 140 includes a TPWT body ("body") 200, a TPWT engine ("engine") 202, a TPWT payload ("payload") 204, an integrated TPWT reel ("reel") 206, and a TPWT controller 208. The engine 202 may include a solid propellant driven engine operable to generate thrust to propel the TPWT 140 forward in the wellbore 120. The thrust may be generated, for example, by a jet of gas or liquid discharged from the engine 202. In some embodiments, such a jet may be discharged in a rearward direction to generate forward thrust that provides forward propulsion of the TPWT 140 (e.g., toward the downhole end of the wellbore 120). In some embodiments, some or all of the jets may be directed in a forward direction to generate a reverse thrust that limits the forward propulsion of the TPWT 140 or moves the TPWT 140 in a reverse direction (e.g., "backward" toward the uphole end of the wellbore 120). The payload 204 may include various types of devices, such as a BHP sensor or a BHT sensor. In some embodiments, the umbilical 142 is the payload 204. For example, where it is desired to deploy a DAS FO line into the wellbore 120, the DAS FO line may be used as the umbilical 142 and be the payload 204.

[0068] A TPWT controller 208 may be provided for monitoring and controlling the operation of the TPWT 140, or for communicating with devices external to the TPWT 140, such as the well control system 118. In some embodiments, the TPWT controller 208 includes a processor 218, a memory 220, and a local power source 222. The local power source 222 may be, for example, a battery. The local power source 222 may supply power to operate the controller 208 or other devices of the TPWT 140, such as sensors, valves, igniters, navigation elements, or the payload 204.

[0069] In some embodiments, the TPWT controller 208 may monitor the status of various elements of the TPWT 140. For example, the TPWT controller 208 may monitor the operating status of the engine 202, the operating status of the navigation elements of the TPWT 140 (such as the position of the stabilizer and reverse thrust system), the operating status of the sensors of the TPWT 140 (such as the CCL), or the operating status of the payload 204 of the TPWT 140 (such as the BHP sensor or the BHT sensor). The controller 208 may transmit the corresponding TPWT operating data to the well control system 118 via the umbilical cable 142.

[0070] In some embodiments, the TPWT controller 208 may control various aspects of the operation of the TPWT 140. For example, the TPWT controller 208 may receive commands related to controlling the operation of the TPWT 140 and may execute these commands by controlling the corresponding operation of the TPWT 140. The commands may be received from the well control system 118 via the umbilical cable 142. In some embodiments, the TPWT controller 208 includes at least one Fig.15 140 . Although some embodiments are described with respect to the well control system 118 sending commands and the TPWT controller 208 executing the commands and reporting operational data to the well control system 118, embodiments may include the TPWT controller 208 performing operational tasks independently of the well control system 118. For example, the TPWT controller 208 may locally process the TPWT operational data to determine the status of the TPWT 140 and the corresponding operational tasks, and may then control the operation of the TPWT 140 to perform the tasks. For example, when the controller 208 determines that the TPWT 140 has reached a target point in the wellbore 120, the TPWT 140 may initiate ignition of the engine 202.

[0071] In some embodiments, the body 200 of the TPWT 140 is formed of a material that is suitable for dissolving when exposed to the wellbore environment. The body 200 may be formed, for example, of a magnesium alloy that is expected to dissolve in the wellbore 120. In such embodiments, the TPWT 140 may be parked at a deployment location within the wellbore 120, and the dissolvable body 200 of the TPWT 140 may dissolve (e.g., over the course of hours, days, or weeks), thereby leaving the umbilical 142 and any insoluble portions of the TPWT 140, such as the payload 204 or the controller 208, at the deployment location.

[0072] In some embodiments, the body 200 is cylindrical with a tapered front end (or "nose") 210. The thrust generated by the engine 202 may be discharged rearwardly (in the direction of arrow 212) from the rear end (or "tail end") 214 of the body 200 to generate forward thrust that propels the TPWT 140 forwardly (in the direction of arrow 216). For example, combustion gases generated by the engine 202 may be discharged rearwardly via an outlet nozzle of the engine 202 located at the tail end of the body 200 to generate forward thrust that propels the TPWT 140 forwardly (e.g., toward the downhole end of the wellbore 120). In some embodiments, some or all of the thrust generated by the engine 202 may be selectively discharged forwardly (in the direction of arrow 216) from the front end 210 of the body 200 to generate reverse thrust that slows or stops the forward propulsion of the TPWT 140. For example, at least some of the combustion gases generated by the engine 202 may be discharged in a forward direction to generate reverse thrust that slows or stops the forward propulsion of the TPWT 140. The magnitude of the forward or reverse thrust may be controlled to adjust the speed of the TPWT 140 or to stop the TPWT at or near a given deployment location in the wellbore 120. In some embodiments, the reverse thrust may be of sufficient magnitude to move the TPWT 140 in the reverse direction (e.g., "backward" toward the uphole end of the wellbore 120).

[0073] In some embodiments, the reel 206 provides a location for housing the umbilical 142 at the TPWT 140. The reel 206 enables the umbilical 142 to be unwound from the TPWT 140 as the TPWT 140 travels through the wellbore 120 of the well 114. For example, the reel 206 may include a circumferential depression (or "recess") extending along the length of the exterior of the cylindrical body 200. The umbilical 142 may be wound onto the reel 206 (e.g., the umbilical may be wound in the recess around the body 200) with the uphole end of the umbilical 142 physically coupled to a surface component such as the TPWT tree cap 144. During deployment of the TPWT 140 into the wellbore 120, the umbilical 142 may be unwound (or "unwound") from the reel 206 as the TPWT 140 advances down the wellbore 120. In some embodiments, the recess of the reel 206 has a sufficient depth so that the windings of the umbilical 142 loaded onto the reel 206 do not protrude radially outward from the recess. Such a reel 206 can be provided for easily loading the umbilical 142 onto the TPWT 140, can protect the umbilical 142 during assembly and transportation of the TPWT 140 and during travel of the TPWT 140 in the wellbore 120, and can facilitate easy unwinding of the umbilical 142 from the TPWT 140 in the wellbore 120.

[0074] In a deployment operation, the umbilical 142 may be spooled onto the reel 206 of the TPWT 140, the upper end of the umbilical 142 may be attached to the tree cap 144, and the TPWT 140 may be advanced in the wellbore 120 to a deployment location in a downhole portion of the wellbore 120, with the umbilical 142 unspooled from the reel 206 as the TPWT 140 is advanced in the wellbore 120. In some embodiments, the advancement of the TPWT 140 includes a gravity-driven free fall of the TPWT 140 in the wellbore 120, followed by thrust-driven propulsion of the TPWT 140 that advances the TPWT 140 further into the wellbore 120. For example, the TPWT 140 may be released to free fall through a first / upper portion of the wellbore 120, such as a vertical portion of the wellbore 120, and upon reaching a trigger point, such as a predetermined depth in the wellbore 120, the engine 202 of the TPWT 140 may be ignited to generate thrust that propels the TPWT 140 into a second / lower portion of the wellbore 120, such as a horizontal portion of the wellbore 120. The TPWT 140 may stop in a deployed position, for example, at a downhole end of the second / lower portion of the wellbore 120. For example, the TPWT 140 may stop in a deployed position based on controlling the thrust to slow or stop the advancement of the TPWT 140 in the deployed position, or based on the TPWT 140 exhausting its fuel source.

[0075] During operation, the controller may control the operation of the TPWT 140. For example, the controller 208 may control the firing and operation of the engine 202 or other navigation elements (such as wings, rudders, or directional thrust systems) to “fly” the TPWT 140 through the wellbore 120. In some embodiments, the controller 208 may control the operation of the TPWT 140 based on commands received from the well control system 118 via the umbilical 142.

[0076] Figure 3is a diagram illustrating a TPWT tree cap 144 according to one or more embodiments. In some embodiments, the tree cap 144 includes a TPWT tree cap body ("tree cap body") 300 having a TPWT tree cap sealing flange ("tree cap sealing flange") 302 and defining a TPWT tree cap chamber ("tree cap chamber") 304, a TPWT retainer 306, and a TPWT tree cap communication port ("tree cap communication port") 308. The tree cap sealing flange 302 may provide a sealed engagement with a complementary component, such as a sealing flange of a wellhead 130. The tree cap chamber 304 may include a void sized to accommodate the TPWT 140. The tree cap communication port 308 may include a port, such as a sealed bulkhead connector, that provides for communicatively coupling the umbilical 142 of the TPWT 140 to an external communication device, such as a well control system 118. The sealing properties of the tree cap sealing flange 302 and the tree cap communication port 308 may enable the tree cap chamber 304 to accommodate high pressures, such as when the TPWT tree cap 144 is assembled to the wellhead 130 and a valve of the wellhead 130 is opened to expose the tree cap chamber 304 to the pressure of the wellbore 120. The TPWT retainer 306 may include a device suitable for retaining the TPWT 140 within the tree cap chamber 304. For example, the TPWT retainer 306 may include a pin, a door, or a valve that may be moved to a closed (or "hold") position to retain the TPWT 140 within the tree cap chamber 304 and may be moved to an open (or "release") position to release the TPWT 140 from the tree cap 144, thereby allowing the TPWT 140 to fall or otherwise exit from the tree cap chamber 304. As described above, in a deployment operation, a “loaded” TPWT 140 (having an umbilical 142 wound onto the spool 206 of the TPWT 140) may be inserted into the tree cap chamber 304, the upper end of the umbilical 142 may be coupled to the tree cap communication port 308 at the upper end of the tree cap chamber 304, the TPWT retainer 306 may be moved to a closed position to retain the TPWT 140 within the tree cap chamber 304, and the “loaded” TPWT tree cap 144 (including the TPWT retained within the tree cap chamber 304) may be deployed. 140) is assembled to the wellhead 130 so that the tree cap sealing flange 302 is sealed with the complementary sealing flange of the wellhead 130, the valve of the wellhead 130 can be opened to expose the tree cap chamber 304 to the conditions of the wellbore 120 (including the wellbore pressure), and after confirming that there is no leakage in the chamber 304 or at the tree cap sealing flange 302, the TPWT retainer 306 can be moved to the open position to release the TPWT 140 from the tree cap chamber 304, through the passage of the wellhead 130 and into the wellbore 120.Communications between the TPWT 140 and the well control system 118 may be provided via the umbilical cable 142 and the tree cap communication port 308 before, during, or after advancement of the TPWT 140 through the wellbore 120 .

[0077] Figure 4 1 is a diagram showing the deployment of a TPWT 140 according to one or more embodiments. Figure 4 In the illustrated embodiment, deploying the TPWT 140 into the wellbore 120 of the well 114 may include preparing the TPWT 140 for deployment into the wellbore 120 (as indicated by reference numeral “A”), releasing the TPWT 140 into a gravity-driven free fall in a first / upper portion of the wellbore 120 (as indicated by reference numeral “B”), igniting or otherwise activating the engine 202 of the TPWT 140 (as indicated by reference numeral “C”) in response to the TPWT 140 reaching a trigger point (indicated by trigger point 402) to generate a forward thrust that provides thrust-propelled forward propulsion of the TPWT 140 in a second / lower portion of the wellbore 120 (indicated by reference numeral “D”), such that the TPWT 140 stops at a deployed position (indicated by deployment position 404) within the wellbore 120 (indicated by reference numeral “E”).

[0078] In some embodiments, preparing to deploy the TPWT 140 into the wellbore 120 of the well 114 includes the following steps: (a) assembling the loaded TPWT 140 into the tree cap chamber 304 of the TPWT tree cap 144; (b) coupling the loaded TPWT tree cap 144 to the wellhead 130 of the well 114; and (c) pressure testing the TPWT tree cap 144 coupled to the wellhead 130. Assembling the TPWT 140 into the tree cap chamber 304 of the TPWT tree cap 144 may include inserting the loaded TPWT 140 (with the umbilical 142 wound on the reel 206 of the TPWT 140) into the tree cap chamber 304, coupling the upper end of the umbilical 142 to the tree cap communication port 308, and moving the TPWT retainer 306 to a closed position to retain the TPWT 140 within the tree cap chamber 304. Coupling the loaded TPWT tree cap 144 to the wellhead 130 of the well 114 may include assembling the loaded TPWT tree cap 144 to the wellhead 130 such that the tree cap sealing flange 302 seals with a complementary sealing flange of the wellhead 130. Pressure testing the TPWT tree cap 144 coupled to the wellhead 130 may include opening a valve 406 of the wellhead 130 to expose the tree cap chamber 304 to conditions of the wellbore 120, including the fluid pressure of the wellbore 120.

[0079] In some embodiments, releasing the TPWT 140 into a gravity-driven free fall in the first / upper portion of the wellbore 120 includes moving the TPWT retainer 306 to an open position to release the TPWT 140 from the tree cap chamber 304 such that the TPWT 140 falls through the passageway of the wellhead 130 and into the wellbore 120. During the initial advancement of the TPWT 140 in the wellbore 120, including during the duration of the gravity-driven free fall in the first / upper portion of the wellbore 120, the engine 202 of the TPWT 140 may not be activated.

[0080] In some embodiments, the trigger point is defined by a predetermined depth within the wellbore 120. For example, the trigger point may be a depth of 1000 meters (m). The trigger point may be specified in the TPWT parameters 134. In such an embodiment, in response to determining that the TPWT 140 is located at a depth of approximately 1000 m or greater, it may be determined that the TPWT 140 has reached the trigger point. The depth of the TPWT 140 may be determined, for example, by sensing the passage of a fixed position within the wellbore 120. This may include a casing collar locator of the TPWT 140 that senses the casing collar 128 as the TPWT 140 passes over the casing collar 128 during advancement down the wellbore 120. In some embodiments, the depth of the TPWT 140 is determined based on the length of time that the TPWT 140 is in free fall. For example, if the trigger point corresponds to a depth of approximately 1000 m, and it is determined that the TPWT 140 will reach a depth of approximately 1000 m after free falling for 30 seconds, it may be determined that the trigger point of 1000 m is reached when the TPWT 140 has been free falling for approximately 30 seconds.

[0081] In some embodiments, the trigger point is defined by a predetermined position within the wellbore 120. For example, the trigger point may be a position where the wellbore transitions from a vertical orientation (e.g., the wellbore 120 has a longitudinal axis oriented at approximately 0° relative to the vertical) to a horizontal orientation (e.g., the wellbore 120 has a longitudinal axis oriented at approximately 45° or greater relative to the vertical). In such an embodiment, in response to determining that the TPWT 140 is oriented at approximately 45° or greater relative to the vertical, it may be determined that the TPWT 140 has reached the trigger point. The orientation of the TPWT 140 may be determined, for example, by means of a gyroscopic sensor of the TPWT 140 for sensing the orientation of the TPWT 140.

[0082] In some embodiments, propulsive advancement of the TPWT 140 in the second / lower portion of the wellbore 120 includes operating a navigational element, such as a wing, rudder, or directional thrust system, to “fly” the TPWT 140 through the wellbore 120. For example, where the deployment location 404 is located in the main bore 122 of the wellbore 120, a navigational element, such as a wing, rudder, or directional thrust system, may be controlled to guide the TPWT 140 along the main bore 122 to the deployment location 404. As another example, where the deployment location 404 is located in a side bore 124 of the wellbore 120, a navigational element, such as a wing, rudder, or directional thrust system, may be controlled to guide the TPWT 140 along the main bore 122 and into the side bore 124 to the deployment location 404. In some embodiments, the TPWT may “fly” through the wellbore 120 along a predetermined route specified in the TPWT parameters 134.

[0083] As described above, the engine 202 of the TPWT 140 may generate thrust due to the consumption of fuel, such as solid or liquid propellant. Figure 5 is a diagram illustrating an exemplary engine 202 of the TPWT 140 according to one or more embodiments. In some embodiments, the engine 202 of the TPWT 140 includes a fuel source 502, a combustion chamber 504, an exhaust port 506, and an igniter 510. In embodiments where the fuel is a solid propellant, the fuel source 502 may include the solid propellant. In such embodiments, the igniter 510 may be positioned near, adjacent to, or in the solid propellant and may be activated to ignite the solid propellant. The resulting combustion of the solid propellant may produce hot gases (or "exhaust") that are exhausted from the exhaust port 506. In embodiments where the fuel is a liquid propellant, the fuel source 502 may include a reservoir of liquid propellant, and the engine 202 may include a fuel supply valve or pump that may regulate the flow of liquid propellant into the combustion chamber 504, which in turn may regulate the amount of liquid propellant consumed and the amount of hot gases and thrust generated.

[0084] Exhaust of exhaust gas from the exhaust port 506 may generate a forward thrust that propels the TPWT 140 forward (e.g., toward the downhole end of the wellbore 120). The igniter 510 may include an element that is activated (e.g., using power from a battery of the controller 208) to ignite the fuel, thereby causing the fuel to burn. In some embodiments, the operation of the igniter 510 is controlled by a controller (such as the TPWT controller 208). The exhaust port 506 may terminate in an exhaust nozzle 512 that directs exhaust gas to be discharged rearwardly from the TPWT 140. The exhaust nozzle 512 may include an external or integral nozzle. For example, in the illustrated embodiment, the exhaust nozzle 512 includes an integral tapered nozzle formed in the tail end 214 of the body 200 of the TPWT 140.

[0085] In some embodiments, the engine 202 of the TPWT 140 is a jet pump engine. Figure 66 is a diagram illustrating an exemplary jet pump engine 202 of the TPWT 140 according to one or more embodiments. In the illustrated embodiment, the jet pump engine 202 of the TPWT 140 includes a fuel source 602, a combustion chamber 604, an exhaust port 606, an igniter 610, an exhaust nozzle 612, a mixing chamber 614, an inlet nozzle 616, and a well fluid inlet 618. During operation, the fuel may be ignited and burned to produce hot gases that are exhausted through the inlet nozzle 616 and into the mixing chamber 614 where the hot gases mix with well fluid 620 that is routed into the mixing chamber 614 via the well fluid inlet 618. The well fluid 620 may include production fluid or other substances located in the wellbore 120 of the well 114 that are routed into the well fluid inlet 618 and the mixing chamber 614 as the TPWT 140 advances in the wellbore 120. The hot gas may be mixed with the well fluid 620 in the mixing chamber 614 and then discharged through the throat 622 of the exhaust port 606 and the exhaust nozzle 612. The addition of the well fluid 620 may increase the volume of the material discharged from the exhaust port 606, resulting in a relative increase in the thrust generated by the engine 202. The discharge of the mixture of hot gas and well fluid (or "exhaust") from the exhaust port 606 may generate a forward thrust that propels the TPWT 140 forward (e.g., toward the downhole end of the wellbore 120). The igniter 610 may include an element that is activated (e.g., using power from a battery of the controller 208) to ignite the fuel, thereby causing the fuel to burn. In some embodiments, the operation of the igniter 610 is controlled by a controller (such as the TPWT controller 208). The exhaust port 606 may terminate in an exhaust nozzle 612 that directs the exhaust gas to be discharged rearwardly from the TPWT 140. The exhaust nozzle 612 may include an external or integral nozzle. For example, in the illustrated embodiment, the exhaust nozzle 612 comprises an integral conical nozzle formed in the aft end 214 of the body 200 of the TPWT 140 .

[0086] In some embodiments, the TPWT 140 includes navigational elements, such as wings, rudders, or a directional thrust system. The navigational elements may help guide the TPWT 140 through the wellbore 120. Figure 7 FIG. 1 is a diagram illustrating exemplary navigational elements of a TPWT 140 according to one or more embodiments. In the illustrated embodiment, the TPWT 140 includes Figure 5 An engine similar to engine 202 described above may be used, but other engines may be used, such as Figure 6The TPWT 140 shown includes a stabilizer 702 (including a wing or rudder) and a directional thrust system 706 (including a directional exhaust nozzle 708 and a reverse thrust system 710). The TPWT 140 may include a combination of some or all of the navigation elements described. In the illustrated embodiment, the stabilizer 700 includes a front stabilizer 712 and a rear stabilizer 714. In some embodiments, the stabilizer 702 includes a wing or a rudder. For example, the front stabilizer 712 may include a wing and the rear stabilizer 714 may include a rudder. The wing may include a fixed stabilizer (e.g., a fixed wing element extending laterally from the body 200) that reduces the aerodynamic sideslip of the TPWT 140. The rudder may include a movable stabilizer (e.g., a rotating wing element extending laterally from the body 200) that provides for steering of the TPWT 140. In some embodiments, some of all stabilizers 702 may include a combination of wings and rudders. For example, the stabilizer 702 may include a wing portion including a fixed front wing element extending laterally from the body 200 and a rotating wing element extending from a rear end of the fixed front wing element. The wing element may be provided for stabilizing the TPWT 140, and the rudder element may be provided for steering the TPWT 140. In some embodiments, the front stabilizer 712 includes a wing, and the rear stabilizer 714 includes a rudder or wing portion.

[0087] In some embodiments, a directional thrust system 706 is provided for directing the thrust generated by the engine 202 of the TPWT 140 to help control the movement and direction of the TPWT 140. For example, a directional exhaust nozzle 708 may include a gimbal-mounted exhaust nozzle of the TPWT 140 that may be rotated to direct the direction of the thrust generated by the engine 202 of the TPWT 140. The resulting change in thrust direction may cause the TPWT 140 to turn in different directions. Thus, the direction of the directional exhaust nozzle 708 may be controlled to cause the TPWT 140 to turn in different directions. In some embodiments, the direction of the directional exhaust nozzle 708 is controlled by a controller, such as the TPWT controller 208.

[0088] As another example, the reverse thrust system 710 may include a conduit that is selectively engageable to direct thrust in a forward direction, thereby generating reverse thrust to, for example, slow or stop movement of the TPWT 140 in the forward direction. Figure 5202, except that the reverse thrust system 710 includes a forward thrust control valve 718, a reverse thrust control valve 720, a reverse thrust passage 722, and a reverse thrust port 724. The forward thrust control valve 718 may be a throttle valve operable to regulate the flow of hot gases (or "exhaust") into the exhaust port 506, and thereby regulate the amount of forward thrust generated by the engine 202. The reverse thrust control valve 720 may be a throttle valve operable to regulate the flow of hot gases (or "exhaust") through the reverse thrust passage 722 and the reverse thrust port 724, and thereby regulate the amount of reverse thrust generated by the engine 202. During reverse thrust operation, the reverse thrust control valve 720 may be at least partially opened, or the forward thrust control valve may be at least partially closed, to direct hot gases (or "exhaust gases") through the reverse thrust passage 722 and the reverse thrust port 724. Expulsion of the exhaust gases from the reverse thrust port 724 may result in a forward direction thrust impulse to generate reverse thrust, for example, to slow or stop movement of the TPWT 140 in a forward direction (e.g., toward the downhole end of the wellbore 120). In some embodiments, the reverse thrust force is of sufficient magnitude to move the TPWT 140 in a reverse direction (e.g., toward the uphole end of the wellbore 120). In some embodiments, operation of the forward thrust control valve 718 or the reverse thrust control valve 720 is controlled by a controller, such as the TPWT controller 208. A similar reverse thrust system may be incorporated into a TPWT 140 having a jet pump engine. For example, referring to Figure 6 , a similar reverse thrust passage may extend from the combustion chamber 604 or the mixing chamber 614, wherein a reverse thrust control valve regulates flow through the reverse thrust passage, and a forward thrust control valve located between the combustion chamber 604 and the mixing chamber 614 (or between the mixing chamber 614 and the exhaust port 606) regulates flow through the exhaust port 606.

[0089] In some embodiments, the TPWT 140 includes a locating system, such as a casing collar locator (“CCL”), which is operable to sense the casing collar 128 as the TPWT 140 passes over the casing collar 128 during advancement down the wellbore 120 . Figure 8is a diagram illustrating an exemplary casing collar locator ("CCL") 800 of the TPWT 140 according to one or more embodiments. In the illustrated embodiment, the CCL 800 includes two CCL coils 802a and 802b that are radially located inside a recess of the reel 206. Each of the coils 802a and 802b may include a coil of conductive metal wire (e.g., copper wire) wound into a respective circumferential recess (or "recess") 804a and 804b, which is a recess extending radially inward from the recess forming the reel 206. During use, the coils 802a and 802b may be energized to generate an electromagnet that is capable of sensing changes in a magnetic field caused by changes in the pipe thickness of a surrounding metal pipe (such as the casing 126) in the wellbore 120. As the TPWT 140 travels through the wellbore 120 and passes a location where the thickness of the surrounding metal pipe changes, such as at a casing collar 128, the coils 802a and 802b may sequentially detect corresponding changes in the magnetic field, and the changes may be attributed to the TPWT 140 being at or passing through the changed location. For example, as the TPWT 140 travels through the wellbore 120 and passes a first casing collar 128 known to be at a depth of 100 m, the coils 802a and 802b may detect a first change in the magnetic field at a first time, and may determine that the TPWT 140 is at a depth of 100 m at the first time. As the TPWT 140 continues to travel through the wellbore 120 and passes a second casing collar 128 known to be at a depth of 200 m, the coils 802a and 802b may detect a second change in the magnetic field at a second time, and may determine that the TPWT 140 is at a depth of 200 m at the second time, and so on.

[0090] In some embodiments, TPWT 140 is used to deploy acoustic sensors for DAS, such as FO lines.DAS may be used, for example, for vertical seismic profiling of wells. Fig. 9 1 is a diagram illustrating deployment of a DAS FO line into a wellbore 120 of a well 114 according to one or more embodiments. In the illustrated embodiment, the umbilical 142 includes a DAS FO line 900. When the TPWT 140 is deployed into the well 114, the DAS FO line can be unwound in the wellbore 120, resulting in the DAS FO line 900 being distributed along the length of the wellbore 120. In some embodiments, an interrogator 904 (such as a well control system 118) coupled to the DAS FO line 900 monitors seismic events sensed by the DAS FO line 900. The seismic event can be, for example, a seismic echo caused by a seismic signal generated by an array of seismic sources 906 located at the surface 112.

[0091] In some embodiments, the DAS FO line 900 forming the umbilical 142 is sized to facilitate contact between the DAS FO line 900 and a lining of the wellbore 120, such as an inner wall of the casing 126. For example, the length of the DAS FO line 900 may be approximately 125% of the length portion of the wellbore 120 routed with the DAS FO line 900. This additional length may facilitate radial expansion of the DAS FO line 900 to adhere (or "stick") to a tubular wall, such as an inner wall, of the casing 126 by means of surface tension. As a result, the DAS FO line 900 may take on a spiral or helical shape, thereby sticking to the tubular wall of the wellbore 120. The resulting coupling of the DAS FO line 900 to the tubular wall may help reduce attenuation of seismic events sensed by the DAS FO line 900.

[0092] Fig.10 1 is a diagram illustrating deployment of a U-bend DAS FO line into a plurality of wellbores according to one or more embodiments. In the illustrated embodiment, the umbilical cable 142 includes a U-bend DAS FO line 1000, which is deployed into a plurality of wellbores 120a and 120b of respective wells 114a and 114b by means of respective TPWTs 140a and 140b. The DAS FO line 1000 may include a plurality of downhole sections 1002a and 1002b, each of which is deployed into a respective wellbore 120a and 120b. The downhole sections 1002a and 1002b may each include a first DAS FO segment 1004a and a second DAS FO segment 1004b, which are connected to each other by a U-bend 1006. The U-bend 1006 may include a rigid 180° bend in the DAS FO line that provides a curved transition between the first DAS FO line segment 1004a and the second DAS FO line segment 1004b. In some embodiments, the U-bend 1006 includes a "microbend" such as that provided by AFL, headquartered in Duncan, South Carolina, USA. Fiber Optic Components (a Fiber Optic Component, provided by AFL, having headquarters in Duncan, South Carolina, USA).

[0093] During deployment operations for each of the respective wellbores 120a and 120b, the respective downhole portion 1002a or 1002b of the U-bend DAS FO line 1000 may be wound onto the reel 206 of the respective TPWT 140a or 140b, and the TPWT 140a or 140b may be deployed into the respective wellbore 120a or 120b to deploy the respective downhole portion 1002a or 1002b into the respective wellbore 120a or 120b. As shown, as a result of the deployment operation, the TPWTs 140a and 140b and the corresponding downhole portions 1002a and 1002b may be lowered into the downhole portions of the corresponding wellbores 120a and 120b, wherein each of the first DAS FO segment 1004a and the second DAS FO segment 1004b of the downhole portions 1002a and 1002b extends along the corresponding wellbores 120a and 120b to the surface 112. In some embodiments, an interrogator 1010 (such as a well control system 118) coupled to the DAS FO line 1000 monitors seismic events sensed by the corresponding downhole portions 1002a and 1002b of the DAS FO line 1000. The seismic events may be, for example, seismic echoes caused by seismic signals generated by an array of seismic sources 1012 located at the surface 112.

[0094] In some embodiments, the U-bend 1006 of the downhole section 1002 of the U-bend DAS FO line 1000 is wrapped around the reel 206 of the TPWT 140 in a manner that maintains and protects the curved shape of the U-bend 1006. Fig.11 As shown in , in some embodiments, the U-bend 1006 of the downhole section 1002 of the U-bend DAS FO line 1000 is wrapped around the periphery of the reel 206 of the TPWT 140 to maintain and protect the curved shape of the U-bend 1006. In such embodiments, loading the reel 206 may include wrapping the U-bend 1006 around the periphery of the reel 206 and then winding the downhole section 1002 of the U-bend DAS FO line 1000 around the periphery of the U-bend 1006 or the reel 206. Fig.12As shown, in some embodiments, the U-bend 1006 is fixed to the surface of the reel 206, wherein the downhole section 1002 of the U-bend DAS FO line 1000 is wrapped around the periphery of the reel 206 of the TPWT 140 to maintain and protect the curved shape of the U-bend 1006. For example, the U-bend 1006 can be "tucked into" below the wrapped portion of the downhole section 1002 of the U-bend DAS FO line 1000 to maintain and protect the curved shape of the U-bend 1006. In such an embodiment, loading of the reel 206 can include placing the U-bend 1006 against the surface of the reel 206, and then winding the downhole section 1002 of the U-bend DAS FO line 1000 around the periphery of the U-bend 1006 and the reel 206. This tuck-in configuration can be suitable for a micro-bend U-bend 1006. For example, the micro-bend U-bend 1006 may be tucked under the wrap of the downhole section 1002 of the U-bend DAS FO line 1000 to maintain and protect the curved shape of the U-bend 1006 .

[0095] Fig.13 1 is a flow chart illustrating a DAS sensing method 1300 according to one or more embodiments. The method 1300 may include deploying a DAS FO line into a wellbore using a TPWT (block 1302). In some embodiments, deploying the DAS FO line into the wellbore includes deploying the DAS FO line into one or more wellbores using one or more TPWTs. For example, deploying the DAS FO line into the wellbore using a TPWT may include deploying the DAS FO line 900 into the wellbore 120, as described at least with respect to Fig. 9 As another example, deploying a DAS FO line into a wellbore using a TPWT may include deploying a U-bend DAS FO line 1000 into wellbores 120a and 120b, as described at least with respect to Fig.10 as described.

[0096] Method 1300 may include deploying seismic sources (block 1304). In some embodiments, deploying seismic sources includes deploying one or more seismic generators operable to generate seismic signals. For example, deploying seismic sources may include positioning an array of seismic sources 906 on ground 112, such as at least about Fig. 9 As another example, deploying the seismic sources may include positioning an array of seismic sources 1012 on the ground 112, such as at least about Fig.10 as described.

[0097] The method 1300 may include activating a seismic source to generate a seismic signal (block 1306) and recording the resulting seismic signal received at the DAS FO line (block 1308). In some embodiments, activating the seismic source to generate a seismic signal includes operating the seismic source to generate a seismic signal that penetrates the formation. For example, activating the seismic source to generate a seismic signal may include an interrogator such as the well control system 118 controlling the seismic source 906 or 1012 to generate a seismic signal that penetrates the formation 104. In some embodiments, recording the resulting seismic signal received at the DAS FO line includes recording the seismic signal sensed at the DAS FO line. For example, for at least about Fig. 9 1. For example, the DAS FO line 900 described above, recording the resulting seismic signals received at the DAS FO line may include the well control system 118 recording the seismic signals sensed at discrete locations along the portion of the DAS FO line 900 located in the wellbore 120. As another example, for at least one embodiment of the present invention, the well control system 118 may record the seismic signals sensed at discrete locations along the portion of the DAS FO line 900 located in the wellbore 120. Fig.10 Depicting the DAS FO line 1000, recording the resulting seismic signals received at the DAS FO line may include the well control system 118 recording the seismic signals simultaneously sensed along the first DAS FO segment 1004a and the second DAS FO segment 1004b of the downhole portions 1002a and 1002b disposed in the wellbores 120a and 120b.

[0098] In some embodiments, various operations may be performed based on the seismic data obtained via the DAS FO line. For example, the recorded acoustic data may be used to determine characteristics of the formation 104 and the reservoir 102, which in turn may be used to determine appropriate operating parameters for the well 114 (or wells 114a and 114b), such as the recovery rate or recovery pressure of the well 114 (or wells 114a and 114b), or to determine appropriate locations and trajectories for additional wells in the formation 104. The well 114 (or wells 114a and 114b) or other wells in the formation 104 may be operated according to the determined operating parameters, or other wells may be drilled in the formation 104 at the determined locations and with the determined trajectories.

[0099] Fig.141400 according to one or more embodiments. The method 1400 may include preparing to deploy the TPWT into the wellbore (block 1402). In some embodiments, preparing to deploy the TPWT into the wellbore includes preparing to deploy the TPWT 140 into the wellbore 120 of the well 114. For example, preparing to deploy the TPWT 140 may include the well operator performing the following operations: (a) loading the reel 206 of the TPWT 140 with an umbilical 142 (e.g., a FO line, a DAS FO line, or a U-bend DAS FO line); (b) assembling the TPWT 140 into the tree cap chamber 304 of the TPWT tree cap 144; (c) coupling the "loaded" TPWT tree cap 144 to the wellhead 130 of the well 114; and (d) pressure testing the TPWT tree cap 144 coupled to the wellhead 130.

[0100] The method 1400 may include releasing the TPWT into a gravity-driven free fall in the wellbore (block 1404). In some embodiments, releasing the TPWT into a gravity-driven free fall in the wellbore includes releasing the loaded TPWT 140 into a gravity-driven free fall in the first / upper portion of the wellbore 120. For example, the well control system 118 or other well operator may control operation of the tree cap 144 to move the TPWT retainer 306 to an open position to release the TPWT 140 from the tree cap chamber 304 such that the TPWT 140 falls through the wellhead 130 and into the first / upper portion of the wellbore 120.

[0101] The method 1400 may include determining whether the TPWT has reached a trigger point (block 1406). In some embodiments, determining whether the TPWT has reached a trigger point includes monitoring the advancement of the TPWT within the wellbore 120 to determine whether the TPWT 140 has reached the trigger point. For example, a controller (such as the well control system 118 or the TPWT controller 208) may determine whether the TPWT 140 has reached the trigger point 402 based on a timed duration of the fall or navigation data indicating a speed, position, or orientation of the TPWT 140.

[0102] The method 1400 may include, in response to determining that the TPWT has reached the trigger point, performing propulsive advancement of the TPWT in the wellbore to the deployed position in the wellbore (block 1408). In some embodiments, performing propulsive advancement of the TPWT in the wellbore to the deployed position in the wellbore includes operating the engine 202 of the TPWT 140 to generate thrust to propel the TPWT 140 into the second / lower portion of the wellbore 120 such that the TPWT 140 stops at the deployed position 404 in the wellbore 120. For example, a controller (such as the well control system 118 or the TPWT controller 208) may control the firing and operation of the engine 202 and control the operation of other navigation elements (such as wings, rudders, or directional thrust systems) to "fly" the TPWT 140 through the wellbore 120 to the deployed position 404. In some embodiments, control of the TPWT 140 is provided by navigation commands initiated locally by the TPWT controller 208 or provided to the TPWT controller 208 from the well control system 118 via the umbilical 142 .

[0103] The method 1400 may include monitoring a payload of the TPWT (block 1410). In some embodiments, monitoring the payload of the TPWT includes monitoring data received from the payload 204 of the TPWT 140. For example, where the payload 204 includes a BHP sensor or a BHT sensor, a controller (such as the well control system 118) may monitor operational data including BHP data and BHT data indicating a BHP or BHT at a deployment location 404 in the wellbore 120. As another example, where the payload 204 includes a DAS FO line, a controller (such as the well control system 118) may monitor operational data including acoustic data indicating a seismic event sensed by a DAS FO line 900 or 1000 deployed in the wellbore 120.

[0104] In some embodiments, various operations may be performed based on data obtained with the aid of the payload 204 of the TPWT 140 deployed into the well 114. For example, where the payload 204 includes a BHP sensor or a BHT sensor, the corresponding BHP data and BHT data may be used to determine the BHP and BHT of the well 114, which in turn may be used to determine appropriate operating parameters for the well 114, such as the recovery rate or the recovery pressure of the well 114, and the well 114 or other wells in the formation 104 may be operated in accordance with the determined operating parameters. As another example, where the payload 204 includes a DAS FO line, the acoustic data may be used to determine characteristics of the formation 104 and the reservoir 102, which in turn may be used to determine appropriate operating parameters for the well 114, such as the recovery rate or the recovery pressure of the well 114, or to determine appropriate locations and trajectories for additional wells in the formation 104. The well 114 or other wells in the formation 104 may be operated in accordance with the determined operating parameters, or other wells may be drilled in the formation at the determined locations and with the determined trajectories.

[0105] Fig.15 2000 . In some embodiments, the system 2000 includes a memory 2004, a processor 2006, and an input / output (I / O) interface 2008. The memory 2004 may include a non-volatile memory (e.g., flash memory, read-only memory (ROM), programmable read-only memory (PROM), erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM)), a volatile memory (e.g., random access memory (RAM), static random access memory (SRAM), synchronous dynamic RAM (SDRAM)), or a mass storage memory (e.g., CD-ROM or DVD-ROM, hard disk drive). The memory 2004 may include a non-transitory computer-readable storage medium having program instructions 2010 stored therein. Program instructions 2010 may include program modules 2012 executable by a computer processor (eg, processor 2006 ) to perform described functional operations, such as those described with respect to well control system 118 , TPWT controller 208 , method 1300 , or method 1400 .

[0106] Processor 2006 may be a processor capable of executing program instructions 2010. For example, processor 2006 may include a central processing unit (CPU) that executes program instructions (e.g., program instructions of program module 2012) to perform arithmetic, logic, or input / output operations described herein. Processor 2006 may include one or more processors. I / O interface 2008 may provide an interface for communicating with one or more I / O devices 2014 (such as a joystick, a computer mouse, a keyboard, or a display screen (e.g., an electronic display for displaying a graphical user interface (GUI))). I / O device 2014 may be connected to I / O interface 2008 via a wired connection (e.g., an industrial Ethernet connection) or a wireless connection (e.g., a Wi-Fi connection). I / O interface 2008 may provide an interface for communicating with one or more external devices 2016. In some embodiments, I / O interface 2008 includes one or both of an antenna and a transceiver. In some embodiments, external device 2016 includes a sensor or other computer system.

[0107] In view of this specification, further modifications and alternative embodiments of various aspects of the disclosure of the present invention will be apparent to those skilled in the art. Therefore, this specification should be interpreted as being illustrative only, and is intended to teach those skilled in the art the general manner of implementing these embodiments. It should be understood that the forms of the embodiments shown and described herein will be considered as examples of embodiments. Elements and materials may replace those shown and described herein, parts and processes may be reversed or omitted, and certain features of the embodiments may be used independently, all of which will be apparent to those skilled in the art after having benefited from this description of the embodiments. Changes may be made to the elements described herein without departing from the spirit and scope of the embodiments described in the appended claims. The titles used herein are for organizational purposes only and are not intended to limit the scope of the specification.

[0108] It will be appreciated that the processes and methods described herein are exemplary embodiments of processes and methods that may be employed in accordance with the techniques described herein. These processes and methods may be modified to facilitate variations in their implementation and use. The processes and methods provided and the order of operations may be changed, and various elements may be added, reordered, combined, omitted, modified, etc. Portions of the processes and methods may be implemented in software, hardware, or a combination of software and hardware. Some or all of the portions of the processes and methods may be implemented by one or more of the processors / modules / applications described herein.

[0109] As used throughout this application, the word "may" is used in a permissive sense (i.e., meaning with possibility) rather than in a mandatory sense (i.e., meaning must). The words "include", "comprise" and "contain" represent including but not limited to. As used throughout this application, the singular forms "one", "an" and "the" include plural references unless the content clearly indicates otherwise. Therefore, for example, referring to "an element" may include a combination of two or more elements. As used throughout this application, the term "or" is used in a containing sense unless otherwise specified. That is, the description of an element including A or B may refer to an element including one or both of A and B. As used throughout this application, the phrase "based on" does not limit the associated operation to being based only on a specific item. Therefore, for example, the processing "based on" data A may include processing based at least in part on data A and at least in part on data B, unless the content clearly indicates otherwise. As used throughout this application, the term "from" does not limit the associated operation to being directly from, unless otherwise specified. Thus, for example, receiving an item "from" an entity may include receiving the item directly from the entity or indirectly from the entity (e.g., through an intermediate entity). Unless otherwise specifically stated, as will be apparent from the discussion, it should be understood that throughout this specification, discussions utilizing terms such as "processing," "computing," "calculating," "determining," and the like may refer to actions or processes of a specific device such as a special-purpose computer or similar special-purpose electronic processing / computing device. In the context of this specification, a special-purpose computer or similar special-purpose electronic processing / computing device is capable of manipulating or transforming signals, which are typically represented as physical, electronic, or magnetic quantities within a memory, register, or other information storage device, transmission device, or display device of the special-purpose computer or similar special-purpose electronic processing / computing device.

Claims

1. A method of deploying a distributed acoustic sensing (DAS) sensor in a subterranean well, the method comprising: releasing a torpedo for gravity-driven advancement within a first portion of a wellbore of a subterranean well, the torpedo comprising: a distributed acoustic sensing (DAS) fiber optic (FO) umbilical physically coupled to a surface member and configured to be unspooled from the torpedo as the torpedo advances in the wellbore; and an engine configured to generate thrust to propel the torpedo forward in the wellbore; determining that the torpedo has reached a trigger point within the wellbore that includes a predetermined depth; and In response to determining that the torpedo has reached the trigger point within the wellbore, activating the engine to generate forward thrust that propels the torpedo within the horizontal portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the horizontal portion of the wellbore and the torpedo stops at a deployed position within the wellbore.

2. A method for performing distributed acoustic sensing in a subterranean well, the method comprising: Advancing a torpedo into a first portion of a wellbore of a subterranean well, the torpedo comprising: a distributed acoustic sensing (DAS) fiber optic (FO) umbilical physically coupled to a surface member and configured to be unspooled from the torpedo as the torpedo advances in the wellbore; and an engine configured to generate thrust to propel the torpedo; determining that the torpedo has reached a trigger point within the wellbore that includes a predetermined depth; and In response to determining that the torpedo has reached the trigger point within the wellbore, activating the engine to generate thrust that propels the torpedo forward within a second portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the second portion of the wellbore.

3. The method according to claim 2, wherein: After the torpedo is in the deployed position, the DAS FO umbilical is extended from the surface member into the second portion of the wellbore.

4. The method according to claim 2, further comprising: After the torpedo comes to rest at the deployed position within the wellbore, seismic operations are performed, the seismic operations comprising sensing seismic events by means of the DAS FO umbilical cable unreeled in the wellbore.

5. The method of claim 4, further comprising positioning a plurality of seismic sources at surface locations, wherein the seismic operation further comprises operating the seismic sources to generate seismic signals, and wherein the seismic events correspond to the generated seismic signals.

6. The method according to claim 2, further comprising: After the torpedo stops at the deployed position within the wellbore, a fluid flow monitoring operation is performed, the fluid flow monitoring operation including sensing fluid flow by means of the DAS FO umbilical cable unreeled in the wellbore.

7. The method according to claim 2, further comprising: After the torpedo comes to rest at the deployed position within the wellbore, a leakage monitoring operation is performed, which includes sensing leakage by means of an integrated acoustic sensor of the DAS FO umbilical unreeled in the wellbore.

8. The method according to claim 2, wherein: The DAS FO umbilical comprises a single section of FO line.

9. The method according to claim 2, wherein: The DAS FO line includes a U-bend DAS FO line including a first section of the DAS FO line and a second section of the DAS FO line connected by a U-shaped bend.

10. The method according to claim 9, wherein: The torpedo includes a cylindrical spool, the method further including wrapping the U-shaped bend around a periphery of the spool, and wrapping the first segment of the DAS FO line and the second segment of the DAS FO line around the U-shaped bend wrapped around the periphery of the spool.

11. The method according to claim 9, wherein: The torpedo includes a cylindrical spool, the method further including arranging the U-shaped bend on a surface of the spool, and wrapping the first segment of the DAS FO line and the second segment of the DAS FO line around the U-shaped bend arranged on the surface of the spool.

12. The method according to claim 9, wherein: The U-shaped bend includes a micro-bend connector.

13. The method according to claim 9, wherein: Using the torpedo to place a first portion of the DAS FO umbilical including a first section of the DAS FO, a second section of the DAS FO line and the U-bend in the wellbore, the method further comprising: using a second torpedo to deploy a second portion of the DAS FO umbilical into a second wellbore, the second portion of the DAS FO umbilical including a third section of the DAS FO line and a fourth section of the DAS FO line connected by a second U-bend.

14. The method of claim 13, further comprising performing a seismic operation comprising sensing a seismic event with the first portion of the DAS FO umbilical disposed in the wellbore and the second portion of the DAS FO umbilical disposed in the second wellbore.

15. The method according to claim 2, wherein: The torpedo includes a body formed of a dissolvable material configured to dissolve in the wellbore, the method further comprising leaving the torpedo at a deployment location such that the body of the torpedo dissolves at the deployment location within the wellbore.

16. The method according to claim 2, wherein: The DAS FO umbilical is coupled to a well control system and is configured to facilitate communication between the torpedo and the well control system, the method further comprising the well control system receiving data from the torpedo via the DAS FO umbilical.

17. The method according to claim 2, wherein: The second portion of the wellbore includes a horizontal portion of the wellbore.

18. The method according to claim 2, wherein: The first portion of the wellbore includes a vertical portion of the wellbore and the second portion of the wellbore includes a horizontal portion of the wellbore, and the trigger point within the wellbore includes a transition point between the vertical portion of the wellbore and the horizontal portion of the wellbore.

19. A non-transitory computer readable storage medium, comprising program instructions stored on the readable storage medium, the program instructions being executable by a processor to cause the following operations: Advancing a torpedo into a first portion of a wellbore of a subterranean well, the torpedo comprising: a distributed acoustic sensing (DAS) fiber optic (FO) umbilical physically coupled to a surface member and configured to be unspooled from the torpedo as the torpedo advances in the wellbore; and an engine configured to generate thrust to propel the torpedo; determining that the torpedo has reached a trigger point within the wellbore that includes a predetermined depth; and In response to determining that the torpedo has reached the trigger point within the wellbore, activating the engine to generate thrust that propels the torpedo forward within a second portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the second portion of the wellbore.

20. An underground well torpedo system, the underground well torpedo system comprising: Control systems; as well as A torpedo, the torpedo comprising: a distributed acoustic sensing (DAS) fiber optic (FO) umbilical physically coupled to a surface member and configured to be unspooled from the torpedo as the torpedo advances in the wellbore; and an engine configured to generate thrust for propelling the torpedo, The control system is configured to: advancing the torpedo into a first portion of the wellbore of the subterranean well; determining that the torpedo has reached a trigger point within the wellbore that includes a predetermined depth; and In response to determining that the torpedo has reached the trigger point within the wellbore, activating the engine to generate thrust that propels the torpedo forward within a second portion of the wellbore such that at least some of the DAS FO umbilical is disposed in the second portion of the wellbore.

21. The system of claim 20, wherein: The first portion of the wellbore comprises a vertical portion of the wellbore and the second portion of the wellbore comprises a horizontal portion of the wellbore, and the trigger point within the wellbore comprises a transition point between the first wellbore portion and the second wellbore portion of the wellbore.

22. The system of claim 20, wherein: The DAS FO umbilical has a length that is at least 25% greater than a distance between the surface component and a target deployment location within the wellbore.

23. The system of claim 20, wherein: After the torpedo is in the deployed position, the DAS FO umbilical is extended from the surface member into the second portion of the wellbore.

24. The system of claim 20, wherein: The control system is further configured to perform seismic operations after the torpedo stops at the deployed position within the wellbore, the seismic operations comprising sensing seismic events via the DAS FO umbilical cable unspooled in the wellbore.

25. The system of claim 24, wherein: A plurality of seismic sources are positioned at surface locations, and wherein the seismic operations further include operating the seismic sources to generate seismic signals, and wherein the seismic events correspond to the generated seismic signals.

26. The underground well torpedo system of claim 20, wherein: The control system is further configured to perform a fluid flow monitoring operation after the torpedo stops at the deployed position within the wellbore, the fluid flow monitoring operation comprising sensing fluid flow via the DAS FO umbilical cable unspooled in the wellbore.

27. The underground well torpedo system of claim 20, wherein: The control system is further configured to, after the torpedo stops at the deployed position within the wellbore, perform a leakage monitoring operation including sensing a leakage via the DAS FO umbilical cable unreeled in the wellbore.

28. The underground well torpedo system of claim 20, wherein: The DAS FO umbilical consists of a single section of FO line.

29. The underground well torpedo system of claim 20, wherein: The DAS FO line includes a U-bend type DAS FO line including a first section of the DAS FO line and a second section of the DAS FO line connected by a U-shaped bend.

30. The system of claim 29, wherein: The torpedo includes a cylindrical spool, and wherein the U-shaped bend is wrapped around a periphery of the spool, and wherein the first section of the DAS FO line and the second section of the DAS FO line are wrapped around the U-shaped bend wrapped around the periphery of the spool.

31. The underground well torpedo system of claim 29, wherein: The torpedo comprises a cylindrical reel, and wherein the U-shaped bend is arranged on a surface of the reel, and the first section of the DAS FO line and the second section of the DAS FO line are wrapped around the U-shaped bend arranged on the surface of the reel.

32. The underground well torpedo system of claim 29, wherein: The U-shaped bend includes a micro-bend connector.

33. The system of claim 29, wherein: The first portion of the DAS FO umbilical cable includes the first section of the DAS FO, the second section of the DAS FO line, and the U-bend, the first section of the DAS FO line is arranged in the wellbore using the torpedo, and the second portion of the DAS FO umbilical cable is arranged in a second wellbore, the second portion of the DAS FO umbilical cable includes the third section of the DAS FO line and the fourth section of the DAS FO line connected by a second U-bend.

34. The system of claim 33, wherein: The control system is further configured to perform seismic operations including sensing seismic events by means of the first portion of the DAS FO umbilical disposed in the wellbore and the second portion of the DAS FO umbilical disposed in the second wellbore.

35. The system of claim 20, wherein: The torpedo includes a body formed of a dissolvable material configured to dissolve in the wellbore.

36. The underground well torpedo system of claim 20, wherein: The DAS FO umbilical is coupled to a well control system and is configured to facilitate communications between the torpedo and the well control system.

37. The system of claim 20, wherein: The second portion of the wellbore includes a horizontal portion of the wellbore.

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