RU2809112C1 - System, device and method for communication transmission inside drilling well - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: invention is related to providing communications inside a borehole. The system contains a set of lower pipe segments configured to connect to downhole tools, a lower distal end of a fibre optic cable configured to use a submersible connection for connection to downhole tools, a set of upper pipe segments configured to mechanically connect a set of lower pipe segments and surface equipment wherein the set of upper pipe segments comprises at least one upper pipe segment, an upper distal end of the fibre optic cable located uphole from the lower distal end, configured to use an uphole connector for communication with the pipeline cable the first top pipe segment in a set of pipe top segments. The fibre optic cable is located after the downhole tools are located below the surface and is connected to communicate with the downhole tools. Each top pipe segment in the set of top segments includes a corresponding conduit cable communicatively connected to adjacent conduit cables, and wherein the assembly containing each conduit cable provides a communicable connection between the fibre optic cable and the ground equipment.

EFFECT: efficiency of communication increases by reducing the number of connectors and reducing the attenuation of the transmitted signal.

15 cl, 8 dwg

Description

TECHNICAL FIELD

[001] This application relates generally to downhole communications and, more specifically, to the use of fiber optic cable for downhole communications.

BACKGROUND OF THE ART

[002] Downhole operations require two-way communication between downhole tools and surface or near-surface equipment. Conventional communication implementations can reach transmission rates of hundreds of bits per second (bps), such as in hydraulic pulse technology, or tens of thousands of bps, such as in wired drill pipe technology. Fiber optic systems can provide significantly higher transmission speeds of 1 gigabit per second or higher. As the number of pipe segments inserted into the well increases, the number of fiber optic connectors increases proportionally. Each fiber optic connector can attenuate the optical signal, reducing the effective transmission speed. A system that can reduce this optical signal attenuation would be useful.

The solution known from the prior art is US 9109439 B2, which is the closest analogue, which proposes a hybrid telemetry system for transmitting signals between a surface control unit and a downhole tool. The downhole tool is deployed using a drill string in the wellbore, penetrating into the underground formation. The hybrid telemetry system includes an uplink connector, a downhole connector, and a cable that functionally connects the uplink and downhole connectors. The top connector is operatively connected to the drill string telemetry system for communication with it. The downhole connector is operatively connected to the downhole tool for communication with it.

However, in this solution, the conduit cable is not attached to each of the corresponding pipe segments in the set of pipe segments, and the conduit cable does not communicateably connect the fiber optic cable and the ground equipment, which would reduce the number of connectors used in the system, thereby reducing the attenuation of the transmitted signal, as proposed in this decision.

Also known is the solution WO 2019/112790 in which a variable frequency light source is configured to emit a light beam and modulate the frequency of the light beam. A fiber optic cable is connected to a variable frequency light source. The fiber optic cable is configured to receive a light beam at the input and pass the light beam to the output. Several optical detectors are attached to the fiber optic cable. Each of the optical detectors is configured to detect light of a specific frequency that is scattered back through the fiber optic cable. The actuator is attached to the fiber optic cable. The actuator is configured to deform the fiber optic cable in response to impact.

However, in this solution, the conduit cable is not attached to each of the corresponding pipe segments in the set of pipe segments, and the conduit cable does not communicateably connect the fiber optic cable and the ground equipment, which would reduce the number of connectors used in the system, thereby reducing the attenuation of the transmitted signal, as proposed in this decision.

Also known is the solution US 7740064 B2 in which a downhole submersible pump device uses fiber optic sensors and distributed temperature sensors under the submersible pump to monitor pump discharge pressure and temperature, inlet pressure and temperature, and motor temperature. In addition, distributed temperature sensors are used under the pump to monitor holes in the wellbore.

However, in this solution, the conduit cable is not attached to each of the corresponding pipe segments in the set of pipe segments, and the conduit cable does not communicateably connect the fiber optic cable and the ground equipment, which would reduce the number of connectors used in the system, thereby reducing the attenuation of the transmitted signal, as proposed in this decision.

BRIEF DESCRIPTION OF GRAPHIC MATERIALS

[003] Reference is made to the following description, taken in conjunction with the accompanying drawings, wherein:

[004] in FIG. 1 is a schematic illustration of an exemplary downhole system using a fiber optic communication system;

[005] in FIG. 2 is an illustration of a diagram of an example communication system in a downhole hydraulic fracturing (HF) system;

[006] in FIG. 3 is a schematic illustration of an exemplary communication system in an offshore well system;

[007] in FIG. 4 is a schematic illustration of an exemplary device with a long length of fiber optic cable connected at a surface location;

[008] in FIG. 5 is a schematic illustration of an exemplary device with a long length of fiber optic cable connected at a location below sea level;

[009] in FIG. 6 is a schematic illustration of an exemplary downhole telemetry system, including electrical connections;

[0010] in FIG. 7 is an illustration of a block diagram of an exemplary fiber optic telemetry system (FOTS) with a light source located at optional points within the system; And

[0011] in FIG. 8 is a block diagram illustration of an exemplary method for implementing FOTS.

DETAILED DESCRIPTION OF THE INVENTION

[0012] When working with boreholes, i.e., wellbores, for example, in the hydrocarbon production industry, there is a need for communication up the wellbore and down the wellbore. Downhole tools inside the wellbore and wellbore controllers at or near the surface must be able to easily and quickly transmit data, telemetry, commands and other information. Various solutions such as fluid pulse technology are commonly used, although with a general transmission rate limitation of approximately 120 bits per second (bps). This data transfer rate includes conventional data compression techniques. Electromagnetic and acoustic transmission methods also have disadvantages in their respective communication systems. Wired drill pipes can achieve significantly higher speeds of 56,000 bps at additional cost and with less reliability.

[0013] A fiber optic cable system can achieve higher transmission speeds, for example up to approximately 40 gigabit/s (Gbps) over several hundred kilometers and 10 Gbit/s over several thousand kilometers, with actual transmission rates depending on the technology used and also on the conditions under which transmission occurs. Single-mode fiber optic cable can have a core diameter of 8.0 micrometers (µm) to 10.5 µm and a cladding diameter of 125 µm. There may be types of single-mode fiber optic cable that have been chemically or physically altered to create properties, such as dispersion-biased fiber and non-zero-dispersion dispersion-biased fiber. Data rates can be reduced by polarization mode dispersion and chromatic dispersion. With the help of optical amplifiers and dispersion compensation devices, optical systems can increase effective communication ranges to thousands of kilometers.

[0014] Optical signals may be attenuated when the signals pass through a fiber optic connector, such as fiber optic connectors connecting fiber optic cables at each joint along the length of the drill pipe. Signal loss in a fiber optic cable can be measured in decibels (dB). A three dB loss in a link means that the transmit signal at the far end is half the intensity of the transmit signal that was sent over the fiber optic cable. A loss of six dB means that a quarter of the transmission signal passes through the fiber optic connector. If too much of the transmission signal is lost, the signal may be too weak to recover and communications may become unreliable and may eventually stop functioning. Transmitter power and receiver sensitivity can affect how much signal loss can be absorbed by the communication system.

[0015] Multimode index fibers can, under some circumstances, have an attenuation (signal loss) of three dB per kilometer (km) at a wavelength of 850 nanometers (nm) and one dB/km at a wavelength of 1300 nm. Single-mode losses can be, for example, 0.35 dB/km at 1310 nm and 0.25 dB/km at 1550 nm. Very high quality single mode fiber intended for long distance applications may have lower signal loss, such as 0.19 dB/km at 1550 nm. Plastic optical fiber (POF) can have high loss, such as 1.0 dB/m at 650 nm. Each fiber optic cable connector can add approximately 0.6 dB of average signal loss, and each splice can add approximately 0.1 dB of signal loss. For each connector, a loss of 0.3 dB for most adhesive/polish or weld-on connectors can be used to evaluate communication system performance. The loss specification for pre-polished/mechanical butt connectors or multi-fiber connectors may be higher. Attenuation, such as loss of strength or power, of an optical transmission signal can significantly reduce the perceived bits/s of a communication system.

[0016] This invention provides a fiber optic communication system in which a long length of fiber optic cable (such as a conventional fiber optic cable, a reinforced fiber optic cable, a supported fiber optic cable, or an armored fiber optic cable) can be lowered below a surface point, such as deep into a wellbore, and connected to downhole tools using, for example, a submersible connection such as a wet connector. Fiber optic cable can be tens of thousands of feet long, although different lengths can be used. This long length of fiber optic cable can support high transmission speeds while minimizing the number of fiber optic cable connectors used in the system. Reducing the number of fiber optic cable connectors used can reduce the experienced attenuation of the optical transmission signal.

[0017] A long length of fiber optic cable may be located within or partially within one or more pipe segments positioned, lowered or positioned within the wellbore. These pipe segments are the lower pipe segments, and the fiber optic cable can be attached, disconnected, or both with respect to the lower pipe segments. In aspects of the present invention in which the lower pipe segments rotate, a long length of fiber optic cable that is located in the internal diameter (ID) of the lower pipe segments is free to rotate with the lower pipe segments, eliminating inertial effects.

[0018] The uphole end of the fiber optic cable may be connected to the first upper pipe segment using an uphole connector. Additional top pipe segments may be connected to the first top pipe segment to increase the overall length of pipe connected to the surface equipment. The surface equipment may be, for example, a derrick, a drilling system, a computer system, a well site controller, an electrical system, a power supply, or a combination thereof. Each upper pipe segment also includes a communications connector and a cable/wire, such as a fiber optic connector and a fiber optic cable, or an electrical connector and an electrical cable or wire, providing a long-length fiber optic cable communication capability to ground equipment. In some aspects, the first upper pipe segment may comprise a wireless communications system communicatively coupled to a ground transceiver. In this aspect, the upper pipe segments do not necessarily need to have fiber optic cable, electrical cable or wire. Additionally, this invention does not require that the pipe segments be connected using inductive coupling technology, such as that used in wired drill pipe solutions. As used herein, the term “connection” may include one or more of a communication connection, a power transmission connection, and a mechanical connection.

[0019] As used herein, “communication” may be one-way or bi-directional. Communication may be, without limitation, one or more of data transmission, amplitude changes, or frequency changes. Communication can use optical signals, electromagnetic signals, and other forms of energy transmission such as thermal energy, radiated energy, chemical energy, nuclear energy, electrical energy, motion energy, sound energy, elastic energy, or gravitational energy. In some aspects, the communication used in this document is not limited to the transfer of information; communication may involve the transfer of one or more types of energy to perform work (for example, adjusting a valve, activating a motor, supplying power to another system, or other types of work) or to effect a change of state (for example, a binary switch or variable, position indicator, programmed variable, conditional variable, or other types of state changes).

[0020] Using long lengths of fiber optic cable in the lower segments of the pipe results in fewer connectors along that length. Reducing the number of connectors over this length may result in reduced impact on transmit signal strength due to higher hydrostatic pressure (which could be, for example, 20,000 pounds per square inch (psi) at 30,000 ft depth) and higher wellbore temperatures at greater wellbore depths. Connectors can be more sensitive to environmental factors than the fiber optic cable itself. A fiber optic cable may carry more than one transmission signal, and there may be more than one fiber optic cable, or the cable may contain more than one strand. Connectors (fiber optic or electrical) used with upper pipe segments can be subjected to lower hydrostatic pressures such as 2000 psi. inch at a depth of 3000 feet, as well as lower wellbore temperatures, with lower pressure and temperature having less impact on the transmission signal.

[0021] Depending on the type of pipe tops used, the conduit cable attached to each pipe top, typically attached to the outside diameter (OD) of the pipe segment, may move or rotate as the pipe top moves or rotates. The conduit cable may be a fiber optic cable, an electrical cable, or an electrical wire. In aspects in which the lower and upper pipe segments are drill pipe segments, the connected pipe segments can be rotated to provide rotation of the bottom hole assembly (BHA). Rotation may cause the cable attached to the pipe to contact or rub against the wellbore, casing, riser, or other wellbore components. The piping cable may fail due to this wear and tear. To protect the pipeline cable, a protective device, such as a cage, can be applied to the upper segments of the pipe. Various holding devices may be used to hold the protective equipment in place and provide protection in some aspects. Casing couplings, mechanical stop couplings, pipe clamps (e.g., friction clamp with set screws, spiral pin clamp, toothed clamp, or pinch clamp), and various types of centralizers may be used as protective or retaining devices.

[0022] Running cable or wire from the outside of the drill pipe can increase costs and potential hazards, especially in situations where the clearance between the drill string, such as drill pipe, and the casing (or wellbore) is minimal. In this invention, the gap between the drill string and the riser can be significant. In an exemplary embodiment, the riser may have an OD of 19-1/2 inches and an ID of approximately 18 inches.

[0023] Drill pipe used in deepwater wells may typically have a diameter of 6-5/8 inches (OD 6-5/8 inches and tool joint OD, eg joint, 8-1/2 inches). The radial clearance between tool joint OD and riser ID can be approximately (18" - 8-1/2") / 2=9-1/2" / 2=4.75". These component parameters allow the release of a centralizer or other type of device to protect the pipeline cable. Preferably, the conduit cable may be pre-installed on the drill pipe segments to reduce the time required to secure these components to the well site. Likewise, assembling three segments of drill pipe into a drill pipe stand and arranging the stand stands on the derrick will improve the efficiency of the operation. Then, when it comes time to trip-in-hole and start drilling, one connection can be made every 90 feet instead of three connections when using single drill pipe joints.

[0024] Tubing cable protectors and tubing cable segments can be installed on the next stand while drilling using the previous section of the stand. For example, when drilling from 12,997 ft to 19,500 ft, wellsite operators can assemble 3-30 ft joints of drill pipe to produce a 90 ft stand. They bring it back to the rig while drilling continues. Since the next section of the wellbore may be 4,457 feet long, they will have to space 51 drill pipe stands. During the assembly of 3-30 ft joints, users can install pipeline cable protectors and pipeline cable segments without interrupting drilling operations. The conduit cable segments may be 90 feet long, such as the length of a candle, or 30 feet long, such as three for each candle. It is also possible to install a pipeline cable of a different length. By installing conduit cable to the length of the drill pipe stand, the number of connectors used can be reduced compared to using conduit cable to the length of each segment of drill pipe - in this example, the number of connectors may be reduced by two thirds.

[0025] Two pipeline cable protectors can be installed on each plug. In some aspects, two or more pipe clamps or other fastening devices may be added to secure the line to the drill pipe connection. In some aspects, two pipe clamps may be used per joint. The ends of each conduit cable may be secured so that the ends (1) remain protected during the installation and stand-up procedure, (2) can be secured to the drill pipe when stand-off is set, (3) do not interfere with the use of normal drilling equipment such as iron drillers' aids , lifting devices and wedge grips during TIH, (4) could be attached relatively quickly during TIH, and to (5) provide a clean connection with connectivity when attached.

[0026] The light source for generating the optical signal may be located in the wellbore in close proximity to the wet joint downhole connector, uphole from where the long length of fiber optic cable (or multiple cables) connects to the first upper pipe segment , in another part of the upper pipe segments, or at a surface location. The light source may be one or more of a laser (including a laser emitting diode), a light emitting diode (LED), a high power LED, and other conventional light sources used to create or modulate an optical signal over a fiber optic cable. In some aspects, the light source may be replaced by another energy source using wavelengths in the electromagnetic spectrum that are longer or shorter than the visible spectrum.

[0027] In aspects in which the light source is located in close proximity to the wet mating connector and downhole tools, the light source may be powered by a power source located within the downhole tools, such as one or more batteries, capacitors, generators and other energy sources. In some aspects, the light source may be powered by a separate electrical cable or wire that is installed parallel to a long length of fiber optic cable, wherein the uphole end of the electrical cable or wire is electrically connected to the surface equipment, such as by connectors and cable segments or wires on each upper pipe segment. In some aspects, the top-of-pipe conduit cables may be electrical wires or cables and may be used to deliver electrical energy downhole and be used to interconnect long lengths of fiber optic cable to surface equipment.

[0028] Downhole tools can communicate with a light source to send messages, such as telemetry data, over long lengths of fiber optic cable and electrical wires or cables to surface equipment. The downhole end of the long fiber optic cable may also be interfaced with electro-optical devices that can convert the optical signal to an electrical signal and vice versa, as well as circuitry or software to perform signal processing, data processing, such as compression and modulation algorithms . The resulting electrical signal can enable downhole tools to receive data and commands from surface equipment.

[0029] In aspects in which the light source is located in close proximity to the first upper tube segment, a light source sensing element, reflector, receiver, transceiver, demodulator, modulator, amplifier, converter, or energy device may be used in close proximity to the lower one. along the borehole of a wet joint connector to provide reception, modulation, conversion or demodulation of an optical signal, thereby providing a mechanism for downhole tools to receive and transmit data, information and commands when interacting with surface equipment. In this aspect, the light source can avoid higher hydrostatic pressures and temperatures in the well, as well as avoid the effects of vibration from the use of downhole tools, such as vibrations from a BHA. The light source may be powered by ground equipment or a power source located in close proximity to the light source. In some aspects, the light source may be a second light source. In some aspects, the light source may include transceiver capabilities, for example, for transmitting and receiving light signals. In other aspects, reception and transmission may be performed by separate devices, and the devices may be shared, partially shared, partially functionally shared, partially physically shared, or a combination of the above.

[0030] In some aspects, the light source may be located in close proximity to ground equipment. In this aspect, the upper pipe segments include attached sections of fiber optic cable, wherein the fiber optic cable attached to the first upper pipe segment is connected to a long length of fiber optic cable. The light source sensing element and reflective device can be used in close proximity to a downhole connector being mated in wet conditions to provide modulation of the optical signal, thereby providing a mechanism for downhole tools to receive and transmit data, information and commands when interacting with surface equipment. The light source may be powered by ground equipment or a power source located in close proximity to the light source. In one or more of the above-described aspects, more than one light source may be used, for example, one light source located in close proximity to the BHA and one light source located in close proximity to the first top pipe segment, or one light source located in close proximity from ground equipment.

[0031] This invention can be used in a variety of applications such as hydrocarbon and non-hydrocarbon production drilling systems, drill string testing, formation testing, and hydrocarbon production systems such as completion systems, workovers, evaluation systems, production systems, hydraulic fracturing systems formation (hydraulic fracturing), onshore and offshore systems, as well as intelligent completion systems. Higher received signal bandwidth and assured transmission speed can facilitate the use of tools and systems such as seismic while drilling (SWD) tools, data acquisition tools, drilling tools, logging while drilling tools, tools for measurement while drilling, valves, actuators and wireline tools. In addition, alternative communication systems may be replaced by the described fiber optic cable system, for example, to replace wireless communication systems.

[0032] Referring now to the figures, FIG. 1 is a schematic illustration of an exemplary downhole system 100 using a fiber optic communication system, such as a drilling system, a logging while drilling (LWD) system, a measurement while drilling (MWD) system, an SWD system, a telemetry while drilling system, an extraction system. , formation evaluation system, fluid evaluation system, production system, wireline pump system and other downhole systems for hydrocarbon production. The well system 100 includes a drilling rig 105, a well pad controller 107, and a computing system 108. The well pad controller 107 includes a processor and a memory device and is configured to control the operation of the well system 100. The drilling rig 105 is located on surface 106.

[0033] Underneath the derrick 105 extends a wellbore 110 with a set of upper pipe segments 112 and a set of lower pipe segments 115 located within the diameter of the wellbore 110. At the bottom of the set of lower pipe segments 115 are located the downhole tools 120. The downhole tools 120 may include various downhole tools and BHAs, such as a drill bit 122. Other components of the downhole tools 120 may be present, such as a local power source (e.g., a generator) , batteries, capacitors, telemetry systems, sensors, transceivers and control system. The wellbore 110 is surrounded by a subterranean formation 150.

[0034] A long length of fiber optic cable 130 (shown as a solid line) is inserted into the set of lower pipe segments 115. Long length fiber optic cable 130 is connected to downhole tools 120 using a wet splice connector. The uphole end of a long length of fiber optic cable 130 is connected to the lowest, eg first, top pipe segment in a set of top pipe segments 112. A protected conduit cable 132 (shown in dotted line) is attached to the outside of a set of top pipe segments 112. Protected conduit 132 extends to the derrick 105 and connects to one or more electrical cables 134 (shown in dotted line) connecting to the rig controller 107. Protected conduit 132 may be protected from wear while rotating adjacent a riser, casing, or drill pipe by being secured to a suitable upper pipe segment by a centralizer, pipe clamp, cage, other protective means, or various combinations thereof. Protected conduit 132 may be one or more cables and wires (such as fiber optic cables, electrical cables, electrical wires, or a combination thereof) and have varying lengths, such as 30-foot lengths for drill pipe segments or 90-foot lengths for drill strings. pipes

[0035] In some aspects, electrical cables 134 may be replaced by a wireless communication system with a transceiver. In some aspects, a type of slip ring connector may be used in the coupling between the protected conduit 132 and the wellsite controller 107. In some aspects, the protected conduit 132 may terminate before the connection to the equipment on the rig 105 and the electrical connection, and an electrical connection, a fiber optic connection, or a wireless connection may be used to connect the protected conduit 132 and the wellsite controller 107.

[0036] Wellsite controller 107 or computing system 108 may be communicatively coupled to wellsite controller 107 or secure conduit 132, or may be used to communicate with downhole tools 120, such as to send and receive telemetry, data, commands and other information. The computing system 108 may be located in close proximity to or some distance from the well site controller 107, such as in a cloud environment, data center, laboratory, or corporate office. The computing system 108 may be a laptop, a smartphone, a PDA, a server, a desktop computer, a cloud computing system, other computing systems, or a combination thereof that is configured to perform the process and methods described herein. Wellsite operators, engineers, and other personnel may send and receive telemetry, data, commands, and other information through various conventional means using the computer system 108 or the wellsite controller 107 .

[0037] In FIG. 2 is an illustration of a diagram of an exemplary communication system in a downhole fracturing system 200, which may be a well site at which fracturing activities are being carried out by implementing a fracturing treatment plan. The 200 well fracturing system demonstrates a nearly horizontal wellbore undergoing hydraulic fracturing.

[0038] The downhole fracturing system 200 includes surface well equipment 205 located on the surface 206, wellsite control equipment 207, a fiber optic light source 215 located below the surface 206, and a computer system 208. In some aspects, the wellsite control equipment 207 is coupled to a communication with a separate computing system 208, such as a server, data center, cloud service, tablet, laptop, smartphone, or other types of computing systems. The computing system 208 may be located in close proximity to the wellsite control equipment 207 or located remotely from the wellsite control equipment 207 and can be used by the engineer and downhole system operator to receive and transmit telemetry, data, commands, and other information.

[0039] Below the surface 206, a wellbore 210 extends from the surface well equipment 205. The wellbore 210 may have zero or more cased sections and a lower section that is cased or uncased. A fluid pipe 220 is inserted into the wellbore 210. The lower portion of the fluid pipe 220 is configured to release well material 230, such as a carrier fluid with whipstock material, from the fluid pipe 220 into subterranean formations 235 containing hydraulic fractures 240. The release of downhole material 230 may be accomplished by sliding sleeves, valves, perforations in fluid pipe 220, or other release means. At the end of the fluid pipe 220 is the end of a pipe assembly 225, which may contain one or more downhole tools or an end plug assembly. In some aspects in which a fiber optic light source 215 is not present, the end of the pipe assembly 225 may include a downhole light source 227 to provide generation and modulation of a transmission signal to generate communication between the end of the pipe assembly 225 and the wellsite control equipment 207 and the computing system 208.

[0040] The top tube segments 212 of the fluid pipe 220 include a fiber optic cable connection at each top tube segment joint or at each tube candle top segment joint. In addition, the fiber optic light source 215 is located in the borehole at the connecting joint of the top pipe segments 212, such as the first top pipe segment. The topsides fiber optic cable 212 is connected to the surface fiber optic cable 254 (shown in dotted line), which in turn is connected to the wellsite control equipment 207 and the computing system 208. Similar to the downhole system 100, in some aspects, the topsides 212 You can use electrical cables or wires instead of fiber optic cables. In some aspects, fiber optic cables attached to the top pipe segments 212 or electrical cables attached to the top pipe segments 212 may be communicatively coupled to the wellsite control equipment 207 using a slip ring connector or wireless transceiver system.

[0041] A long length of fiber optic cable 250 is located in the lower pipe segments 214 of said fluid pipe 220 and is connected to the fiber optic cable of the upper pipe segments 212 and the end of the pipe assembly 225. In other aspects, long-length fiber optic cable 250 may be located outside the lower pipe segments 214. In some aspects, when a downhole light source 227 is present, a long length of fiber optic cable 250 is connected to the downhole light source 227. The end tools of the pipe assembly 225 and the wellsite control equipment 207 may use one or more of a fiber optic light source 215 and a downhole light source 227 along with receiver or transceiver functionality or devices to provide communication with the other end of the tube assembly 225 or the wellsite control equipment 207 platform. Additionally, the long length fiber optic cable 250 can be used as a sensor, such as a distributed acoustic sensor, along its entire length. In some aspects, the end of the pipe assembly 225 may be located at various depths within the wellbore 210 in addition to the location of the end of the pipe.

[0042] In FIG. 3 is a diagrammatic illustration of an exemplary communication system in an offshore well system 300, where an electric submersible pump (ESP) assembly 320 is located downhole in a wellbore 310 below a body of water 340, such as an ocean or sea. The wellbore 310, protected by casing, well screens, or other structures, is surrounded by a subterranean formation 345. The ESP assembly 320 can also be used for onshore operations. ESP assembly 320 includes a well controller 307 (eg, to act as a speed controller and communications controller for ESP assembly 320), an ESP motor 314, and an ESP pump 324.

[0043] The well controller 307 is located in a cabinet 306 within a control room 304 on an offshore platform 305, such as an oil rig. The well controller 307 is configured to regulate the operation of the ESP motor 314 to increase the productivity of the well. In the illustrated aspect, ESP motor 314 is a two-pole, three-phase squirrel cage induction motor that drives ESP pump 324. The ESP motor 314 is located near the bottom of the ESP assembly 320, directly above the downhole sensors within the wellbore 310. Power cable 330 extends from well controller 307 to ESP motor 314 .

[0044] In some aspects, the ESP pump 324 may be a horizontal surface pump, a progressive cavity pump, an underground compressor system, or an electric submersible cavity pump. The engine seal section and the inlet section may extend between the ESP motor 314 and the ESP pump 324. A riser 315 separates the ESP assembly 320 from the water body 340, and a casing 316 may separate the wellbore 310 from the subterranean formation 345. Perforations in the casing 316 may allow fluid of interest to flow from the subterranean formation 345 into the wellbore 310.

[0045] Running parallel to the power cable 330 is a long length fiber optic cable 350 and a high pipe fiber optic cable 352 (in this figure, the power cable 330, long length fiber optic cable 350 and high pipe fiber optic cable 352 are shown as a thick line representing both the power cable 330 and corresponding long-length fiber optic cable 350 and top-of-pipe fiber optic cable 352, and in other aspects may be located outside the ESP pipes). The fiber optic light source may be located in the well, such as in close proximity to the ESP motor 314 located within the riser 315 on the subterranean surface 342 or on the water surface 344, on the offshore platform 305, or at other depths within the wellbore 310. Power cable 330 may supply power to the downhole fiber optic light source.

[0046] In FIG. 1 and 2 show operations on land. Those skilled in the art will appreciate that the present invention is equally well suited for use in offshore operations. In FIG. 1, Fig. 2 and Fig. 3 illustrates specific wellbore configurations, those skilled in the art will appreciate that the invention is equally well suited for use in wellbores having other orientations, including vertical wellbores, horizontal wellbores, deviated wellbores, multilateral wellbores, and other types of wellbores.

[0047] In FIG. 4 is a schematic illustration of an exemplary device 400 with a long length of fiber optic cable connected at a surface location. Device 400 is shown in offshore operation. The disclosed systems can be used on land and in other operating environments. The device 400 can be used to provide high throughput communications between downhole tools and surface equipment. The device 400 includes surface equipment 405, a drill riser 410, a drill string 415 located within the drill riser 410, and a BHA 420. The BHA 420 may be various types of downhole tools, drill bits, sensors, fluid regulators, power sources, transceivers, and combinations thereof. .

[0048] The BHA 420 may further include a drilling assembly 422. A long-length fiber optic cable 450 is inserted into the drill string 415, located at the bottom of the drill string 415. The long-length fiber optic cable 450 is at least three strings long and can be tens of thousands in length. ft. The lower distal end of the long length fiber optic cable 450 is connected to the BHA 420 via a fiber optic cable connector 430 and a BHA submersible connection 432. A nearby fiber optic cable connector 430 may provide a downhole light source, if present. The downhole light source may have the functionality to be a receiver, transmitter, or transceiver. The upper distal end of the long length fiber optic cable 450 is connected uphole to surface equipment 405 via an uphole connector 435.

[0049] Surface equipment 405 is preferably located at or above sea level 460. Blowout preventers 417 are located above the seabed 462. The drilling assembly 422 is located in close proximity to the bottom 464 of the wellbore. For demonstration purposes, in this example, face 464 may be 23,000 feet below sea level 460. The seabed 462 may be 7,000 feet below sea level 460. Long length fiber optic cable 450 can extend from BHA 420 to uphole connector 435 approximately 23,000 feet. The 23,000 ft long 450 fiber optic cable can reduce the number of connectors used in the system, thus reducing the attenuation of the fiber optic signal.

[0050] For the remaining distance to ground equipment 405, upper pipe segments with fiber optic cables or electrical cables or wires can be used. Using fiber optic cable runs, one per pipe segment, may result in signal loss. Using electrical cables on the upper segments of the pipe can reduce this potential signal loss. In some applications that use fiber optic cables, fiber optic amplifiers can be used to reduce potential signal loss. Optionally, the top pipe segments may include guards such as cages, pipe clamps, centralizers and couplings to protect the fiber optic cable from rotational wear - the guards may rotate in conjunction with the set of top pipe segments.

[0051] The reduction of the connectors may vary as the drilling depth interval changes. For example, in aspects where the drilling interval is 3000 feet, such as 23,000 to 26,000 feet, the number of connectors can be reduced to a range of approximately 33 to 100 fiber connections, such as reducing potential signal loss to 20 to 60 dB (from 33 * 0.6 dB/connector to 100 * 0.6 dB/connector). In comparison, wired drill pipe would require approximately 866 inductive couplers (using conventional pipe segments) for the same length of 26,000 feet. For a drilling interval of about 2000 feet, for example from 26,000 to 28,000 feet, the number of fiber optic connectors ranges from about 22 to 66, while a wired drill pipe would use approximately 933 inductive connectors to reach a depth of 28,000 feet.

[0052] In FIG. 5 is a schematic illustration of an exemplary device 500 with a long length of fiber optic cable connected at a location below sea level. Apparatus 500 is an extension of FIG. 4 after drilling additional wellbore depth. Device 400 and device 500 also demonstrate a high speed telemetry system. Device 500 is shown in offshore operation. The disclosed systems can be used on land and in other operating environments. The device 500 can be used to provide high throughput communications between downhole tools and surface equipment. The device 500 includes surface equipment 505, a riser 510, a set of upper pipe segments 512 located within the riser ID 510, a set of lower pipe segments 514 located within the riser ID 510 (in the case of a location above the seabed 562), and a casing 511 (in the case located at or below the seabed 562).

[0053] A long length of fiber optic cable 550 is inserted into the set of lower pipe segments 514. The lower distal end of the long length fiber optic cable 550 is connected to the BHA 520 via a fiber optic cable connector 530 and a BHA submersible connection 532. In some aspects, the fiber optic cable connector 530 and the BHA submersible connection 532 may include electrical coupling connectors, such as contacts. The electrical connection contacts can be used to convert the signal carried by the long length fiber optic cable 550 into an electrical signal, to convert the electrical signal from the BHA 520 into an optical signal, or to connect an electrical cable or wire along the length of the long length fiber optic cable 550 to the BHA 520.

[0054] Various combinations of transceivers, optical converters, modulators, demodulators, multiplexers, demultiplexers, amplifiers, filters, and other devices may be used in this process to facilitate communication connectivity. In other aspects, a separate connector may be present for the electrical connection. A downhole light source, for example configured as a transceiver system, may be located in close proximity to the fiber optic cable connector 530. The upper distal end of the long length fiber optic cable 550 is connected uphole to the first top pipe segment 513 in the set of top pipe segments 512 via an uphole connector 535. In turn, each top pipe segment in the set of top pipe segments 512 is connected with an adjacent pipe segment (or pipe candle). The uppermost uppermost pipe segment is connected to the surface equipment 505. In some aspects, the uphole connector 535 may include a fiber optic light source, for example, also configured as a transceiver system, for generating and modulating optical signals. In other aspects, uphole connector 535 may be communicatively coupled to a wireless transceiver, which in turn may be coupled to surface equipment 505. Uphole connector 535 may include an electro-optical connector or an optical-optical connector. optical connector.

[0055] Surface equipment 505 is located at approximately sea level 560. Blowout preventers 517 are located above the seabed 562. The drilling assembly 522 is located in close proximity to the previous bottom hole designation 564, and in this example, the drilling assembly 522 extends the wellbore below the previous depth as indicated by the previous bottom hole designation 564. For demonstration purposes, in this example the previous face designation 564 may be 23,000 feet below sea level 560. The seabed 562 may be 7,000 feet below the 560 sea level. Long length fiber optic cable 550 can extend from BHA 520 to uphole connector 535 approximately 20,000 feet.

[0056] For the remaining 3000 feet to surface equipment 505, a set of top pipe segments 512 with conduit cables 552 may be used, for example, one for each segment of drill pipe (approximately 30 feet), one for each stand of drill pipe (approximately 90 feet ), other lengths or a combination thereof. This can reduce the number of connectors used in the system, thereby reducing transmission signal attenuation. In this example, a set of top pipe segments 512 have their respective conduit cables 552 attached to the OD of the corresponding top pipe segment. In some aspects, the conduit cables 552 may include protectors, such as cages, pipe clamps, centralizers, sealing end caps, and sleeves, to protect the conduit cables 552 from rotational wear and may rotate in conjunction with the upper segments of the pipe.

[0057] The first top pipe segment 513 may vary in design compared to the other pipe segments in the set of top pipe segments 512, for example, its length may be 10 feet and the OD may be greater than the other pipe segments. In some aspects, the first upper pipe segment 513 may contain other equipment, such as an electro-optical connector, also known as a fiber media converter (for connecting a fiber optic cable and an electrical cable or wire, and for converting light signals and electrical signals to another type of signal), source power supply, power regulator, light source such as an LED, laser, semiconductor diode laser, or other source of electromagnetic radiation. In some aspects, there may be more than one fiber optic cable, more than one electrical cable or wire, or a combination thereof, and one or more signal multiplexers and one or more signal demultiplexers may be present along with the signal processors.

[0058] In some aspects, conduit cables 552 may be one or more fiber optic cables, one or more electrical cables, one or more electrical wires, various combinations of coupled and unconnected cables, or various combinations thereof. Using an electrical wire or cable as a conduit can reduce the signal attenuation experienced since the optical transmission signal will pass through fewer connectors. In some aspects, conduit cables 552 may be replaced by one or more wireless transceiver systems. In other aspects, conduit cables 552 may use an electrical cable or wire for a portion of their length and use a wireless transceiver for the remainder of their length.

[0059] Conduit cables 552 may be similar to industrial downhole fiber optic cables, such as conventional downhole cable, hybrid downhole cable, or umbilical with fiber optic components. 552 pipeline cables may contain sealed stainless steel tube, high tensile wire, polyethylene sheath, hydrogen absorbing gel and in-line splicing technology. 552 conduit cables can use 18AWG insulated copper conductor, free-tube design for optical fibers, and materials that provide protection from harsh chemical environments containing _H2S , _CO2 , methane, petroleum, diesel, gasoline, toluene, and other organic solvents. 552 conduit cables can have a wide operating temperature range from -40.0°C to 150.0°C and use materials with high abrasion and impact resistance.

[0060] In FIG. 6 is a schematic illustration of an exemplary downhole telemetry system 600, including electrical connections. Downhole telemetry system 600 demonstrates the use of electrical connections to downhole tools to provide communication with downhole tools and to provide a power source for a downhole light source, if present. Downhole telemetry system 600 includes a set of lower pipe segments 614 terminated by downhole tools 620. Located within the ID set of lower pipe segments 614 is a long length of fiber optic cable 650. The long-length fiber optic cable 650 contains connectors at the downhole end and the uphole end, which minimizes the number of connectors along its length.

[0061] Preferably, the long-length fiber optic cable 650 has a continuous length. In some aspects, long-length fiber optic cable 650 may include splices and amplifiers, such as electrical or erbium-doped fiber optic amplifiers, at locations along its length. In addition, long-length fiber optic cable 650 may include one or more optical strands, one or more fiber optic cables, zero or more electrical cables or wires, and support structures such as steel strands or other materials to help support the fiber optic cable. In addition, long-length fiber optic cable 650 may have various types and combinations of sheathing and protection, such as armored fiber optic cable.

[0062] At the downhole end of the long-length fiber optic cable 650 is an immersion connection 630. The immersion connection 630 may include a light source controller, a modulator, a light detector, a light reflector such as a mirror to reflect the modulated signal, a power supply, a regulator power and other components used to complete the communication system. The communication system may include additional communication systems and methods, such as a drill string communication system that may send a signal using lower pipe segments 614. In some aspects, the communication system may include components for converting communication signals. For example, components may be included that can perform signal processing to convert a signal from electrical to mechanical, electrical to light, light to thermal to electrical, light to light, carrier wave to carrier wave, use signal encryption, use compression signal, other transformations and transformations, as well as their various combinations. In some aspects, the communication system may use a fiber optic light source, a low resolution wireless communication system (LiFi), a visible light communication system (VLC), and other types of communication systems.

[0063] In some aspects, the submersible connection 630 may include a light source 634, such as a laser, high power LED, or other types of light or electromagnetic sources. The submersible connection 630 may be connected to a downhole submersible connection 632, such as a wet connector, where the downhole submersible connection 632 is further connected to the downhole tools 620.

[0064] Electrical connection 624 may provide a communication-capable connection between downhole tools 620 and associated telemetry devices (not shown) and downhole connection 630. Telemetry devices may be one or more devices that can collect data downhole using various types of sensors and generate data using the collected data. For example, temperature sensors, pressure sensors, magnetic resonance sensors, fluid sensors, seismic sensors, permeability and porosity sensors and other types of sensors that may be located in the wellbore. These telemetry sensors can be used with drilling wellbores, PBM, IPB, SWD, ESP, fracturing, production wellbores, intersecting wellbores, relief wellbores and other types of downhole systems. Long length fiber optic cable 650 can be connected to ground equipment or to the first top pipe segment. The first top pipe segment may be connected to additional top pipe segments and in turn connected to the surface equipment.

[0065] Electrical connections 626 may supply power to the submersible connection 630 and, if present, the light source 634. Downhole tools 620 may include a power source such as a generator, batteries, capacitors, and other types of power sources. This energy may be made available for use by other components, such as the submersible connection 630. In an alternative aspect, a separate electrical wire or electrical cable may be in close proximity to a long length of fiber optic cable 650. The electrical wire or electrical cable may provide a conduit for supplying power up the wellbore, such as from a surface generator or a generator located in close proximity to the downhole tools 620, for use by the downhole tools 620, the submersible connection 630, and the light source 634.

[0066] In FIG. 7 is an illustration of a block diagram of an exemplary fiber optic telemetry system (FOTS) 700 with a light source located at optional points within the system. FOTS 700 describes groups of tools, devices and equipment that may be mechanically or communicationally coupled in a wellbore environment. FOTS 700 includes surface equipment 705, a set of top pipe segments 715, a first top pipe segment 716 in a set of top pipe segments 715, a set of bottom pipe segments 717, a submersible connection 730, and downhole tools 720.

[0067] Surface equipment 705 may include drilling equipment, derricks, cranes, winches, controllers, pumps, pipelines, computing systems, and other types of equipment used to operate the wellbore system. Typically, a wellbore operator or engineer, such as a surface user, can view and analyze data received from downhole tools 720 and then make adjustments to work plans. In addition, the user can interact with downhole tools 720 to make changes to commands or work plan in near real time.

[0068] Alternatively, the acquired data may be analyzed by a computer system and adjustments may be made programmatically to the commands and operating plans of the downhole tools 720, for example when a machine learning algorithm is used to process the acquired telemetry data. In some aspects, the user can provide review and approval of changes recommended by the machine learning algorithm. The computing system executing the machine learning algorithm may be located in the wellbore in close proximity to downhole tools 720, in close proximity to surface equipment 705, in close proximity to the first top pipe segment 716, or at another location along the length of the wellbore. Well bores may be for scientific purposes, hydrocarbon exploration and production purposes, or for other purposes such as mining, coal, or sulfur.

[0069] The set of top pipe segments 715 may be one or more pipe segments that contain a conduit cable and connector, such as an electrical cable or wire, a fiber optic cable, a wireless transceiver system, or a combination thereof, providing a communication-capable connection between downhole tools. 720 and ground equipment 705. The first upper pipe segment 716 may include an electro-optical connector for connecting long-length fiber optic cable 750 to an additional length of fiber optic cable, an electrical cable or wire, a wireless transceiver, or other communications tools such as a light source, a multiplexer, a demultiplexer, a processor. signal processing, amplifier and other devices. Long length 750 fiber optic cable is at least three candles long and can be tens of thousands of feet long. This example shows that the top three pipe segments (representing one pipe stand) are mechanically and communicationally connected, separated by a dotted line, although fewer or additional pipe segments and pipe stand can be used.

[0070] In aspects in which a separate electrical cable or electrical wire is included (either as a separate cable or as an electrical cable within a hybrid cable), the upper pipe segments are also electrically connected. Conduit cable 752 may be secured to each of the upper pipe segments using conventional methods, such as guards 754. For example, guards 754 may be cages, pipe clamps, couplings, and other guards and fastening devices. Conduit cable 752 may be located within guards 754. In other aspects, guard 754 may be included within various segments of conduit cable 752. Minimizing the number of pipe tops in a set of pipe tops 715 can minimize the number of connectors used, thus reducing potential transmission signal attenuation and loss as the transmission signal passes through each respective connector. In addition, reducing the number of upper pipe segments can reduce the need for additional protection 754 for conduit cable 752, thereby reducing costs and potential points of failure.

[0071] In some aspects, the first top pipe segment 716 may be a lowermost, middle, or other top pipe segment and may include a light source 740. The light source 740 may be configured to generate and modulate the light source to generate an optical signal for transmission through various fiber optic cable components. The light source 740 also includes other instruments, devices, and electronics for effecting the transmission of one or more signals, such as one or more light detectors, a light reflector, an electro-optical conversion circuit, a controller circuit, an electrical amplifier, a light amplifier, an erbium-doped fiber amplifier, signal processor, modulator, multiplexer, demultiplexer, power source or input from power source and other components. In some aspects, the light source 740 includes instruments, devices, and electronics for receiving one or more signals, such as one or more light detectors, a light reflector, an electro-optical conversion circuit, a controller circuit, an electrical amplifier, a light amplifier, an erbium-doped fiber amplifier , signal processor, modulator, demodulator, multiplexer, demultiplexer, power source or power source input and other components.

[0072] Light source 740 may also be located with ground equipment 705. It also includes devices configured to receive and transmit optical and electrical signals, multiplex and demultiplex, amplify, filter, store, buffer, trigger, and perform other functions. , typically associated with fiber optic converters, such as simple converters, switch converters, network bridges, managed converters, transceivers, gigabit interface converters, fiber optic communications, compact transceivers, or other types of converters known in the field of data and power transmission and communications.

[0073] Data and power can be transferred using data transfer protocols including, but not limited to, Ethernet, High Speed Ethernet, Gigabit Ethernet, T1/E1/J1, DS3/E3, as well as many cable types such as coaxial cable, twisted pair , multimode cable, single-mode fiber, or other types of data and power transmission protocols known in the art.

[0074] The set of lower pipe segments 717 can have different shapes and sizes and do not have to be the same. In addition, the set of lower pipe segments 717 may perform functions other than those described herein. For example, the set of lower pipe segments 717 may include, but are not limited to, drill jars, data sensors and recorders, seismic sources, seismic receivers, other types of receivers (such as gamma ray receivers, radioactive receivers, geological receivers), amplifiers, flow dividers, coolers drilling fluid, formation evaluation tools, samplers, other tools and devices, and various combinations thereof. The set of lower pipe segments 717 may have fiber optic cables and electrical cables or wires that are not used in this invention. Typically, less expensive pipe segments that do not include these components can be used.

[0075] The set of lower pipe segments 717 may have a varying number of pipe segments, and an example is shown using dashed lines to indicate a number of mechanically connected pipe segments. FOTS 700 is not shown to scale and the size and number of top pipe segments and bottom pipe segments may vary depending on application. A set of lower pipe segments 717 may extend through the wellbore 710 to downhole tools 720. A long length of fiber optic cable 750 may be located at least partially within the ID set of lower pipe segments 717. A long length fiber optic cable 750 may only contain connectors at each end, thereby reducing the number of connectors on a given length. The uphole end of the long length of fiber optic cable 750 may be connected to the first top pipe segment 716, to the light source 740, or to another top pipe segment. The downhole end of the long-length fiber optic cable 750 may be coupled via a submersible connection 730 to downhole tools 720

[0076] In some aspects, the plunge connection 730 may be part of a housing that also includes a light source 745 similar to the configuration described with respect to the light source 740. When a light source 740 is present, the light source 745 is typically a reflector and a light demodulator to generate a communication signal. In some aspects, the light source 745 includes instruments, devices, and electronics for receiving one or more signals, such as one or more light detectors, a light reflector, an electro-optical conversion circuit, a controller circuit, an electrical amplifier, a light amplifier, an erbium-doped fiber amplifier , signal processor, modulator, demodulator, multiplexer, demultiplexer, power source or power source input and other components. In other aspects, light source 745 may include a laser, laser emitting diode, high power LED, or other types of electromagnetic spectrum sources. Submersible connection 730 may be coupled to downhole tools 720. Downhole tools 720 may be a BHA, fracturing end assembly, telemetry tools, pumps, sensors, and other tools and devices, or combinations thereof.

[0077] The submersible connection 730 may be one or more instruments or devices in the same or a different housing, including, but not limited to, a light detector, a light reflector, an electro-optical conversion circuit, a controller circuit, an electrical amplifier, a light amplifier, a fiber amplifier, erbium doped, signal processor, modulator, multiplexer, demultiplexer, power source or power source input and other components. It may also include devices configured to receive, transmit optical and electrical signals, multiplex and demultiplex, amplify, filter, store, buffer, trigger, and perform other functions typically associated with fiber optic converters, such as simple converters, switch converters, network bridges, controlled converters, transceivers, gigabit interface converters, fiber optic communications, compact transceivers and other types of converters known in the field of data and power transmission, as well as communications. Data and power can be transferred using data transfer protocols including, but not limited to, Ethernet, High Speed Ethernet, Gigabit Ethernet, T1/E1/J1, DS3/E3, as well as many cable types such as coaxial cable, twisted pair, multimode cable , single-mode fiber, and other types of data and power transmission protocols known in the art.

[0078] In FIG. 8 is a flowchart illustration of an exemplary FOTS implementation method 800. Method 800 may be implemented using, for example, FOTS 700. Method 800 begins at block 805 and proceeds to block 810. At block 810, a downhole tool may be lowered into the well using a set of lower pipe segments. The lower pipe segments can be tens of thousands of feet in length.

[0079] At step 815, a long length of fiber optic cable may be located within the ID set of lower pipe segments. The downhole end of the long length of fiber optic cable may include a submersible connection for connection to a wet mat connector coupled to the downhole tools. Once the connection is made, the uphole end of the long length of fiber optic cable may be optically coupled to a first upper pipe segment that contains the fiber optic connector or electro-optical connector and the conduit cable. Additional upper pipe segments may be added, mechanically connected to the corresponding lower depth pipe segment and communicatively connected (including powered) to a conduit cable that is attached to the OD of the respective upper pipe segments. The first uphole pipe segment and additional uphole pipe segments, if present, may comprise one or more conduit cable protectors to minimize wear on the conduit cable. In some aspects, a light source configured to generate an optical transmission signal may be located in the first upper pipe segment or in one of the additional pipe segments. In other aspects, the light source may be co-located with the ground equipment.

[0080] At step 820, the uppermost of the additional upper pipe segments, or the first upper pipe segment if it is the uppermost, is mechanically coupled to the ground equipment, including being communicatively coupled to the ground equipment. The surface equipment is further coupled to surface computing systems configured to generate and receive data, commands, information and telemetry to and from downhole tools, as well as to and from remote locations. In some aspects, the terrestrial computing systems are configured to execute a machine learning algorithm or deep learning neural network. In other aspects, downhole tools are configured to execute a machine learning algorithm or deep learning neural network.

[0081] At step 825, power can be applied to the light source at an appropriate location in the system, and high throughput unidirectional or bidirectional communications can be established between the downhole tools and surface equipment and surface computing systems. An appropriate location may be in close proximity to downhole tools, in close proximity to surface equipment, or in close proximity to the top pipe segments.

[0082] Communication may be one or more, or a combination, without limitation, of data transmission, amplitude changes, or frequency changes. Optical signals, electromagnetic signals and other types of energy transmission, such as thermal energy, radiated energy, chemical energy, nuclear energy, electrical energy, motion energy, sound energy, elastic energy or gravitational energy, can be used for communication. In some aspects, the communication used in this document is not limited to the transfer of information; communication may involve transmitting one or more types of energy to perform work (for example, adjusting a valve, activating a motor, supplying power to another system, or performing other types of work) or to effect a change of state (for example, a binary switch or variable, position indicator, programmed variable, conditional variable, or other types of state changes). In some aspects, additional steps may be included, such as adding a step after step 815 to test communications and power connections before moving to step 820. Method 800 ends at step 850.

[0083] Because fiber optics have higher capacity than electrical wires, especially over long distances (30 to 3000 feet or more), it can be advantageous to be able to connect more than one electrical wire to the top and bottom ends of a long fiber optic cable. For example, 10 different BHA sensors can provide electrical signals to a downhole light source/transceiver combination. 10 electrical signals can be combined and transmitted by a fiber optic light source. A fiber optic receiver can receive a signal from a wellbore, split the signals into several different signals, 10 in this example, and then transmit the different signals up the wellbore to surface equipment.

[0084] Portions of the above-described apparatus, systems, or methods may be implemented or implemented by various analog or digital data processors, wherein the processors are programmed or store executable programs of program instruction sequences to perform one or more steps of the methods. The processor may be, for example, a programmable logic device such as a programmable array logic (PAL), a generic array logic (GAL), a field programmable gate array (FPGA), or a computer device data processing (CPD; computer processing device) of another type. The program instructions of such programs may be algorithms and may be encoded in machine-executable form on non-volatile digital storage media, such as magnetic or optical disks, random access memory (RAM), magnetic hard disks, flash memory, and/or read only memory (ROM). ROM) to enable various types of digital data processors or computers to perform one, more, or all of the steps of one or more of the above-described methods or functions, systems, or devices described herein.

[0085] Portions of the disclosed examples or embodiments may relate to computer storage products on non-volatile computer readable media that contain program code for performing various computer-implemented operations that implement a portion of an apparatus, device, or perform steps of a method set forth herein. As used herein, the term "non-volatile" refers to all computer-readable media, excluding volatile propagated signals. Examples of non-volatile computer-readable media include, but are not limited to: magnetic media such as hard disks, floppy disks and magnetic tape; optical media such as CD-ROMs; magneto-optical media such as floppy disks; and hardware devices that are specifically configured to store and execute software code, such as ROM and RAM devices. Examples of program code include both machine code, such as that produced by a compiler, and files containing higher-level code that can be executed by a computer using an interpreter.

[0086] In interpreting this invention, all terms should be construed as broadly as possible according to the context. In particular, the terms “comprises” and “comprising” should be construed to refer to elements, components or steps in a non-exclusive manner, indicating that said elements, components or steps may be present, used or combined with other elements, components or steps that not explicitly stated. The terms “comprises” and “comprising” should also be construed to refer to elements, components or steps in a non-exclusive manner, indicating that said element, component or step may be present, used or combined with other elements, components or steps that are expressly identified . Likewise, the terms “comprises” and “comprising” should also be interpreted to refer to elements, components or steps exclusively, indicating that said element, component or step may be present, used separately, independently, together but independently, or together dependently on or in combination with other elements, components or steps not expressly indicated.

[0087] Those skilled in the art to which this application pertains will appreciate that other and further additions, deletions, substitutions, and modifications may be made to the described embodiments. It should also be understood that the terminology used herein is for purposes of describing specific embodiments only and is not intended to be limiting, as the scope of the present invention will be limited only by the claims. Unless otherwise specified, all technical and scientific terms used herein have the meaning commonly understood by one of ordinary skill in the art to which this invention relates. Although any methods and materials similar or equivalent to those described herein may also be used in the practice or testing of this invention, a limited number of exemplary methods and materials are described herein.

[0088] Aspects disclosed herein include the following:

A. A system comprising: (1) a set of lower pipe segments configured to connect to downhole tools, (2) a lower distal end of a long length of fiber optic cable configured to use a submersible connection for connection to downhole tools, wherein the fiber optic cable is large length is located after the downhole tools are located below the surface, and wherein a long length of fiber optic cable is connected for communication with the downhole tools, (3) a set of upper pipe segments configured to mechanically connect the set of lower pipe segments and surface equipment, wherein the set of upper pipe segments comprises at least one upper pipe segment, and (4) an upper distal end of a long length of fiber optic cable located uphole from the lower distal end, configured to use an uphole connector for a communication-capable connection with a conduit cable of a first upper pipe segment in the set of upper pipe segments, and wherein each upper pipe segment in the set of upper pipe segments comprises a corresponding conduit cable connected in communication with adjacent conduit cables, and wherein the assembly containing each conduit cable provides the connection with the ability to communicate between long-length fiber optic cables and ground-based equipment.

B. An apparatus comprising: (1) a long length fiber optic cable disposed within a wellbore, (2) a downhole tool communicatively coupled to a lower distal end of the long length fiber optic cable, the downhole tool employing a submersible connection, (3) a set of pipe segments, wherein each pipe segment is mechanically connected to an adjacent pipe segment, and wherein a first upper pipe segment in the set of pipe segments is connected to an upper distal end of a long length of fiber optic cable, and the first upper pipe segment is located uphole from the downhole tool, and (4) surface equipment connected to a set of pipe segments.

C. A method comprising: (1) connecting a downhole tool to a set of lower pipe segments and lowering the downhole tool below the surface using the set of lower pipe segments, (2) connecting an uphole portion of a set of lower pipe segments to a first uphole portion of the set of lower pipe segments. well to a pipe segment, wherein the lower distal end of the long-length fiber optic cable is lowered within the inner diameter of the set of lower pipe segments and is connected for communication with the downhole tool, and the upper distal end of the long-length fiber optic cable is connected to the first pipe segment located upstream of the wellbore, (3) connecting the uppermost, topmost pipe segment of the top pipe segment set to the surface equipment, wherein the top pipe segment set comprises a first uphole pipe segment and zero or more additional top pipe segments, and wherein each top pipe segment pipe in the set of upper pipe segments includes a conduit cable for connecting with the ability to communicate a long length of fiber optic cable with surface equipment, and (4) providing communication between the surface equipment and a downhole tool using a long length of fiber optic cable and one or more conduit cables.

[0089] Each of aspects A, B and C may have one or more of the following additional elements in combination. Element 1: characterized in that the pipeline cable comprises one of an electrical pipeline cable, an electrical wire or a fiber optic cable. Element 2: characterized in that the immersion connection uses at least one of one or more electrical immersion connections or one or more fiber optic immersion connections. Element 3: characterized in that the immersed connections provide one or more of electrical transmission or communication transmission. Element 4: characterized in that the downhole tools are one or more of bottom hole assembly, telemetry tools, logging while drilling tools, measurement while drilling tools, seismic measurement while drilling tools, sensors, valves, actuators machinery, data collection instruments and wireline instruments. Element 5: further comprising one or more conduit cable protectors configured to protect the conduit cable and attached to one or more top pipe segments in the set of top pipe segments. Element 6: characterized in that the pipeline cable protectors rotate together with the corresponding upper pipe segments and are one or more of a cage and a centralizer, and employ one or more of a coupling, a locking coupling or a pipe clamp. Element 7: characterized in that the long-length fiber optic cable is one of a fiber optic cable, a reinforced fiber optic cable, a supported fiber optic cable or an armored fiber optic cable. Element 8: characterized in that the long-length fiber optic cable is one or more of a fiber-optic cable and one or more of a long-length electric cable. Element 9: characterized in that the connector located upstream of the wellbore uses one of an electro-optical connector or an optical-optical connector. Element 10: characterized in that the connector located upstream of the wellbore supports a long length of fiber optic cable when connected to the submersible connection. Element 11: further comprising a light source configured to generate or modulate a signal transmitted over a long fiber optic cable. Element 12: characterized in that the light source is one of a laser or a light-emitting diode. Element 13: characterized in that the light source is located in one of the positions in the immediate vicinity of the submersible connection or in the immediate vicinity of the connector located upstream of the wellbore. Element 14: characterized in that the uphole connector is a first uphole connector and the submersible connection is a first submersible connection. Element 15: further comprising a lower distal end of an electrical cable configured to transmit electrical power and communication signals, connected to the downhole tools via a second submersible connection. Member 16: further comprising an upper distal end of the electrical cable located at a second uphole location from the lower distal end of the electrical cable, configured to use a second uphole connector for connection to the electrical conduit attached to the first upper segment pipes. Element 17: characterized in that the electrical conduit cable is electrically connected to the ground equipment. Element 18: characterized in that the set of upper pipe segments contains at least one upper pipe stand. Element 19: characterized in that the surface equipment is one or more of a rig, a drilling system, a computer system, an electrical system and a power source. Element 20: characterized in that, at the top portion of the set of pipe segments, one or more of a cage or centralizer is used to protect one or more of the conduit cable attached to each of the corresponding pipe segments in the set of pipe segments. Element 21: characterized in that the pipeline cable connects a long-length fiber optic cable and ground equipment with communication capabilities. Element 22: characterized in that each of the pipe segments in the set of pipe segments uses a conduit cable for communication and power connection with an adjacent pipe segment. Element 23: characterized in that the pipeline cable is one of a fiber optic cable, an electric cable or an electric wire. Element 24: further comprising a light source configured to generate or modulate an optical signal and transmit the optical signal over a long length of fiber optic cable. Element 25: characterized in that the light source is located in close proximity to the downhole tool, in close proximity to the first upper pipe segment, or in close proximity to surface equipment. Element 26: The light source is one of a laser or a light-emitting diode. Element 27: characterized in that the conduit cable is at least one of one or more of a fiber optic cable, one or more of an electrical cable or one or more of an electrical wire. Element 28: characterized in that the light source is located in one of a position in close proximity to the downhole tool, in close proximity to surface equipment, or in close proximity to the first uphole pipe segment. Element 29: characterized in that the light source generates or modulates an optical signal for transmission over a long length of fiber optic cable and one or more conduit cables. Element 30: characterized in that a cable protector is used in the set of upper pipe segments. Element 31: characterized in that the cable protector rotates in conjunction with a set of upper pipe segments and is one of a cage, a centralizer, a coupling or a pipe clamp.

Claims (34)

1. A system for transmitting communications inside a borehole, containing a set of lower pipe segments configured to be connected to downhole tools; a lower distal end of the fiber optic cable configured to employ a submersible connection for communication with downhole tools, wherein the fiber optic cable is located after the downhole tools are located below the surface, and wherein the fiber optic cable is communicatively coupled to the downhole tools; a set of upper pipe segments configured to mechanically connect the set of lower pipe segments and ground equipment, the set of upper pipe segments comprising at least one upper pipe segment; And an upper distal end of a fiber optic cable located uphole from the lower distal end, configured to use an uphole connector to communicatively connect to a pipeline cable of a first top pipe segment in the set of top pipe segments, and wherein each top segment The pipes in the set of upper pipe segments include a corresponding conduit cable communicatively connected to adjacent conduit cables, and wherein the assembly containing each conduit cable provides a communicable connection between the fiber optic cable and the ground equipment. 2. The system according to claim 1, additionally containing: one or more pipeline cable protectors configured to protect the pipeline cable and attached to one or more upper pipe segments in a set of upper pipe segments, wherein the pipeline cable protectors rotate with the corresponding upper pipe segments and constitute one or more of a cage and a centralizer, and employ one or more of a coupling, a locking coupling or a pipe clamp. 3. The system according to claim 1, wherein the uphole connector is a first uphole connector and the downhole connection is a first downhole connection, further comprising: a lower distal end of an electrical cable configured to transmit electrical power and communication signals connected to the downhole tools via a second submersible connection; And an upper distal end of an electrical cable located at a second uphole location from a lower distal end of the electrical cable, configured to use a second uphole connector for connection to an electrical conduit attached to the first upper pipe segment, wherein the electrical The conduit cable is electrically connected to the surface equipment. 4. The system according to claim 1, additionally containing: a light source configured to generate or modulate a signal transmitted over the fiber optic cable, wherein the light source is one of a laser or a light emitting diode, and optionally, wherein the uphole connector uses one of an electro-optical connector or an optical-optical connector. optical connector, and wherein the uphole connector supports the fiber optic cable when connected to the submersible connection. 5. The system according to claim 4, characterized in that the light source is located in one of the positions in close proximity to the submersible connection or in close proximity to the connector located upstream of the wellbore. 6. The system according to any one of paragraphs. 1-4, wherein the conduit cable comprises one of an electrical conduit cable, an electrical wire, or a fiber optic cable, and optionally the set of top pipe segments comprises at least one top tube stand. 7. The system according to any one of paragraphs. 1-4, characterized in that the immersion connection uses at least one of one or more electrical immersion connections or one or more fiber optic immersion connections, and optionally, the immersion connections provide one or more of electrical transmission or communication transmission. 8. The system according to any one of paragraphs. 1-4, characterized in that the downhole tools are one or more of bottom hole assembly, telemetry tools, logging while drilling tools, measurement while drilling tools, seismic measurement while drilling tools, sensors, valves, actuators, data acquisition tools and wireline tools. 9. The system according to any one of paragraphs. 1-4, wherein the fiber optic cable is one of a fiber optic cable, a reinforced fiber optic cable, a supported fiber optic cable, or an armored fiber optic cable, and optionally, wherein the fiber optic cable is one or more of a fiber optic cable and one or more of electrical cable. 10. A device for transmitting communications inside a borehole, containing: fiber optic cable located inside the wellbore; a downhole tool communicatively coupled to a lower distal end of the fiber optic cable, the downhole tool using a submersible connection; a set of pipe segments, wherein each pipe segment is mechanically coupled to an adjacent pipe segment, and wherein a first upper pipe segment in the set of pipe segments is coupled to an upper distal end of the fiber optic cable, and the first upper pipe segment is located uphole from the downhole tool; wherein the conduit cable is attached to each of the respective pipe segments in the set of pipe segments, the conduit cable communicatively connecting the fiber optic cable and the ground equipment; And surface equipment connected to a set of pipe segments. 11. The device according to claim 10, additionally containing: a light source configured to generate or modulate an optical signal and transmit the optical signal over a fiber optic cable, and optionally the light source is located in close proximity to the downhole tool, in close proximity to the first top pipe segment, or in close proximity to surface equipment , and the light source is one of a laser or a light-emitting diode. 12. Device according to any one of paragraphs. 10, 11, characterized in that at the top portion of the set of pipe segments, one or more of a cage or centralizer is used to protect one or more of the pipeline cable, and, optionally, in each of the pipe segments in the set of pipe segments, a pipeline cable is used to communicating and energizing with an adjacent pipe segment, and wherein the pipe cable is one of a fiber optic cable, an electrical cable, or an electrical wire. 13. A method for transmitting communications inside a borehole, including: connecting the downhole tool to a set of lower pipe segments and lowering the downhole tool below the surface using the set of lower pipe segments; connecting a section of a set of lower pipe segments located upstream of the wellbore to a first pipe segment located upstream of the wellbore, wherein the lower distal end of the fiber optic cable is lowered within the inner diameter of the set of lower pipe segments and is connected for communication with the downhole tool, and the upper distal end a fiber optic cable is connected to a first pipe segment located upstream of the wellbore; connecting the topmost pipe segment in the set of top pipe segments to surface equipment, wherein the set of top pipe segments comprises a first uphole pipe segment and zero or more additional top pipe segments, and wherein each top pipe segment in the set of top pipe segments the pipe contains a pipeline cable for connecting with the ability to communicate a fiber optic cable with ground equipment; And providing communication between surface equipment and downhole tools using fiber optic cable and one or more pipeline cables. 14. The method of claim 13, wherein the light source is located at one of positions in close proximity to the downhole tool, in close proximity to surface equipment, or in close proximity to the first uphole pipe segment, wherein the light source generates or modulates an optical signal for transmission over a fiber optic cable and one or more conduit cables. 15. Method according to any one of paragraphs. 13, 14, characterized in that the conduit cable is at least one of one or more fiber optic cable, one or more electrical cable, or one or more electrical wire, and optionally, wherein the set of upper pipe segments uses cable protector, wherein the cable protector rotates in conjunction with the set of upper pipe segments and is one of a cage, a centralizer, a coupling, or a pipe clamp.

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