NO339508B1 - System and method for self-propelled communication and sensor network in a borehole - Google Patents

Description

BACKGROUND OF THE INVENTION

Invention Council

The invention relates to the transmission of information along a pipe string and relates more particularly to a system with autonomous telemetry stations positioned along the pipe string for low energy, adaptive communication and measurement.

Description of Related Art

The oilfield industry now uses two communication extremes in boreholes, the classification of these two extremes relates to the time period for the borehole construction, typically respectively during the borehole construction and after construction during the operation of the borehole for the production of hydrocarbons.

In the sub-phases of drilling and completion, communication is carried out using a form of mud pulse telemetry usually used within systems with measurement while drilling "MWD". Alternative telemetry methods, such as low frequency electromagnetism and acoustics, have been investigated and found to be of limited or specialized use. In general, MWD telemetry is bound by the speed of sound and the viscous properties of the drilling fluid, so that data capacity for mud pulse telemetry rarely exceeds 10 bits per second.

An increase in the number and complexity of well sensors in MWD systems has increased the need for higher data capacities for the telemetry link. The introduction of rotary closed-loop control systems has increased the need for two-way telemetry from the top to the bottom of the well.

Industry efforts to develop high throughput telemetry have included methods of incorporating fiber optic or wireline technology into the drill string, transmission of acoustic signals through the drill string, and transmission of electromagnetic signals through the earth surrounding the drill string. US Patent No. 4,095,865 (Denison et al) describes sections of drill pipe, pre-wired with an electrical conductor, but each section of pipe is manufactured separately and is difficult and expensive to maintain. Acoustic systems suffer from damping and filtering effects caused by reflections at each drill pipe joint. Attempts have been made to predict filtering effects, see for example US patent no. 5,477,505 (Drumheller). In most such methods, signal busters or signal amplifiers are necessary approximately every 300 metres. So far, the only practical and commercial method for MWD telemetry is modulation of mud flow and mud pressure with its relatively slow data capacity.

Once a well is drilled and completed, special sensors and control devices are usually installed to help operate the well. These devices have historically been individually controlled or monitored using assigned wiring. These controls were initially hydraulically operated valves (such as seabed safety valves) or were sliding sleeves operated by displacement tools physically inserted on a special cable to displace the sleeve as required.

The next development in well sensing and well control was to move from hydraulic to electrical cabling permanently mounted in the borehole and communicating back to control and reporting units on the surface. Initially, these control lines provided both energy and data/command between the well and the surface. With advances in sensor technology, the ability to multiplex along cables now allows multiple sensors to be used along a single cable run. The industry has started to use fiber optic transmission lines instead of traditional electrical wires for data communication.

A common element for these well operation sensors and devices is the transmission of energy and information along the installed telemetry path. The telemetry path is typically installed in long lengths over several sections of joined pipe. The installation of the telemetry path is thus necessary after the main pipe has been installed in the well. The devices along the telemetry path must meet a common interface and energy specification. Any malfunction in the path puts energy transfer and communication at risk.

A need has thus been demonstrated for telemetry systems with higher data capacity with two-way transmission capability that are less susceptible to communication and energy interruptions for use with joined pipes.

SUMMARY OF THE INVENTION

The objectives of the present invention are achieved by a communication system for use with a joined drill string in a borehole, comprising: a tubular drill string, where the tubular drill string has a plurality of sections connected by means of a plurality of connecting joints; and further characterized by that

an autonomous telemetry station is arranged in each of said plurality of connecting joints, the autonomous telemetry station being arranged to receive a first signal and send a second signal related to said first signal.

Preferred embodiments of the system are further elaborated in claims 2 to 9 inclusive.

The objectives of the present invention are further achieved by a method for communicating along a jointed drill string in a borehole, comprising: - a tubular drill string is extended into the borehole, the tubular string having a plurality of sections connected by means of a plurality of connecting joints; and further characterized in that - an autonomous telemetry station is placed close to each said plurality of connection joints, the autonomous telemetry station being arranged to receive a first signal and transmit a second signal related to the said first signal.

Preferred embodiments of the method are further elaborated in claims 11 to 19 inclusive.

A measurement and communication system for use with a pipe string is described which comprises a plurality of separate, autonomous telemetry stations arranged at predetermined locations along the pipe string. Energy is drawn from potential energy sources near each autonomous telemetry station. Each of the plurality of autonomous telemetry stations is adapted to receive at least a first signal and transmit at least a second signal related to said at least one first signal.

A method of communicating information along a pipe string is also described, which includes the arrangement of a plurality of separate, autonomous telemetry stations at predetermined locations along the pipe string. A preferred transmission path is determined autonomously at each of the autonomous telemetry stations. Information is transmitted along the pipeline according to the autonomously determined preferred path.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present invention, reference is made to the following detailed description of the preferred embodiment, seen in connection with the attached drawings, in which corresponding elements have been given the same reference numbers, in which: Fig. 1 is a schematic drawing of a drilling system with a jointed pipe string in a borehole according to an embodiment of the present invention; Fig. 2 is a schematic drawing of a joined connection with an autonomous telemetry station placed therein, according to an embodiment of the present invention; Fig. 3 is an electrical schematic drawing of a circuit for providing energy from a piezoelectric device, according to an embodiment of the present invention; Fig. 4 is a schematic seal of a galvanic energy source, according to an embodiment of the present invention; Fig. 5 is a schematic drawing of an autonomous telemetry station with an extension sleeve extending into an adjacent section of the drill string, according to an embodiment of the present invention; Fig. 6 is a schematic drawing of an autonomous telemetry station with an extension sleeve extending substantially the length of a section of drill string, according to an embodiment of the present invention; Fig. 7 is a schematic drawing of a method for expanding a casing into a section of drill string, according to an embodiment of the present invention; Fig. 8A, B are schematic drawings of a method for installing an elastic sleeve into a section of drill string, according to an embodiment of the present invention; Fig. 9 is a schematic drawing of several transmission paths along a jointed pipe string, according to an embodiment of the present invention; Fig. 10A, B are schematic drawings of an autonomous telemetry station with a plurality of telemetry modules therein, according to an embodiment of the present invention; Fig. 11 A, B are schematic drawings of a piezoelectric energy generator according to an embodiment of the present invention; Figs. 12A-D are schematic drawings of waveguide devices for use with the present invention; Fig. 13 is a schematic drawing depicting a magneto-hydrodynamic energy generator for use as an energy source according to an embodiment of the present invention; Fig. 14 is a schematic drawing of an eccentric mass generator for use in an autonomous telemetry station according to an embodiment of the present invention; Fig. 15A, B are schematic drawings of a rolling ball generator for use in an autonomous telemetry station according to an embodiment of the present invention; Fig. 16A, B are schematic drawings of a section of the drill string with a waveguide attached thereto, according to an embodiment of the present invention; Fig. 17A, B are schematic drawings of a microturbine generator in a drill string, according to an embodiment of the present invention; Fig. 18 is a schematic drawing of a microturbine generator that supplies energy to several autonomous telemetry stations, according to an embodiment of the present invention; Fig. 19 is a schematic drawing of a galvanic energy source using a drill string section as a cathode, according to an embodiment of the present invention; Fig. 20 is a schematic drawing of a galvanic cell with anode and cathode that is electrically isolated from the drill string section, according to an embodiment of the present invention; Fig. 21 is a schematic drawing of an instrumented transition inserted in a drill string, according to an embodiment of the present invention; Fig. 22A-C are schematic drawings of an optical communication system, according to an embodiment of the present invention; Fig. 23 is a schematic drawing showing a system for detecting multiphase current in a borehole, according to an embodiment of the present invention; and Fig. 24 is a schematic drawing of a system for creating flow vortices and generating energy therefrom, according to an embodiment of the present invention;

DESCRIPTION OF PREFERRED EMBODIMENTS

In a preferred embodiment, see fig. 1 and as described herein by way of example and not by way of limitation, a drilling operation includes a conventional drilling derrick 10 for carrying a drill string 3 in a borehole 2, also referred to as a wellbore. The drill string 3 comprises several sections of drill pipe 1 connected together by means of threaded connections 4. A downhole assembly NHA 9 is attached to the bottom end of the drill string 3 and has a drill bit 8 attached to a bottom end thereof. The drill bit 8 is rotated to drill through soil formations. The downhole assembly BHA 9 comprises several sections of drill collars 6 and may have a measurement while drilling MWD system 7 attached therein, above the drill bit 8. Collar sections 6 and the MWD system 7 are connected through threaded connections 5. Measurement while drilling MWD and/or logging while drilling LWD systems are well known in this area. Such systems typically measure a number of parameters of interest regarding the drilling operation, the formations surrounding the wellbore 2 and the position and direction of the drill bit 8 in the wellbore 2. These systems may include well processors (not shown) to provide open or closed loop control, in conjunction with a controllable system (not shown) of the trajectory of the borehole 2 towards a predetermined target in the underground formations.

Drilling fluid 11, usually referred to as drilling mud, is pumped using the pump 16 through the drill string 3, exits through the drill bit 8, and returns back to the surface in the annulus 12 between the drill string 3 and the drill hole 2. Drilling fluid flow rates can usually be in the range of 400 liters per minute to more than 4000 liters per minute, depending at least to some extent on the borehole size and the ability of the fluid to remove the cuttings from the borehole. The potential energy in the drilling fluid that flows through the drill string is typically more than 100 kilowatts.

Located at each of the threaded connections 4 and 5 is an autonomous telemetry station (ATS) 20, see fig. 2, located between inner shoulders of the pin section 21 and the base section 22 which form the threaded connection 4 for two sections of drill pipe 1. ATS 20 is a torus-shaped or donut-shaped ring that is held by the pin shoulder, also referred to as the pin nose 46, and the return drilling socket shoulder 47.1 a preferred design ATS 20 comprises a signal receiver 25, a signal transmitter 23, a controller 24, and an energy source (not shown). The ATS 20 may also contain sensors (not shown) to measure parameters of interest related to the drilling process and the formations surrounding the borehole 2. The components of the ATS 20 may be encapsulated in a suitable compliant material, for example elastomer, so that the ATS 20 is compressed in a predetermined degree between the pin nose 46 and to the backbore shoulder 47 and can be installed in the field during the establishment of each connection. Suitable elastomers are known in the field and are usually used for submerged acoustic transducers. By locating an ATS 20 at each threaded joint 4, 5, signals communicated along the drill string 3 only need to have sufficient strength to be transmitted between each ATS 20, or between antennas connected to each ATS as described later. The attenuation and interference associated with transmitting signals over multiple links is no longer a limiting factor. Therefore, low-energy transmissions are suitable for communicating signals containing mainly increased data capacities over the length of the drill string 3. ATS 20 operates at energy levels of the order of a few tens of milliwatts to a few watts in contrast to conventional well telemetry systems that operate with tens to hundreds of watts. As shown in fig. 2, an acoustic signal 26 is moved through a section of a drill string 1a towards connection 4. The signal is transmitted from the section of drill string 1a to the receiver 25 in the ATS 20. The ATS 20 processes the signal and forwards the signal using the transmitter 23 into the next section of the drill string 1 b. The process is repeated at each connection in the drill string 3 and is detected by a surface located receiver 30 attached to the surface controller 15, see fig. 1. In a similar way, signals can be transferred from the surface system to a well ATS 20 and/or to the MWD system 7 in fig. 1, and/or between several ATS devices. The receiver 25 and the transmitter 23 can be piezoelectric devices as are well known in this area. Such devices can be adapted to function interchangeably as a receiver or transmitter to enable two-way communication.

In a preferred embodiment, as a significant novelty feature, the energy source for each ATS 20 draws or "harvestes" electrical energy from sources of potential energy at the location of each ATS 20. For example, mechanical vibration from the stirring elements of the drill string and/or inefficient fluid movement can (such as parasitic velocity pressure loss) related energy is drawn from the drill string and the fluids moving within the drill string. Similar energy sources are, for example, present in production strings and pipelines and are intended to be covered by the invention referred to herein. The extracted energy can come from naturally occurring "lost" energy, such as existing pipe vibration energy or existing fluid differential pressure (caused by existing geometry). Alternatively, devices or geometries near each ATS can be adapted to cause a vibration for mechanical energy or fluid derived energy (turbulence or differential pressure) for utilization of the ATS. In addition to harvesting existing lost energy from the existing process, additional devices can be inserted in the fluid flow or in the drill string, at a distance from the ATS, to induce additional energy within the piping system and/or fluid flow for utilization by the ATS.

It is well known in the field that the drill string 3 vibrates both axially, rotationally and laterally during the drilling process. In addition, the drilling fluid 11 is typically in turbulent flow inside the drill string at normal operating flow rates. Both the vibrational energy of the drill string 3 and the turbulent flow energy of the drilling fluid 11 provide sources of potential energy which can be converted using suitable methods to provide sufficient energy for the ATS 20.1 In one embodiment, piezoelectric materials are used to harvest electrical energy from at least one of these potential energy sources. As is well known, when a force is applied to a piezoelectric material, positive and negative charges are induced on opposite crystal surfaces. Such materials as quartz and barium titanate are examples of piezoelectric materials. Various mechanical mounting arrangements expose the piezoelectric materials to the vibrational motion of the drill string to generate an energy. For example, piezoelectric materials can be mounted in the ATS 20 in fig. 2, so that they react to the general vibrational movement of the drill string 3. The materials can be assembled as separate crystals. Example, with reference to fig. 11 A, B shows an embodiment of an ATS 20 with an integrated energy source 100. The ATS 20 has a controller 24 and energy source 100 in a housing 110 with receiver 25 and transmitter 25 embedded between the pin nose 46 and the return drilling shoulder 47. The controller 24 has suitable circuitry for converting the energy signals from the energy source 100 into suitable voltages for various devices, as required. The energy source 100 comprises an annular ring mass 101 attached to several piezoelectric rods oriented around the donut-shaped ring-shaped configuration of the ATS 20. When the drill string is moved according to the arrows 111, the inertial mass in the ring 101 causes the piezoelectric rods 102 to bend and creates bending loads and generates electrical energy. The components are contained in the housing 110 which is filled with the dielectric fluid 103. Dielectric fluid 103 is separated from the drilling fluid 11 by means of the flexible diaphragm 104. Drilling fluid is released through compensation hole 105, so that the well pressure and well temperature are legalized inside the housing 110. Alternatively, each piezoelectric rod 102 can have a mass consisting of a segment of a ring (not shown), so that the rod/mass system is free to respond to both lateral and swirling movement of the drill string.

Alternatively, the piezoelectric materials may be formed as any number of microelectromechanical system (MEMS) type devices. For example, commercially available piezoelectric MEMS accelerometers generate electrical signals in response to vibrational energy. Such devices may be configured to generate electrical energy. Fig. 3 shows an exemplary circuit for converting the output from a piezoelectric device 35. The output from the piezoelectric device 35 is rectified by means of the diode bridge 36 to charge an energy storage device 37 which supplies energy to the load 38 which can be any combination of electrically driven devices in the ATS 20. Several voltages from several such piezoelectric devices can be rectified across a common diode bridge. The energy storage device is preferably a capacitor, but can alternatively be a rechargeable battery. Several capacitors and/or batteries can be used.

In a further preferred embodiment, see fig. 4, the ATS 20 has an extension tube 41 attached thereto. The extension pipe 41 extends upward a predetermined distance into the bore 42 of the socket connection 22. The extension 41 may extend (i) downstream from the ATS 20; (ii) upstream from ATS 20 into the tap connection 21, see fig. 5; or (iii) in both the upstream and downstream directions (not shown). The extension 41 can have piezoelectric devices embedded in it, so that these devices react to pressure variations in the fluid flow 11. Such pressure variations can be due to turbulent fluctuations in the fluid and/or can be due to pressure fluctuations caused by the positive displacement pump 16 which pumps the drilling fluid 11 through the drill string 3. The extension 41 may have a piezoelectric polymer material, such as polyvinylidene difluoride (PVDF) attached to the inner surface, so that the PVDF film (not shown) is exposed to the flow energy to generate electrical energy. The length of the extension pipe 41 can be chosen so that sufficient area is exposed to the flow to generate sufficient energy, including that the pipe extends over substantially the length of a section 1 of drill string 3. The energy harvested from such systems in the fluid flow can is used to operate ATS 20.

In a further embodiment, turbulence inducing protuberances (not shown) may be positioned on the ATS and/or along an extension sleeve and extend into the fluid flow to induce turbulent eddies in the fluid flow containing sufficient energy. Such protuberances can be used in conjunction with any of the piezoelectric fluid utilization features. Such protuberances include but are not limited to button-shaped or ring-shaped. Alternatively, recesses may be spaced around the donut-shaped ATS and/or along an extension sleeve to induce turbulence. In one embodiment, see fig. 24, the ATS 260 is made of a suitable elastomeric material and is embedded between sections 265 and 266 at the coupling 264. The ATS 260 has a sleeve 263 attached thereto in which piezoelectric materials (not shown) are embedded, as previously described herein. ATS 260 is dimensioned so that a predetermined protuberance 261 is generated when the connection is established. The protuberance 261 causes turbulent eddies (not shown) to be created which strike against the sleeve 263 and cause it to generate voltages from the incorporated piezoelectric materials. The voltages are rectified using circuits in the ATS 260.

In a further preferred embodiment, the extension 41 is made of an electrically insulating material and has a sacrificial anode sleeve 43 attached to an inner diameter thereof. A galvanic current is established between the sacrificial anode and the steel drill string 3 in the presence of an electrically conductive drilling fluid 11. Using methods known in the field based on the materials used and the conductivity of the drilling fluid 11, a predetermined amount of energy can be generated for use in driving ATS 20.

Alternatively, the extension 41 can contain a suitable number of batteries suitable for well use. The batteries can be of the disposable type and can be of the replaceable or rechargeable type. Any suitable shape configuration of battery can be used in accordance with the space limitations known in the art. Plenty of batteries are provided.

Other methods may be used, alone or in combination with any other of the methods described above to provide sufficient energy to the ATS 20. These methods include but are not limited to (i) thermoelectric generators based on temperature differentials between the inside and outside of the drill string 3; (ii) micro fuel cell devices; (iii) photon absorption from natural gamma emission from the surrounding formation; (iv) photon absorption from natural gamma emission from a downwell source; (v) long piezoelectric film strips, or "socks" adapted to flutter in the flowing drilling fluid, so that the relevant movement is amplified and energy is generated; (vi) magneto-hydrodynamic generators; and (vii) eccentric mass generators. Such a micro fuel cell device can be contained in the ATS 20 and be self-sufficient with sufficient fuel and oxidizer to operate for a predetermined period.

In a preferred embodiment, see fig. 13, permanent magnets 130 are arranged in the ATS 135 to induce a magnetic field over the fluid flow area 133. As is known in the art when a conductive fluid 11 flows through the magnetic field, either in or out of the plane as indicated in FIG. 13, voltages are induced at electrodes 131 in a plane orthogonal to both the plane of the magnetic field and the direction of flow. Such voltages can be used to generate energy which is stored in the source 132.

In yet another embodiment, a ring coil (not shown) is placed in an ATS 20, so that drilling fluid 11 passes through the center of the coil. The drilling fluid has ferromagnetic particles, such as hemtite, dispersed therein. The flow of magnetic particles through the coil induces electrical currents in the coil and which can be stored in an energy source for use in the ATS.

In a further preferred embodiment, see fig. 1, an eccentric mass 141 swings about a shaft 142 in the vicinity of spools 143 mounted in an ATS in a drill string. The permanent magnet 140 is arranged in the mass 141 near the outer end. When the mass 141 is exposed to lateral vibration and torsional swirl of the drill string, the mass will be induced to rotate the magnet 140 past the coils 143 and induce an electric current to flow in the coils and which can be stored in the energy source 145. Many such eccentric masses can be bridged and rectified together, such as in a MEMS device, to generate energy from the movement of the drill string.

In a further preferred embodiment, see fig. 15, a plurality of balls 150 are enclosed to roll between coil assemblies 152 in response to lateral vibration and swirl of the drill string. Each ball has a permanent magnet 151, so that when the ball with the magnet rolls, it passes the magnetic flux lines through the coils 154 in the coil assemblies 152. The induced electric currents and related voltages are rectified by the bridge 155 and stored in the energy source 156.

As an alternative, or used in combination with the above-discussed yielding donut, the complete energy, sensing, and communication elements can be packaged in a sleeve that protrudes into the tubing string above or below the tool tubing length of interest. . In a preferred embodiment, the sleeve, see fig. 6, a rigid thin-walled tube 61 that is lowered or pushed into a joint, bonded to the tube 61, or encapsulated therein, is an ATS 60 with a receiver, a controller, a transmitter, and other elements including sensors and any energy device , as previously described, and/or electrical or optical conductors (not shown) necessary to enable alternative communication methods described later. For example, antenna wires (not shown) may be attached to or alternatively embedded in the sleeve along the length of the sleeve to enable RF and EM communications, as described later, and the sleeve may extend the length of the section of drillstring 1. The tubing may be substantially pressure neutral (submerged) in the drilling fluid 11 within the drill string 1 and all components are electrically and mechanically isolated and isolated from the section of the drill string 1 and the fluid 11. The rigid casing 61 may be constructed of any number of materials including, but not limited to plastics, fibre-reinforced composites and metal. The materials may be considered expandable. The material selections depend on the function of the sleeve 61 related to energy generation and/or radio wave transmission and can be selected by a person skilled in the art without much experimentation.

In a further preferred embodiment (see Fig. 7), the sleeve 71 is a plastically deformable sleeve which has a smaller diameter than the ID of the section 1 of the drill string 3 in which it is to be inserted. The OD of the inserted sleeve 71 may be coated with a material 75, such as an elastomer or a plastic material, which has electrical and/or optical conductors and other necessary components pre-positioned inside the material 75. The undersized sleeve 71 is inserted and then expanded by by means of a spindle 73 which is pulled by a rod 74, so that the expanded sleeve 72 is plastically deformed and placed in compression against the inner surface of the drill string section 1 and anchors the expanded sleeve 72 inside the drill string 1. A method of removing the expanded sleeve 72 is an internal spiral cutter (not shown), known in the art, which allows the cut sleeve to be drawn out in the form of an elongated strip.

In a further preferred embodiment, see fig. 8A, B, has an elastic sleeve 81, for example of a rubber material suitable for well use, ATS 80 and the antenna 82 encapsulated therein. The sleeve 81 has a relaxed diameter 81' greater than the inner diameter of the drill string section 1. By stretching the sleeve 81' longitudinally using known methods, the OD of the sleeve 81' is reduced to the diameter of 81". If stretched in the correct direction extent, the sleeve 81" can then be placed inside section 1 without interference. Once in place, the elongating force is relieved and the tube elastically expands to contact the inner diameter of section 1 and provides a locating and holding force between the OD of sleeve 81 and the ID of section 1. Additional anchoring can be provided by means of a external binder part (not shown). An upper end retainer or anchor 83 can be used to add sealing and prevent flowing fluids from stripping the sleeve 81 from section 1. The anchor 83 can be bent or expanded during the final installation process. Removal of the inserted sleeve 81 can be by means of a renewed stretching and removal method or alternatively by means of a spiral cutting method, as discussed above.

The previously described communication system shows a signal transmitted acoustically through the material in each section 1, 6 of the drill string 3. Other localized communication methods include but are not limited to (i) radio frequency transmission, (ii) low frequency electromagnetic transmission (iii) optical transmission, and (iv) back reflection method. As used herein, radio frequency (RF) transmission refers to transmissions in the range of approximately 10 kHz to 10 GHz, while low frequency electromagnetic (EM) transmission refers to transmissions in the range of approximately 20 Hz to 10 kHz.

The previously described acoustic system mainly uses the aforementioned ATS to transmit a signal over the connection joint and uses the drill string section as a relatively low loss waveguide between the connections. The RF and EM signal transmission media are the surrounding earth formation and the fluids in the borehole and formation. It is known within this area that the attenuation in such media is strongly dependent on the localized properties including, but not limited to, formation, fluid resistivity and signal frequency. In some situations, attenuation may be unacceptable for low-energy transmissions over the distance between the connections, typically of the order of 10 meters. By using the extended sleeve configurations and methods described above, however, the effective transmission distance can be significantly reduced and thereby allow low energy communication between the connections, see fig. 6. For example, miniaturized low energy RF transceivers (combined transmitter/receiver) are commercially available and are described for well applications in which an interrogator transceiver is brought into close proximity to an RF identification device for locating specific compounds in a borehole, see US Patent Nos. 6,333,699 and 6,333,700. When using the sleeve 61, as described in fig. 6, antenna wires can be introduced along the length of the sleeve 61 and provide a transmission length of the order of a few tens of centimeters to many tens of centimeters, as needed. Similarly, the other sleeve configurations described can be introduced along the entire length of the drill string section to greatly reduce transmission lengths, enabling low energy RF and/or EM communication over the links. Alternatively, the sleeve can have such a length that it coaxially overlaps the ATS of an adjacent connection to establish communication.

In a further preferred embodiment, see fig. 12A-D, a waveguide 115 is inserted along the length of the drill string section 1b. The waveguide 115 has an outer, wave-transmitting section 111 and a reflective inner shield 112 which together channel signal energy from ATS 110c to ATS 110b between the inner diameter of the drill string section 1b and the reflective shield 112. The transmission medium can be a solid, liquid or gaseous material depending on the type of energy transferred and the available energy. Fig. 12c shows an example of a waveguide 115 with an energy-reflecting inner shield 112 separated by axial ribs, or spacers, 120 arranged around the periphery of the shield 112. For an acoustic transmission system, the waveguide section 111 comprises several liquid-filled channels 122 which is sealed by means of a seal 125 which creates a liquid-filled waveguide which transfers the acoustic energy from ATS 110c to ATS 110b. The reflective screen 112 may consist of a composite material with microbeads (not shown) embedded inside. The micro-beads have entrapped air and serve to provide an acoustic impedance boundary layer that internally reflects the transmitted acoustic signal to retain the signal within the waveguide channel. By effectively capturing all the transmitted acoustic energy within the channel, the signal is not subject to significant attenuation that would occur if the wave was transmitted as a normal spherical wave from source to receiver. Such normal transmissions are subject to exponential signal energy loss with distance from the source location. Alternatively, the channel 122 can be filled with a gas, for example air, and the signal is transmitted as an RF signal. The reflective shield 112 may be a metal shield to reflect the RF energy back into the waveguide channels 122. The gas-filled channels will provide greatly reduced attenuation as opposed to RF signals being transmitted through the surrounding formation. In an alternative waveguide embodiment, see fig. 12D, the waveguide section 120 is sandwiched between the reflective screen 121 and the drill string section 1b. For an acoustic transmission, the transmission section 120 can be an elastomeric material such as rubber. It is known in this area that the acoustic impedance of rubber is approximately as great as the corresponding impedance of water and oil. With reference to fig. 12A, therefore, if an acoustic transmitter in the ATS 110c transmits into the drilling fluid 11 surrounding the transmitter, the signal will readily enter a rubber transfer section 120 and propagate along the waveguide, provided that the reflective shield 121 has an acoustic impedance, so that the acoustic energy is captured in the transmission section 120. As previously described, the inclusion of gas-filled microbeads in the reflective screen 121 provides an acoustic impedance match, so that the acoustic signals are reflected back into the transmission section.

In a further example, RF energy can be channeled through a solid insulator layer 120, see fig. 12D, in which a suitable reflective shield prevents the RF signal from escaping from the waveguide 115. As will be appreciated by one skilled in the art, there is no attenuation associated with the transmission through the insulating material, but the signal energy is concentrated in the waveguide 115 and is not subjected to the geometric dispersion associated with free transmission through the surrounding media.

In a further preferred embodiment, optical fibers can be introduced into a sleeve and brought into close proximity to light-emitting devices in the ATS of the adjacent connection. Because the transmission distance is short, even a low energy optical source can provide sufficient received light energy to be received by the superfluid media boundary layer. The fluid boundary layer may contain drilling fluid. Alternatively, the gap can be a controlled environment containing fluid with suitable optical properties for transmission.

In a preferred embodiment, back-reflection methods can be used to transmit signals over splices. In one example, an oscillating circuit signal is passed through the conductors in an elongated sleeve, sleeve 61 in FIG. 6, for example, in a first section of the drill string affected by an inductive load in the ATS in the adjacent connection to a second drill string section. By switching the inductive load in the ATS between two states, a change can be detected in the oscillating circuit signal in the first section and thereby transmit information over the connection.

In a further preferred embodiment, it is known that changes can be imposed on the polarization characteristics of light traveling in an optical fiber by changes in a magnetic field near the optical fiber. An ATS is adapted to modulate a local magnetic field to modulate light traveling in an optical fiber in a sleeve attached to an adjacent section of drill string.

It is an object of the present invention to provide a fault-tolerant, moderate fault communication system for use in a drilling system and/or completion system in a borehole. The character of the particular communication system is to a large extent dependent on the transmission characteristics of the surrounding formations and the drilling fluid in the borehole. The concepts described below enable such communications between drill pipe lengths using low energy levels. Depending on the type of communication link used, one of several network structures and operational configurations can be used. The nature of the communication devices chosen will determine the practicability of a given network type.

In a preferred embodiment, the communication link is a series system and

transmits at least one of, see fig. 9, (i) a short pin-to-socket transfer stretch across a joint 4a (about 3 mm to 10 cm) 86; (ii) from joint 4a to joint 4b (order of magnitude 10 to 15 m) 87; and (iii) over more than one splice, for example from 4a to 4c (about 18 to

27 m) 89. Software instructions stored in the well controller of each ATS control communications from each ATS to the next and only allow those splices that

are needed become active, to enable apparently continuous communication along the borehole or pipe string. For example, each ATS can have a unique address for communication and the installation order can be controlled, so that each ATS in the system

knows the addresses of the adjacent ATS. The system will attempt to provide transmission over the longest distance that allows acceptable transmission integrity. Initially, the system may undergo an initial adaptive learning mode of transmitting known predetermined signals sequentially from each ATS to the next in sequence. By, for example,

determine that ATS 20c receives the same signal from ATS 20a and ATS 20b, the ATS can instruct ATS 20b to enter a passive mode and transmit only when ATS 20b has new data, such as local sensor data, to transmit. If the signal integrity between ATS 20a and 20c drops below an acceptable, predetermined level, ATS 20c can instruct ATS 20b to start transmitting information from ATS 20c. In addition, in the event that no communication is established, the ATS can, according to programmed instructions, change its transmission parameters, such as lowering the transmission frequency, for example. ATS can cycle through several sequences to search for appropriate communication. Interruptions in signal transmission can result in data stacking, while data or

signals to be retransmitted are stored in a buffer memory. Such data can be transferred at a later date or maintained in buffer memory for retrieval at the surface for both data and diagnostic purposes. Signal integrity can be determined

from different transmission parameters including but not limited to received signal level and data loss. In addition, each ATS can include in its data stream status signals regarding the relative "health" of the ATS. For example, each ATS can transmit information regarding its energy storage status and/or its energy generating status. If, for example, ATS 20b is in a passive mode and receives status information indicating that ATS 20 has a low energy, ATS 20b may, according to programmed instructions in its controller, begin transmitting signals received from ATS 20a including the low energy status of ATS 20a to notify the rest of the network, including the surface system, of the status of the ATS 20a. The surface system alerts the operator who may wish to take corrective action, such as replacing the ATS 20, the next time the drill string is removed from the borehole.

The system described above provides a mainly serial communication network. To improve fault tolerance and moderate fault checks, in a further preferred embodiment, multiple parallel communication paths are included along each of the sections of the serial path. As shown as an example in fig. 10A, B, an ATS 95 has several telemetry modules 90a-h enclosed in the ring 91 suitable for insertion into a threaded connection as previously described. Each module 90a-h has a receiver, a transmitter, and a controller with a processor and memory. Each module 90-h may also contain or be connected to one or more sensors for detection of a parameter of interest. The module 90a-h can be connected to an energy source as previously described. Each module 90a-h can be connected to a separate energy source, or they can alternatively be connected to a central energy source. Any of the previously described energy sources can be used. Each of the modules works to establish a separate communication link with similar modules at each connection point. Examples of such modules are described in US patent application serial number 10/421475, filed April 23, 2003 (Baker Hughes Incorporated) and incorporated herein by reference. The multiple telemetry modules 90a-h may be configured to carry at least one of (i) independent data streams, (ii) redundant data streams, and (iii) multiple paths for a single data stream, thereby providing higher bandwidth for the data stream. The multiple telemetry modules can be controlled under local program control to allow moderate error control of bandwidth during periods of high demand, energy constraints and partial system failure. For example, a hierarchy protocol can be established that directs a particular telemetry module to be a master module that controls the transmissions of the slave modules at each ATS location. The protocol provides a predetermined order of data transmission if the master module or any other of the slave modules fails. The protocol also provides a hierarchical list of data streams, so that the link capacity is reduced, for example, in the event of a module failure. An example data stream can contain measurements related to well pressure, well temperature and vibration. It is known that in most cases vibration data is significantly more variable over time than the equivalent for temperature. If therefore the transmission bandwidth is reduced, for example the predetermined protocol can reduce the transmission of temperature data in order to maintain suitable transmission of vibration data. Note that any number of telemetry modules that can be conveniently packed into the available space can be used with the present system.

Any of the transfer methods discussed above can be used together with the parallel transfer methods. For example, multiple transmission frequencies can be used with acoustic, RF and EM transmissions, and wavelength division multiplexing is common for sending multiple signals over optical systems.

The serial capability of transmission over one or more sections, as described above, coupled with the parallel communication methods, adds substantial reliability to the communication of information along the interconnected string of pipes.

Any of the autonomous telemetry stations described above may contain one or more sensors for detecting parameters of interest related to the ATS or the local environment. Such measurements can be added to signals that pass through the ATS or that are alternatively to be transmitted by the ATS itself. Such sensors include but are not limited to (i) pressure sensors to measure pressure of drilling fluid inside and/or outside the drill string (ii) temperature sensors to measure the temperature of drill string and/or drilling fluid; (iii) vibration sensors to measure local drillstring vibration; (iv) sensors to measure parameters related to the proper operation of the ATS such as electrical voltage and/or amperage levels. In addition, the digital diagnostic status of the processor can be transferred.

In a further preferred embodiment, an ATS can communicate with permanently installed devices, for example in a production line. Such devices can be passive devices that derive their energy from the signal transmitted by the ATS, or the devices can have batteries or energy extraction devices as described herein.

In a further preferred embodiment, an independent sensor module with several sensors can be installed in the drill string 3, such as a formation evaluation device (not shown) and/or a device for measuring the load of the drill string section at a predetermined location. Examples of such devices are described in US patent application serial number 10/421475, filed April 23, 2003 (Howard Hughes Incorporated), and previously incorporated herein by reference. Such devices can be adapted to communicate with and/or through the ATS network as previously described. Alternatively, such a system can have its own primary telemetry capacity, such as a sludge pulse system, and the described ATS system is used as a reserve system when such primary systems fail.

The preceding description is described with reference to a drilling system. However, it is intended that the method and systems described may be applied to substantially any pipeline system, including but not limited to (i) production systems, including multilateral systems, and including offshore and subsea systems; (ii) water wells; and (iii) pipelines which include surface, well and subsea pipelines.

All of the systems described above are intended to enable two-way communication between at least (i) multiple ATS devices, (ii) a surface controller and ATS devices, and (iii) ATS devices and remotely located well devices . Such surface generated signals can be used to download instructions, including commands, to any and/or all ATS devices. Such transmissions include, but are not limited to, instructions that may (i) cause changes in the operating format of an ATS, (ii) cause the ATS to issue a command to a remotely located device, such as a well valve in a production string, and ( iii) cause the system to re-establish the preferred communication path. In addition, an externally located device, such as a well controller in a production string, can direct a signal to a further externally located device, such as a valve, through the network of ATS devices.

In a further preferred embodiment, see fig. 16A, B, the pipe string member 161 has a cross-sectional area substantially smaller than the inner diameter of the drill pipe section 160 and is placed inside each section of the drill pipe 160. The length of the pipe string member 161 is predetermined so that it extends substantially over the length of the section 160, but does not interfere when drill pipe sections are connected. When the sections of drill pipe are connected together, the pipe string elements 161 form a waveguide for two-way surface-to-well communication via electromagnetic, optical and/or acoustic energy. The conduit element 161 provides and/or contains all or part of the transmission medium for communication along the length of the section 160. For example, the conduit element 161 may contain one or more electrical conductors 162 and/or optical fibers 165. In one embodiment, at least one optical fiber 165 fixed inside the tube string element 161, which is fixed to the section 160. Optical fiber 165 is used to determine the load on the optical fiber 165 caused by the axial load on the section 160. The optical fiber load can then be related to the load on the section 160 using of analytical and/or experimental methods known in the field. Such optical load measurements can be carried out using known methods. For example, at least one fiber Bragg grating may be located in the optical fiber 165. The Bragg grating reflects a predetermined wavelength of light, related to the spacing of the Bragg grating. As the load on section 160 changes, the spacing of the Bragg grating changes and results in changes in the wavelength of light reflected therefrom, which is related to the load on section 160. The optical components for such a measurement may be located in the electronics 164 in each pipe string element 161 and the results can be telemetered along the communication system. Any other optical loading method is suitable for the purposes of the invention. Alternatively, the tube string element 161 may provide a waveguide path for acoustic and/or RF transmission. Such a waveguide, when firmly attached to section 160, can be used to provide a load indication on section 160.

For example, an acoustic or RF pulse can be transmitted along the waveguide from one end and reflected back from the other end. Changes in the time of flight of the signal can be related to changes in the length of the section 160 using analytical and/or experimental methods known in the art. Electronics 164 and transceiver 163 are located at each end of each pipe string element 161 for communicating to and receiving signals from ATS 162.1 a preferred embodiment, for example, ATS 162 can receive a signal from transceiver 163c, add data to the signal as needed, and on retransmit the signal to the transceiver 163b for transmission along the pipe string member 161a using any of the above transmission media. In order to energize the electronics 164 and the transceiver 163, associated with which communications, the system also provides devices, as previously described, for extracting energy from available energy sources as previously described. The energy source can be integrated into the pipes used for communication or provided by other pipes or systems close to the communication pipe being energized. An example would use a piezoelectric material along the length of the tubing string member 161 to generate a voltage from the dynamic pressure variations and/or turbulent eddies that occur in the drilling fluid flow as a result of surface pump pulsations and/or flow disturbances in the drilling fluid flow. The pipe string member 161 may be positioned substantially against the circumference of the inner diameter of the drill pipe 160. The force to hold the pipe in position may be provided by mechanical devices, such as by means of arc springs known in the field, or by means of a magnetic force provided of magnets distributed along the length of the pipe, or by means of other means such as adhesives, etc. The pipe string element 161 can also be placed mainly centrally in the drill pipe using arc spring centralizers (not shown) or other known devices. The tube can be made from a metal or be made from a plastic material or composite material, such as polyetheretherketone. Communication between the tubes can be achieved using electromagnetic, acoustic, optical and/or other methods described in the preceding and which are passed through the ATS 162. Alternatively, the signals can be transmitted from a transceiver 163 directly to a further transceiver in an adjacent tube 163.

In a preferred embodiment, see fig. 17A-B, a micro turbine generator (MTG) is integrated into the ATS 172 to provide energy to the ATS 172. The MTG comprises a substantially cylindrically shaped rotor 179 with a number of turbine blades 175 formed on an inner diameter of the rotor 179. The turbine blades 175 interrupt a portion of the flow of drilling fluid 177 and causes the rotor to rotate as indicated by arrow 176 about the center of the drill string section. The rotor 179 is supported by bearings 174 and has a number of permanent magnets 178 arranged around the circumference of the rotor 179. The magnets are preferably polarized as shown in fig. 17B and has magnetic field flux lines 169 extending from each surface. The magnets 178 may be of any suitable shape, including but not limited to bar magnets and disk magnets, also referred to as button magnets. The magnets are arranged around the periphery of the rotor 179, so that alternating positive and negative surfaces and their magnetic fields are passed by at least one stationary electrically conductive coil 173 in the ATS 172 and generate alternating voltages therein. More than one coil may be located in the ATS 172. Appropriate circuitry, known in the art, is located in the ATS 172 to convert the alternating voltages into usable energy for the sensors and transceivers located in the ATS 172 and previously described. The amount of energy generated by such an MTG can be determined from methods known in the art without undue experimentation. The rotor 179 can also be made of at least one of ceramic, metallic and elastomeric material. The bearings 174 may be made of at least one of ceramic materials, including diamond-coated and elastomeric materials. Such bearings are known in the field and shall not be described in further detail. In a system that uses several parallel transceivers at each ATS, such as the one described, for example, in fig. 10A, 10B, each individual telemetry module may have its own coil to generate energy from the rotating magnets.

Alternatively, in a further preferred embodiment, see fig. 18, provides MTG 184 energy to several telemetry stations, for example ATS 181, 182,183. The MTG as described above generates an alternating current (AC) voltage which may be inductive, coupled to conductors (not shown) in the sleeves 186 a-d. As is known in the art, alternating current passing through a coil will produce a related time-varying magnetic field. Conversely, a time-varying magnetic field acting on a coil or wire conductor will produce a time-varying current in the coil. Two such coils may be positioned in suitable proximity to transfer energy from one coil to the other. Energy transfer can be affected by various factors, including but not limited to the size of the transfer coverage, dielectric properties of the constituent materials, number of coil turns and coil diameter. The magnetic field can be shaped and/or reinforced by using different magnetic core materials such as ferrite. Such methods are known in the field and are not discussed here in detail. Each sleeve 186 a-d has an inductive coupling at each end 185a, b and transfers energy to and/or through each ATS 181-183. Each ATS may extract the AC voltage for internal conversion and use it to power each ATS and the sensors, as previously described, attached to each ATS. The raw voltage, as generated, may be inductively coupled along the conductors in the sleeves 186a-d. The sleeves 186a-d can be any of the previously described sleeves, for example in fig. 6-8B and 16A, B, or may be any other suitable sleeve and conductor combination. Alternatively, the voltage can be conditioned using circuitry (not shown) in the ATS 181 to change the voltage and/or frequency to improve the inductive coupling efficiency. The applicable distance between adjacent MTG 184 units is application specific and depends on factors including but not limited to the types and energy requirements of the sensors, the efficiency of the inductive coupling, and the losses in the conductors.

In a preferred embodiment comprises a further energy source, see fig. 19, a sleeve 191 which extends over substantially the length of a section of the drill string 190. The sleeve 191 is a sacrificial anode separated from the section 190 by means of a suitable electrolytic material 192, so that a galvanic cell is established which runs along the length of the sleeve 191. Such a cell can be designed to provide predetermined amounts of energy using known methods in this area. The generated voltage depends on the materials of the sleeve and the drill pipe section and the total current capacity is related to the conductivities of the sleeve 191 and the electrolytic gel 192 and the contact area between the sleeve and the gel, which is related to the length of the sleeve. The sleeve may be installed using any of the previously described methods, for example, expansion of such a sleeve 191 into contact with the section 190 while retaining the gel 192 therebetween. Suitable circuitry (not shown) may be embedded in the ends of such sleeve 191 to convert the generated voltage to any suitable voltage needed. In addition, such a circuit system can be used to convert DC energy to AC energy for use in inductive coupling of such energy to adjacent sections of drill string.

In a preferred embodiment, see fig. 20, an insulating sleeve 204 is inserted between the drill string section 200 and the cathode 203. The electrolytic gel 202 is sandwiched between the cathode 203 and the anode 201 forming a galvanic cell. The use of a separate cathode 203 isolated from the drill string section 200 provides more freedom in the selection of the cell materials and cell voltage. The electrolytic gel in fig. 19 and 20 may be embedded or retained in a suitable open-cell grid and/or honeycomb material (not shown) to prevent the gel from being extruded from the space between the anode and cathode materials during installation and operation.

Any of the previously described battery configurations can be configured, using methods known in the art, to be rechargeable using suitable materials. Any of the energizing devices or MTG can be used for recharging such a battery system. Such a battery would at least be capable of providing energy during non-drilling and/or non-production periods and could be recharged once such activity resumes.

In a preferred embodiment, see fig. 21, an instrumented subassembly 210, or adapter pipe, is installed in the drill string between sections 215 and 216. The subassembly 210 has, for example, sensors 212 and 217 mounted on an outer and an inner diameter, respectively. Although they in fig. 21 are shown as single sensors 213 and 217, several sensors can be mounted on the inside and/or outside diameters of the subassembly 210. These sensors include but are not limited to (i) pressure sensors, (ii) temperature sensors, (iii) load sensors, (iv) chemical species sensors, (v) fluid resistivity sensors, and (vi) fluid flow sensors. Sensors 212 and 217 may be powered by the ATS 211 and interfaced through the electronics module 213 attached to the subassembly 210. The electronics module 213 may communicate to adjacent ATs 211, in one direction or the other, using any of the previously discussed communication methods . Several sub-assemblies210 can be inserted into the drill string at predetermined locations. The locations are application-specific and may depend on factors such as the desired measurement and spatial division along the length of the drill string. In addition, the subassembly 210 can have a transceiver (not shown) located on an outer diameter for communication with and/or interrogation of sensors or other devices mounted on production pipes, and/or production hardware. In addition, such an external transceiver can be used to communicate with and/or interrogate devices in lateral branches of multilateral wells in both drilling and production environments. In an example, see fig. 23, the subassembly 253 is arranged in a drill string (not shown) in a substantially horizontal borehole 250 has several sensors 254 attached to an outer diameter of the subassembly 253. Drilling fluid 251 and inflow fluid 252 flow past the subassembly 253 and form a combined multiphase fluid, where multiphase refers to to at least one of (i) an oil-drilling fluid mixture, (ii) than a drilling fluid-gas mixture, and (iii) a drilling fluid-oil-gas mixture. The effects of gravity will try to cause separation of the fluids into fluids 251 and 252. The fluid 252 may be a gas, water, oil or some combination thereof. The sensors 254, for example, can measure the resistivity of fluid passing in close proximity to each sensor 254, so that a cross-sectional profile related to the fluid composition near each sensor is provided. These measurements are communicated to the surface using the methods according to the present invention. Changes in the profile can be used to detect changes in the quantity and composition of the fluid inflow that passes a measuring station along the borehole. Such measurements can, for example, be used to monitor the placement of specialist drilling fluids and/or chemicals, usually referred to as mud plugs, at a desired location in the borehole. In addition, several cross-sectional profiles can be measured and compared to determine the changes in the profiles along the borehole.

As previously described, optical fibers can be incorporated into the sleeves described in fig. 6-8 and the pipes described in 16A, B for communication between automated telemetry stations. The use of optical fibers can provide high bandwidth with relatively low signal loss along the fiber. The main obstacles to the use of optical fibers in such an application include forming optical connections at each ATS and the losses associated with optical connectors. As a person skilled in the art will realize, it is not operationally possible to ensure alignment of the fibers in line when the separate tube elements are threaded together as shown in fig. 22C. Fig. 22A and B show a preferred embodiment of a system for providing optical coupling to optical fibers that are not aligned and/or not in close enough proximity to use direct coupling. Tube sections 225a-b are connected by threaded connection 224. Optical fibers 223 and 222 are attached to an inner diameter of sections 225a and 225b respectively and form part of an optical communication channel. An ATS 220 is placed in the back drilling area 230. The ATS 220 contains sensors as previously described and an optical transceiver 233 for boosting the optical signal that is transmitted along the optical communication channel. The optical transceiver 233 comprises an optical coupler 231 to transmit the received optical signal to an optical receiver 226. The received optical signal is processed using the circuit system 230 and a processor (not shown). In addition, locally generated signals can be added to the received signal and the combined signal forwarded by the optical transmitter 228 by being sent through the optical coupler 232. The optical signal 234 is sent from the end of the optical fiber 222 to the optical coupler 232 through an optical coupling material (OCM) 221. The OCM 221 may be an optically translucent material so that it transmits sufficient energy to be detected and at the same time dissipates the energy so that the optical fiber 222 and the optical coupler 231 may be rotationally misaligned as shown for optical fibers in fig. 22C. OCM 221 can be made translucent by doping the material with reflective materials. In one embodiment, OCM 221 is a translucent potting material that has sufficient natural diffusion characteristics to provide acceptable light reception at the optical receiver 226. For example, ready-to-translucent silicone potting materials are commercially available and are commonly used in potting electronic devices. The ATS 220 may be encapsulated in the embedding material in a shape corresponding to the backbore cavity 230, but be slightly oversized so that when held in place in the connector 224, the optical fibers 222 and 223 are brought into intimate contact with the OCM 221 and provide optical coupling between the optical fibers 22 and 223 and the optical transceiver 233. Alternatively, any suitable transparent and/or translucent material can be used as OCM 221. In one embodiment, OCM 221 can be doped with a phosphorescent material, so that signal light injected into OCM 221 causes that the phosphorescent material emits light within the OCM 221, which can be detected by the optical receiver in the transceiver 233. The OCM 221 may be a viscous gel-like material that is brushed into the socket section of the connector 224 and has the ATS 220 located therein and retained by the connection of the pin section of the connection 224. The transceiver 233 can be powered by its own energy source 229. Alternatively, the transceiver can a 233 is powered by any of the previously described energy systems. To provide optical communications should the transceiver 233 fail, the optical fiber 236 provides a relatively low-loss optical path for the optical signal 234 to pass from the optical fiber 222 to the optical fiber 223. The attenuation in the OCM 221 is typically substantially greater than through an optical fiber, such as fiber 236, and may not allow such transmission through OCM 221 alone. The combined path has lower attenuation and ensures that at least some optical signal reaches the fiber 223.

While only a single optical transceiver is described here, multiple optical transceivers can be positioned ring-shaped in the ATS 220, similar to the multiple acoustic transceivers described in FIG. 10A, B. In one embodiment, each transceiver is configured to receive and transmit the same light frequency signal. Here, too, a hierarchy can be arranged among these transceivers. Distribution of the incoming signal in the OCM 221 allows transceivers adjacent to a primary transceiver to detect the incoming signal and determine whether the primary transceiver has forwarded the signal. If the primary transceiver fails to transmit the signal, for example within a predetermined time period, one of the adjacent transceivers, according to the programmed hierarchy, takes over the task and transmits the signal.

Alternatively, each of the multiple optical transceivers may receive and transmit a different frequency light. Such a system can provide multiple abundant channels transmitting the same signal. Alternatively, each of the multiple channels may communicate a different signal, with a different wavelength of light, to selected channels with abundant transceivers.

The description in fig. 22A, B refer to a one-way signal. It will be clear to one skilled in the art that bidirectional signals can be transmitted along the optical communication path by incorporating optical transceivers for transmission in both directions. Such a system may include multiple optical fibers extending along each section with signals traveling in only a single direction in each individual fiber. Alternatively, bidirectional signals can be transmitted over a single fiber using a number of methods, including but not limited to time division multiplexing and wavelength division multiplexing. It is intended that for the purposes of the present invention any suitable multiplexing scheme known in the art may be used for two-way transmissions.

More than one physical transmission method may be used to communicate information along the communication network as described herein. For example, an optical system can be used to transmit signals in an optical fiber arranged along a section of the drill string. The signal at each end of the drill string section is transmitted to the next section using, for example, an RF transmission method, as previously described. Any combination of described methods can be used. Alternatively, multiple non-interfering physical transmission methods can be used. For example, acoustic and RF, or RF and optical methods can both be used to transmit information over a connection joint. The use of such multiple methods will increase the probability of transmission over the connecting joint. Any number of such non-interfering methods may be employed. Such combinations can be adapted to the special field requirements by the specialist without extensive experimentation.

The distributed measurement and communication network, as shown herein, provides the ability to determine changing conditions along the length of the well in both drilling and production operations. Several exemplary applications are described below. In a normal drilling operation, sensor information may be available at the surface and close to the drill bit, for example from measurement during drilling MWD devices. Little, if any, information is available along the length of the drill string.

In a drilling operation, during insertion and/or retrieval from the borehole, the load on the drill string is typically measured only at the surface. In awiks wells, and especially horizontal wells, indications of distributed and/or localized stress on the drill string can be used to improve the insertion-retrieval process and to identify locations with high stress that may require remedial measures, such as reclamation. In addition, the use of such real-time measurement data allows the insertion-retrieval process to be automated to a significant extent to ensure that the load on any joint in the string does not exceed the maximum allowable load. In addition, distributed measurements of pressure along the string can be used to maintain the pressure increases and pressure decreases within acceptable limits. In addition, profiles of parameters such as deformation, load and torque can be compared at different time intervals to detect time-dependent changes in the drilling conditions along the borehole.

In long-haul rotary drilling operations, variations in rotational friction can occur

along the length of the drill string limit the torque available at the drill bit. However, it is difficult to correct such a problem without knowing where the desired resistance occurs. The distributed sensing system provides profiles of localized torque and vibration measurements (both axial and eddy) along the drill string that enable the operator to identify problem locations and take corrective action, such as installing a roller assembly in the drill string at a point of high resistance. Such profiles can be compared at different time intervals to detect time-dependent changes, such as the build-up of drilling cuttings and other operational parameters.

In rotary drilling applications, the drill string has been shown to exhibit axial, lateral and vortex dynamic instabilities that can damage the drill string and/or well equipment and/or reduce the rate of penetration. The different vibration modes along the drill string are complicated and cannot be easily distinguished from just endpoint measurements (surface and well measurements). Distributed vibration and eddy measurements from the present invention are telemetered to the surface and processed by the surface controller to provide an enhanced picture of the dynamic movement of the drill string. The operator can then, with the help of suitable drilling dynamics software in the surface controller, be guided to modify drilling parameters to control the vibration and swirl of the drill string.

In a further application, the drill string may become stuck in the drill hole during normal drilling operations and stress and/or strain measurements along the drill string then allow determination of the location where the drill string is stuck and allow the operator to take corrective measures known in this field.

In a further embodiment, pressure and/or temperature measurements are made at the sensors distributed along the length of the drill string. Profiles of such measurements along the length of the well can be monitored and used to detect and control well inflows, also known as "well kick". As one skilled in the art will appreciate, as a gas inflow rises in the borehole it expands as the local pressure is reduced to a normal pressure gradient of the drilling fluid in the borehole annulus. If the surface well control I valves are closed, a closed volume system is created. As the bubble rises, it expands and the pressure at the bottom of the borehole increases, causing possible unwanted fracturing along the open hole for the borehole. By detecting the pressure in the annulus using the distributed sensors, the location of the bubble and the associated pressures along the borehole can be determined and allow the operator to release the surface pressure, so that the bottomhole pressure is prevented from shipping the formation.

As is known in this field a borehole traverses several producing formations. The pressure and temperature profiles of the distributed measurements according to the present invention can be used to control the equivalent circulating density (ECD) along the borehole and prevent damage due to overpressure in the annulus near each of the formations. In addition, changes in the pressure and temperature profiles can be used to detect fluid inflows and outflows at the multiple formations along the borehole. In a further example, such distributed pressure and temperature measurements can be used to control an artificial lift pump placed down the well to maintain predetermined equivalent circulating density ECD in multiple formations. An example of such a pump system is shown in published US patent application 2003 00 98181 A1, published May 29, 2003, which is incorporated herein by reference.

In one embodiment, sensors such as that described in US Patent Application Serial No. 10/421475 filed April 23, 2003 (Howard Hughes Incorporated) and previously incorporated herein by reference, are attached to the outside of the casing as it is inserted into the borehole to monitor parameters related to the cementing of the casing in the borehole. Such sensors may be self-powered with limited battery life for the typical duration of such operation, estimated to be approximately 100 hours. The sensors can be adapted for acoustic transmission through the casing to autonomous telemetry stations mounted on a pipe string within the casing. Distributed pressure and temperature sensors provide information related to the placement and solidification of the cement in the annulus between the casing and the borehole.

It is intended that the methods described herein, including the profile mapping, can be used for any production system, including production wells, pipelines, injection wells and monitoring wells.

The preceding description is directed to particular embodiments of the present invention for illustrative and explanatory purposes. However, it will be clear to a person skilled in the art that many modifications and changes to the embodiments listed above are possible and it is intended that the subsequent patent claims should be interpreted to include all such modifications and changes.

Claims (19)

1. Communication system for use with a jointed drill string (3) in a borehole (2), comprising: a tubular drill string (3), wherein the tubular drill string (3) has a plurality of sections connected by means of a plurality of connecting joints (4); and further characterized in that an autonomous telemetry station (20) is arranged in each of said plurality of connecting joints (4), the autonomous telemetry station (20) being arranged to receive a first signal and send a second signal related to said first signal. 2. System according to claim 1, characterized in that the autonomous telemetry station (20) comprises: a receiver (25) for receiving said first signal; a transmitter (23) for transmitting said second signal; a controller (24) with a processor and a memory, the controller (24) operating according to programmed instructions to control the receiver (25) and the transmitter (23) according to a predetermined protocol; and an energy source for supplying energy to said autonomous telemetry station (20). 3. System according to claim 2, characterized in that the energy source is arranged to draw energy from a potential well energy source near the aforementioned autonomous telemetry station (20). 4. System according to claim 2, characterized in that it further comprises an extension pipe (41) connected to the aforementioned autonomous telemetry station (20), the extension pipe (41) extending over a predetermined stretch along a section of the tubular drill string (3). 5. System according to claim 4, characterized in that it further comprises a conductor embedded in said extension pipe (41). 6. System according to claim 2, characterized in that the receiver (25) and the transmitter (23) are arranged to communicate using at least one of (ii) an acoustic transmission, (ii) a radio frequency transmission, (iii) a low frequency electromagnetic transmission, (iv) an optical transmission -conduction, (v) an inductive back-reflectance transmission. 7. System according to claim 2, characterized in that each autonomous telemetry station (20) has a distinctive communication address. 8. System according to claim 2, characterized in that it further comprises a well tool and a surface controller (15). 9. System according to claim 2, characterized in that it further comprises an instrumented subassembly (210) arranged between at least two of said plurality of sections (215, 216), the instrumented subassembly (210) comprising a second sensor (212) to detect at least a second parameter of interest. 10. Method for communicating along a joined drill string (3) in a drill hole (2), comprising: - a tubular drill string (3) is extended into the drill hole (2), the tubular string (3) having a plurality of sections connected by by means of a plural connecting conjunction (4); and further characterized in that - an autonomous telemetry station (20) is placed close to each said plurality of connecting joints (4), the autonomous telemetry station (20) being arranged to receive a first signal and transmit a second signal related to said first signal. 11. Method according to claim 10, characterized in that the autonomous telemetry station (20) comprises: - a receiver (25) to receive said at least one first signal; - a transmitter (23) for transmitting said at least one second signal; - a controller (24) with a processor and a memory, the controller (24) operating according to programmed instructions to control said receiver (25) and said transmitter (23) according to a predetermined protocol; and an energy source for supplying energy to said autonomous telemetry station (20). 12. Method according to claim 10, characterized in that the energy source is arranged to draw energy from a potential well energy source near the aforementioned autonomous telemetry station (20). 13. Method according to claim 11, characterized in that it further comprises an extension pipe (41) connected to the aforementioned autonomous telemetry station (20), the extension pipe extending over a predetermined distance along a section of the tubular drill string (3). 14. Method according to claim 13, characterized in that it further comprises a conductor embedded in said extension tube (41). 15. Method according to claim 11, characterized in that the receiver (25) and the transmitter (23) are arranged to communicate using at least one of (i) an acoustic transmission, (ii) a radio frequency transmission, (iii) a low frequency electromagnetic transmission, (iv) an optical transmission , (v) an inductive back-reflection transmission. 16. Method according to claim 11, characterized in that each autonomous telemetry station (20) has a distinctive communication address. 17. Method according to claim 11, characterized in that it further comprises a well tool and a surface controller (15). 18. Method according to claim 11, characterized in that each of the autonomous telemetry stations (20) at each of the number of connections in the pipe string operates according to programmed instructions to adaptively determine which autonomous stations (20) provide an acceptable data path. 19. Method according to claim 11, characterized in that the autonomous telemetry station (20) comprises a plurality of autonomous telemetry stations, in each of said autonomous telemetry stations (20) a connection provides a separate communication channel according to a predetermined protocol.