CN109899059B - Drill string communication systems, components, and methods - Google Patents

Abstract

Drill string communication systems, components, and methods are described. The uphole transceiver may couple the signal to the drill string at a power that may be greater than, and in some embodiments is always greater than, the selectable power for the downhole signal. Communication from the drilling rig to the subterranean tool may be resumed using the maximum uphole transmission power of the uphole transceiver. The program may establish a new set of transmission parameters for the drill string signal to establish communication between the drilling rig and the subterranean tool. The system may include a ground walking positioner that receives electromagnetic positioning signals that activate/deactivate state control. The reconfiguration command may modify the positioning signal in response to the positioning signal attenuating. The downhole transceiver and the uphole transceiver may automatically modify at least one parameter of the downhole signal. The borehole receiver may apply a compensation response to the transmitted signal to compensate for the drill string channel transfer function.

Description

Drill string communication systems, components, and methods

The present application is a divisional application of patent application with application number 2013100015248, application date 2013, 1-4, and the title of the invention "drill string communication system, components and methods".

RELATED APPLICATIONS

The present application claims priority from U.S. provisional patent application Ser. No. 61/583,591, filed on 1/5/2012, which is incorporated herein by reference in its entirety. The present application also claims priority from U.S. patent application Ser. No. 13/733,097, filed on 1/2 of 2013, which is incorporated herein by reference in its entirety.

Technical Field

The present application relates generally to subsurface (inground) operations, and more particularly, to a system, apparatus, and method including an advanced drill string communication system that couples electrical signals to an electrically conductive drill string for data transmission while providing compensation for at least noise and distortion effects. Ground Walkover locator (Walkover locator) communications can be supported in whole by the system and related methods.

Background

Typically, subterranean operations, such as drilling a well to form a borehole, then reaming the borehole for installation of a utility, borehole mapping, and the like, use an electrically conductive drill string extending from a drilling rig at the surface. The prior art includes examples of using an electrically conductive drill string as an electrical conductor for electrically conducting data signals from a subterranean tool to a drilling rig. The surrounding land itself serves as a signal return path for detecting signals at the rig. This type of system is commonly referred to as a Measurement While Drilling (MWD) system. However, applicants have appreciated that there remains a need for improvements in MWD systems.

The above examples of the related art and the limitations related thereto are illustrative and not exclusive. Other limitations of the related art will become apparent to those of skill in the art upon a reading of the specification and a study of the drawings.

Disclosure of Invention

A drill string communication system is described. The uphole transceiver may couple the signal to the drill string at a power that may be greater than, and in some embodiments is always greater than, the selectable power for the downhole signal. Communication from the drilling rig to the subterranean tool may be resumed using the maximum uphole transmission power of the uphole transceiver. The program may establish a new set of transmission parameters for the drill string signal to establish communication between the drilling rig and the subterranean tool. The system may include a ground walking positioner that receives electromagnetic positioning signals that activate/deactivate state control. The reconfiguration command may modify the positioning signal in response to the positioning signal attenuating. The downhole transceiver and the uphole transceiver may automatically modify at least one parameter of the downhole signal. The borehole receiver may apply a compensation response to the transmitted signal to compensate for the drill string channel transfer function.

The following embodiments and aspects thereof are described and illustrated in conjunction with systems, tools, and methods which are meant to be exemplary and illustrative, not limiting in scope. In various embodiments, one or more of the above-described problems have been reduced or eliminated, while other embodiments are directed to other improvements.

In one aspect of the disclosure, a drill string communication system, related apparatus, and method are disclosed. The drill string communication system uses a drill string extending from a drill rig to an inground tool as an electrical conductor to provide communication between the drill rig and the inground tool. An uphole transceiver is located at the drilling rig and includes an uphole transmitter that couples an uphole signal with uphole transmission power to the drill string for transmission to the subterranean tool. The downhole transceiver is located downhole proximate to the subterranean tool and includes a downhole transmitter that couples a downhole signal to the drill string for transmission to the drill string at the drilling rig at a downhole transmission power that is selectable within a downhole power transmission range and that is always greater than any selected downhole transmission power within the downhole power transmission range.

In another aspect of the disclosure, a method and related apparatus for operating a drill string communication system that uses a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool is described. In response to loss of reception of a downhole signal transmitted from the subterranean tool to the drill string using the current set of transmission parameters, communication from the drilling rig to the subterranean tool is restarted using the uphole transceiver at a maximum uphole transmission power of the uphole transceiver to couple the uphole restart signal to the subterranean tool. Based on the response from the subsurface tool to the uphole restart signal, a program is entered to establish a new set of transmission parameters for at least one of the downhole signal and the uphole signal to thereafter establish communication between the drilling rig and the subsurface tool.

In another aspect of the disclosure, a drill string communication system and associated method are described that use a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool. An uphole transceiver is located at the drilling rig and includes an uphole transmitter that couples an uphole signal with uphole transmission power to the drill string for transmission to the subterranean tool. A downhole transceiver is located downhole proximate the subterranean tool and includes a downhole transmitter that couples a downhole signal to the drill string for transmission to the drill string at the drilling rig at a downhole transmission power selectable within a downhole power transmission range and emits an electromagnetic positioning signal having at least one selectable operating parameter. The ground walking locator receives the electromagnetic locating signal and detects a predetermined attenuation of the received locating signal, and in response to detecting the predetermined attenuation, the system is configured to automatically generate a reconfiguration command that changes at least one of the following parameters of the electromagnetic locating signal: carrier frequency, transmission power, baud rate, and modulation mode.

In another aspect of the disclosure, a drill string communication system and associated method are described that use a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool. An uphole transceiver is located at the drilling rig and includes an uphole transmitter that couples an uphole signal with uphole transmission power to the drill string for transmission to the subterranean tool. A downhole transceiver is located downhole proximate the subterranean tool and includes a downhole transmitter that couples a downhole signal to the drill string for transmission to the drill string at the drilling rig at a downhole transmission power selectable within a downhole power transmission range and emits an electromagnetic positioning signal having at least one selectable operating parameter. The portable ground walking positioner receives the electromagnetic positioning signal and detects the reception loss of the electromagnetic positioning signal, and automatically indicates to the drilling machine the signal loss condition in response to the reception loss.

In another aspect of the present disclosure, a drill string communication system and related method use a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool. An uphole transceiver is located at the drilling rig and includes an uphole transmitter that couples an uphole signal to the drill string for transmission to the subterranean tool. A downhole transceiver is located downhole proximate to the subterranean tool and includes a downhole transmitter that couples a downhole signal to the drill string for transmission to an uphole receiver forming part of the uphole transceiver. The downhole transceiver and the uphole transceiver are configured to cooperate to automatically change at least one operational transmission parameter of the downhole signal based at least in part on signal attenuation of the downhole signal detected by the uphole transceiver.

In another aspect of the disclosure, an apparatus and associated method are described for use in a drill string communication system that uses a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool. The drill string exhibits a channel transfer function when used as such an electrical conductor carrying downhole signals that are coupled to the drill string through the subterranean tool. The borehole receiver receives a downhole signal from the drill string as a transmission signal, the transmission signal being affected by a channel transfer function, and the borehole receiver is configured to apply a compensation response to the transmission signal, the compensation response being tailored based on the channel transfer function.

In another aspect of the disclosure, a surface step locator and associated method are described for use in a system employing a drill string extending from a drilling rig to an inground tool configured to transmit electromagnetic locating signals. The receiver is configured to receive the positioning signal, detect a received attenuation of the positioning signal, and generate a signal loss command in response to the attenuation detection. The telemetry transmitter is configured to transmit a signal loss command to the drilling rig.

In another aspect of the disclosure, a system and associated method for performing at least subterranean operations is described that uses a drill string extending from a drilling rig to a subterranean tool as an electrical conductor to provide communication between the drilling rig and the subterranean tool. The downhole transceiver is located downhole proximate to the subterranean tool and is configured to (i) receive at least one sensor signal related to an operational parameter of the subterranean tool, (ii) generate a downhole signal, the downhole signal being transmitted to a drill string at the drilling rig, and modulate the downhole signal based on the sensor signal, and (iii) emit an electromagnetic positioning signal for above-ground detection, the positioning signal being at least not modulated by the sensor signal. An uphole transceiver is located at the drilling rig and includes an uphole receiver configured to receive the downhole signals from the drill string and to recover the sensor signals so that information relating to the operational parameters is available at the drilling rig. The ground walking locator receives the electromagnetic locating signal as at least one of a homing beacon and a tracking signal such that the detection range of the locating signal without modulation is greater for a given transmission power than the detection range of a modulated locating signal modulated by the sensor signal for the same given transmission power.

In another aspect of the disclosure, a system and method for performing at least subterranean operations is described that uses a drill string extending from a drilling rig to a subterranean tool as an electrical conductor to provide communication between the drilling rig and the subterranean tool. An uphole transceiver is located at the drilling rig and includes an uphole receiver configured to transmit at least an uphole signal on the drill string to the subterranean tool. A downhole transceiver is positioned downhole proximate to the subterranean tool and is configured to receive the uphole signal from the drill string and to selectively emit an electromagnetic positioning signal for above-ground detection. The ground walker receives the electromagnetic positioning signal and automatically detects an activation/deactivation state of the ground walker, and in response to detecting a change in the activation/deactivation state, the ground walker is configured to transmit a status indication to the drilling machine indicating a new activation/deactivation state. The uphole transceiver and the downhole transceiver are further configured to cooperate to turn off the electromagnetic positioning signal at least in response to the disabled state.

In another aspect of the disclosure, a communication system and related method for use in a system for performing at least subterranean operations is described that uses a drill string extending from a drilling rig to a subterranean tool and a surface walk detector serving as at least one of a homing beacon and tracking device. An uphole transceiver is located at the rig. The downhole transceiver is located downhole proximate to the subterranean tool. The telemetry transceiver forms part of a surface step locator. The first bi-directional communication link between the uphole transceiver and the downhole transceiver uses the drill string as an electrical conductor to provide communication between the uphole transceiver and the downhole transceiver. A second bi-directional communication link between the uphole transceiver and the telemetry transceiver of the surface step locator employs wireless electromagnetic communication between the uphole transceiver and the telemetry transceiver. At least a unidirectional communication link is formed from a downhole transceiver of the subterranean tool to the surface step locator such that (i) a first communication mode is provided from the downhole transceiver via the drill string to an uphole transceiver at the drilling rig using the first bidirectional communication link, (ii) a second communication mode is provided from the downhole transceiver to the uphole transceiver via the unidirectional communication link, a telemetry transceiver at the surface step locator, and the second bidirectional communication link, and (iii) the controller manages communication between the downhole transceiver and the uphole transceiver based at least in part on the system status.

Drawings

Exemplary embodiments are shown in the referenced figures of the drawings. The intent is to indicate: the embodiments and figures disclosed herein are illustrative rather than limiting.

Fig. 1 is an elevational diagrammatic view of a system utilizing the advanced drill string coupling system of the present disclosure.

FIG. 2 is a diagrammatic perspective view of one embodiment of a coupling adapter utilizing a current transformer for coupling signals from and to a conductive drill string.

Fig. 3 is a diagrammatic view of another embodiment of a coupling adapter that forms an electrically isolated gap for coupling signals from and to a conductive drill string.

Fig. 4 is a perspective diagrammatic view of one embodiment of an inground tool in the form of a drill bit and an inground housing connected to an embodiment of a coupling adapter of the present disclosure.

Fig. 5 is a perspective diagrammatic view of another embodiment of an inground tool in the form of a tension monitor and reaming tool connected to an embodiment of a coupling adapter of the present disclosure.

FIG. 6 is a block diagram illustrating one embodiment of an electronic portion that may be used with the coupling adapter of the present disclosure.

FIG. 7 is a block diagram illustrating one embodiment of an electronic portion that may be used at a drilling rig or as part of a drill string repeater that cooperates with a coupling adapter of the present disclosure that serves an inground tool.

FIG. 8 is a block diagram of an embodiment of an advanced bi-directional drill string communication system.

Fig. 9 is an approximation model of a drill string made up of a plurality of removably connected conductive drill pipe sections.

Fig. 10a and 10b are block diagrams of embodiments showing details of an advanced downhole transceiver and an advanced uphole transceiver, respectively.

Fig. 11a is a block diagram of an embodiment of a linear channel equalizer.

Fig. 11b is a block diagram of an embodiment of a decision feedback equalizer.

Fig. 12a and 12b are block diagrams of embodiments of decision-oriented adaptive linear and decision feedback equalizers, respectively.

Fig. 13a is a flow chart of an embodiment of a method for system startup and re-initialization of the present disclosure.

Fig. 13b is a flow chart of an embodiment of a method for dynamically/automatically controlling the transmission of positioning signals.

FIG. 13c is a screen shot showing an embodiment of an appearance indicating the active/inactive state of the positioning signal and the ability to change the current state.

Fig. 14 is a flow chart of an embodiment of a method for collaborative operation of an uphole and downhole transceiver of the present disclosure.

Fig. 15 is a flow chart of an embodiment of a method of communication protocol between a downhole transceiver and a portable locator of the present disclosure.

Fig. 16 is a flow chart of an embodiment of a method for operating a communication controller.

Detailed Description

The following description is presented to enable one of ordinary skill in the art to make and use the invention and is provided in the context of a patent application and its requirements. Various modifications to the described embodiments will be readily apparent to those skilled in the art, and the generic principles taught herein may be applied to other embodiments. Thus, the present invention is not intended to be limited to the embodiments shown, but is to be accorded the widest scope consistent with the principles and features described herein, including modifications and equivalents, as defined within the scope of the appended claims. It should be noted that the drawings are not to scale and are essentially illustrations of the manner in which features of interest are believed to be best illustrated. Descriptive terms may be used in connection with these descriptions, however, the terms are employed for the convenience of the reader and are not intended to be limiting. Further, the drawings are not drawn to scale for clarity of presentation.

Turning now to the drawings, wherein like components are designated by like reference numerals throughout the several views, attention is immediately directed to FIG. 1, FIG. 1 is an elevation view schematically showing one embodiment of a horizontal directional drilling system made in accordance with the present disclosure and designated generally by reference numeral 10. While the illustrated system shows the invention within the framework of a horizontal directional drilling system and its components for performing subterranean drilling operations, the invention enjoys equal applicability with respect to other operational procedures including, but not limited to, vertical drilling operations, pullback operations for installing utilities, mapping operations, etc.

Fig. 1 shows a system 10 operating in a region 12. The system 10 includes a drill rig 14 having a drill string 16, the drill string 16 extending from the drill rig 14 to a boring tool 20a or 20b. It should be noted that for reasons that will become apparent, two examples of the subterranean ends of the drill strings 12a and 12b and the boring tools 20a and 20b are shown. Example of a drill string 16a and boring tool 20a are shown using solid lines, while example of a drill string 16b and boring tool 20b are shown in phantom using dashed lines. It should be appreciated that only a selected one of the two illustrated examples is used during a given subterranean operation. Reference numerals 16 and 20 may be used for general reference to the drill string and the boring tool. The drill string may be pushed into the surface to move at least the inground tool 20 in a forward direction 22 generally indicated by the arrow. While this example is constructed in terms of the use of a drilling tool, it should be understood that the discussion applies to any suitable form of subterranean tool, including but not limited to reaming tools, tension monitoring tools used during pullback operations (where utilities or casings may be installed), mapping tools for mapping borehole paths (e.g., using inertial guidance units and downhole pressure monitoring). In operation of the drilling tool, it is generally desirable to monitor based on the advancement of the drill string, while in other operations, such as pullback operations, it is generally monitored in response to the withdrawal of the drill string.

With continued reference to FIG. 1, the drill string 16 is partially shown and segmented so as to be comprised of a plurality of removably attached individual drill pipe segments, some of which are designated 1, 2, N-1 and N, having a segmented length and wall thickness. The drill pipe sections are interchangeably referred to as drill pipes having a rod length. During operation of the rig, to advance the subterranean tool, drill pipe sections may be added to the drill string one at a time and pushed into the ground by the rig using the movable carriage 24. The drilling rig 14 may include suitable monitoring arrangements to measure movement of the drill string into the surface, for example, as described in U.S. Pat. No.6,035,951 (hereinafter the' 951 patent), entitled "SYSTEMS, ARRANGEMENTS AND ASSOCIATED METHODS FOR TRACKING AND/OR GUIDING AN UNDERGROUND BORING TOOL," which is commonly owned with the present application and hereby incorporated by reference. For example, the stationary ultrasonic receiver 28 may be positioned on the boom of a drilling rig while the ultrasonic transmitter 30 may be positioned on a movable carriage for extending and retracting the drill string. The distance between the receiver 28 and the transmitter 30 may be established in the range of less than one inch. By monitoring this distance in combination with monitoring the status of the clamping arrangement 32 (which acts in response to removing or adding drill rod to the drill string), the length of the drill string can be tracked.

Each drill pipe section defines a through opening 34 (two of which are shown) extending between opposite ends of the pipe section. The drill pipe sections may be mated with what are commonly referred to as box and pin fittings such that each end of a given drill pipe section may be threadably engaged with an adjacent end of another drill pipe section in the drill string in a well known manner. Once the drill pipe sections are joined to form a drill string, the through openings of adjacent ones of the drill pipe sections are aligned to form a general passageway 36 as indicated by the arrows. The passages 36 of each downhole instance of the drill string may provide pressurized flow from the drill rig to the drill bit in the direction of the arrow 36 for drilling fluid or mud, as will be further described.

The location of the boring tool within the area 12 and the subsurface path followed by the boring tool may be established and displayed at the boring machine 14 (e.g., on the console 42) using the display 44. The console may comprise processing means 46 and control actuator means 47. It is noted that the processing means 46 at the drilling rig may comprise a device hereinafter referred to as an uphole transceiver.

The drilling tool 20 may include a drill bit 50, the drill bit 50 having an angled face for use in steering based on a tool face orientation (roll orientation). That is, the drill bit will typically deflect based on the tool face orientation of its angled face when pushed forward without rotation. On the other hand, when pushing the drill string, the drill bit may be generally caused to travel in a straight line by rotating the drill string as indicated by double arrow 51. Of course, the foreseeable diversion is premised on suitable soil conditions. It should be noted that the drilling fluid may be injected as a jet 52 at high pressure in order to pass through the surface just in front of the drill bit and to provide cooling and lubrication to the drill bit. The boring tool 20 includes a subterranean housing 54 that houses an electronics package 56. For the purposes of the following description, the electronic package may be referred to as a downhole transceiver. The subsurface housing is configured to provide for the flow of drilling fluid around the electronics package to the drill bit 50. For example, the electronics package may be cylindrical in configuration and centrally supported within the housing 54. The drill bit 50 may include a box fitting that receives a pin fitting of the underground housing 54. The opposite end of the underground housing may include a box fitting that receives a pin fitting of the coupling adapter 60a or 60 b. It should be noted that two examples of coupling adapters shown by way of non-limiting example are generally indicated by reference numeral 60, it being understood that any suitable embodiment may be employed. The opposite end of the coupling adapter 60 may include a box fitting that receives a pin fitting defining the distal underground end of the drill string. It is noted that the box and pin fittings of the drill bit, the underground housing and the coupling adapter are substantially identical box and pin fittings on the drill pipe sections of the drill string that facilitate the detachable attachment of the drill pipe sections to each other when forming the drill string. The subsurface electronic package 56 may include a transceiver 64, and in some embodiments the transceiver 64 may transmit a positioning signal 66 (e.g., a dipole positioning signal), although this is not required. In some embodiments, transceiver 64 may receive electromagnetic signals generated by other subsurface components, as will be described at appropriate points below. For descriptive purposes, the present example will assume that the electromagnetic signal is a positioning signal in the form of a dipole signal. Accordingly, the electromagnetic signals may be referred to as positioning signals. It will be appreciated that the dipole signal may be modulated like any other electromagnetic signal and that the modulated data may then be recovered from the signal. The localization functionality of the signal depends at least in part on the characteristic shape of the flux field and its signal strength, rather than the ability to carry modulation. Thus, modulation is not necessary. Information about certain parameters of the drilling tool, such as inclination (pitch) and face angle (roll), temperature and drilling fluid pressure, may be measured by a suitable sensor device 68 located within the drilling tool, which sensor device 68 may for example comprise inclination sensors, face angle sensors, temperature sensors, AC field sensors for sensing approximately 50/60Hz utility lines, and any other sensors required, such as DC magnetic field sensors for sensing yaw orientation (triaxial magnetometers, forming an electronic compass together with triaxial accelerometers to measure yaw orientation). The electronics package 56 also includes a processor 70 that interfaces with the sensor device 68 and the transceiver 64 as needed. Another sensor that may form part of the sensor arrangement is an accelerometer configured to detect acceleration in one or more axes. A battery (not shown) may be provided within the housing for providing power.

A ground walking/portable locator 80 may be used to detect the electromagnetic signal 66. A suitable and highly advanced portable positioner is described in U.S. patent No.6,496,008, entitled "FLUX PLANE LOCATING IN AN UNDERGROUND DRILLING SYSTEM," which is co-owned with the present application and is hereby incorporated by reference in its entirety. As noted above, although a horizontal directional drilling framework has been employed for descriptive purposes, the description is applicable to various subterranean operations and is not intended to be limiting. As discussed above, the electromagnetic signals may carry information including orientation parameters (e.g., tilt angle and face angle). The electromagnetic signals may also carry other information. Such information may include, for example, parameters measured proximate to or within the boring tool, including temperature and voltage (e.g., battery or power supply voltage). The positioner 80 includes an electronics package 82. It is noted that the electronics package interfaces with the various components of the positioner for electrical communication and data processing is possible. The information of interest may be modulated onto the electromagnetic signal 66 and transmitted to the locator 80 and/or the antenna 84 at the rig in any suitable manner, although this is not required. Any suitable form of modulation currently available or yet to be developed may be used. Examples of suitable types of modulation currently available include amplitude modulation, frequency modulation, phase modulation, and variations thereof. Any parameter of interest about the well (e.g., dip angle) may be displayed on display 44 and/or as recovered from the positioning signal on display 86 of locator 80. The drill 14 may transmit a telemetry signal 98, and the telemetry signal 98 may be received by the locator 80. Telemetry signals 92 may be transmitted from locator 80 to the drilling rig via telemetry antenna 94. The telemetry component provides for bi-directional signaling between the drill rig and the locator 80. As one example of such signaling, based on the state of the gripping device 32, the drilling machine may transmit an indication that the drill string is in a stationary state as drill pipe sections are being added to or removed from the drill string during which the gripping arrangement is engaged with the drill string.

Still referring to fig. 1, a cable 100 may extend from the inground electronics package 56 such that any sensed value or parameter associated with the operation of the inground tool may be electrically transmitted over the cable. Those of ordinary skill in the art will appreciate that what is commonly referred to as a "wire-in-pipe" may be used to transmit signals to the rig. The term in-line refers to a cable that is received within an internal passage 34 formed by the drill string. However, in accordance with the present disclosure, cable 100 extends to an embodiment of underground coupling adapter 60 or other suitable underground device. As described above, a first embodiment coupled to the boring tool 50a is indicated by reference numeral 60a, and a second embodiment coupled to the boring tool 50b is indicated by reference numeral 60b, as will be described further below.

Attention is now directed to fig. 2 in conjunction with fig. 1. Fig. 2 is a diagrammatic perspective view showing an embodiment 60a of the coupling adapter in further detail. It should be noted that COUPLING adapter 60a represents one embodiment of a suitable COUPLING device as described above and is described in detail in U.S. patent application Ser. No.13/035,774, entitled "DRILL STRING COUPLING ADAPTER AND METHOD FOR INGROUND SIGNAL COUPLING," which is hereby incorporated by reference in its entirety. Specifically, the coupling adapter 60a includes a body 120, the body 120 forming a pin fitting 122 for engagement with a box fitting (not shown) of the underground utility 54. It should be noted that threads are not shown on the pin fitting for clarity of illustration, but are understood to be present. The body includes at least one high voltage electrical connection assembly. The coupling adapter 60a also includes an extension 140, the extension 140 being removably attached to the body 120 such that the body or extension can be replaced. The body and extension may be formed of any suitable material, such as a non-magnetic alloy (including non-magnetic stainless steel) and a magnetic alloy (e.g., 4140, 4142, 4340 or any suitable high strength steel). In particular, a non-magnetic form may not be necessary when the coupling adapter is placed many feet or many drill rods from the electronic module that drives the coupling adapter. However, if a coupling adapter is used near an underground device (e.g., a steering tool) that detects the earth's magnetic field, a non-magnetic material is used to avoid potential magnetic field interference. It is well known in this regard that non-magnetic high strength alloys are typically much higher in cost than their magnetically counterparts. It should be noted that there is no such requirement that the body and the extension be formed of the same material.

A cylindrical ring 144 is received between the body 120 and the extension 140. It should be noted that the cylindrical ring is rendered transparent for the purposes of this description so that the current transformer 160 is visible. The cylindrical ring may be formed of any suitable material that is generally resistant to the subterranean environment and electrically insulating. By way of non-limiting example, one suitable material is a phase change toughened zirconia ceramic, and other ceramic materials may also be suitable. As seen in fig. 2, the outer surface of the cylindrical ring 144 may be an insert relative to the outer surfaces of the body and extension in order to reduce potential damage to the cylindrical ring and reduce wear on the cylindrical ring. For example, based on the insert, the clamping arrangement 32 (fig. 1) may bridge and remain out of contact with the cylindrical ring. Further, the subsurface wear of the cylindrical ring due to rotation, advancement and withdrawal of the drill string can be reduced. In this regard, it should be appreciated that for similar reasons, the electrical connection assembly 130 may be an insert, as seen in fig. 2. The current transformer may include a coil wound on a toroidal or toroidal core. In this regard, the core may include any suitable cross-sectional shape, such as rectangular, square, and circular. In the illustrated embodiment, the cores may be separate to facilitate installation of the current transformer. A pair of electrical conductors from opposite ends of the current transformer coil may be coupled to the cable 100 at the electrical connection assembly 130. It should be understood that any suitable current transformer may be used and that the particular current transformers described herein are not intended to be limiting. The opposite end 170 of the extension 140 defines a box fitting for threaded engagement with the underground distal end of the drill string. With respect to fig. 1, it should be appreciated that the coupling adapter 60 may be installed between any two adjacent drill pipe sections when the drill string is assembled at the drilling rig. For example, a suitable embodiment of the coupling adapter of FIG. 1 may be located between drill pipe sections N-1 and N. The cable 100 then extends from the inground tool through the drill pipe section n to the coupling adapter.

Turning now to fig. 3, fig. 3 is a diagrammatic perspective view showing an embodiment of a coupling adapter 60 b. It is noted that fig. 3 corresponds to fig. 2 of US patent application serial No.13/593,439 (hereinafter the' 439 application) entitled "DRILL STRING INGROUND ISOLATOR IN AN MWD SYSTEM AND ASSOCIATED METHOD", the entire contents of which are hereby incorporated by reference. The embodiment of fig. 3 represents one of many suitable embodiments disclosed in the' 439 application. Each of these embodiments creates an electrically isolated gap or discontinuity in the drill string when positioned in the drill string shown in fig. 1. The' 439 application also discloses subsurface interchangeable tool systems that form an electrically isolated gap as another useful embodiment in the context of the present application.

The assembly includes a pin end housing 200 having a pin fitting 202, the pin fitting 202 defining a through passage from which the cable 100 may extend for external electrical connection. The cartridge end housing 210 defines a cartridge fitting 212. The pin fitting 202 and box fitting 212 may mate with fittings on drill pipe sections (which make up the drill string 16) so that the isolator may be inserted into any desired joint in the drill string. The isolator also includes a drive dog (drive dog) housing 220 engaged with each of the pin housing end 200 and the box housing end 210, wherein the drive dog housing is electrically coupled to the pin housing in the overall assembly. The pin housing end, box housing end, and drive dog housing in this embodiment are typically made of suitable high strength materials, such as 4340, 4140, 4142, and 15-15HS or monel K500 (the latter two of which are non-magnetic high strength alloys) because these components are subject to potentially adverse downhole environments and relatively extreme forces. Based on the deployment of the plurality of electrical isolation members 270 (which may be of any suitable shape), the box end housing 210 is electrically isolated from the pin end housing 200 to define an electrical isolation/insulation gap.

It should be understood that any suitable arrangement may be used for coupling the signal to the drill string, and that the details regarding the specific structure of the illustrated embodiments for enabling coupling of the signal to the drill string are not to be considered limiting. Another suitable arrangement using a current transformer is described, for example, in U.S. patent application serial No.13/035,833, entitled "ingound DRILL STRING HOUSING AND METHOD FOR SIGNAL COUPLING," the entire contents of which are incorporated by reference. In this latter application, the current transformer is supported by an underground housing, which may also support the electronics package. Furthermore, the prior art includes examples that at least claim other arrangements for setting an electrically isolated gap. By way of example, US patent No.7,649,474 describes in column three, lines 33 to 42, a simple method of forming electrically isolated sections in a drill string using a material such as a fiberglass section configured with a metallic end.

Fig. 4 is a perspective diagrammatic view showing an inground tool 20 in the form of a boring tool having a drill bit 50. For purposes of this disclosure, the coupling adapter/isolator 60 or other suitable arrangement is installed as part of a drill string having an uphole portion 400 and a downhole portion 402. The downhole portion of the drill string may include any suitable subsurface housing 54 (e.g., a bit housing) and/or one or more intervening drill pipe sections (not shown) connecting the isolators 60 to the subsurface housing. In this example, the subsurface housing is a drill bit or a drilling tool. The cable 100 may extend within a through passage of the drill string to the electronics package 56 for electrical communication with the drill string transceiver 64 (fig. 1). Depending on the particular embodiment, the conductors of cable 100 may be connected to a current transformer or connected in a manner bridging an electrically isolated gap, for example. As discussed above, drilling fluid may flow around the electronics package to reach the subsurface distal end of the drill string (e.g., the drill bit). In the illustrated embodiment, to transmit the signal 66 from the transceiver 64 (fig. 1), the underground housing 54 includes a slot 420. The coupling adapter 60 is removably attached to the underground housing 54, with the underground housing 54 itself ready for removable attachment to the distal end of the drill string.

Fig. 5 is a perspective diagrammatic view showing an inground tool 20 in the form of a reaming tool that includes a reamer 422 removably attached to one end of an inground housing 54. In this embodiment, the housing 54 and the coupling adapter 60 are additionally provided in the same manner as in fig. 4. As the drill string pulls the reaming tool toward the drill rig, the reaming tool is pulled in the direction 424 indicated by the arrow in order to enlarge the borehole. The opposite end of the reaming tool is attached to one end of the tension monitoring device 430. The opposite end of the tension monitoring device may be attached to a utility (not shown) that is pulled through the enlarged borehole to install the utility in the borehole. Tension monitoring device 430 measures the tension applied to the utility during the reaming operation. A suitable and highly advantageous tension monitoring device is described in US patent No.5,961,252, which is co-owned with the present application and incorporated by reference in its entirety. Tension monitoring device 430 may transmit electromagnetic signal 434 and tension monitoring data may be modulated on electromagnetic signal 434. Signal 434 may be received by transceiver 64 (fig. 1) so that corresponding data may be placed on the drill string for transmission to the drilling rig using current transformer 160 (see fig. 2). It should be understood that wireless signals may be received from any form of inground tool via transceiver 64 and that the present embodiment of the tension monitoring device is described without limitation. For example, in another embodiment a mapping device may be used instead of the tension monitoring device. Such a drawing device may be operated, for example, using an Inertial Navigation System (INS).

Fig. 6 is a block diagram illustrating an embodiment of the electronic portion 56 in further detail. Portion 56 may include an in-ground digital signal processor 510 that performs all of the functions of transceiver 64 of fig. 1. The sensor portion 68 may be electrically connected to a digital signal processor 510 via an analog-to-digital converter (ADC) 512. Any suitable combination of sensors may be provided for a given application, and may be selected, for example, from among accelerometer 520, magnetometer 522, temperature sensor 524, and pressure sensor 526, where pressure sensor 526 may sense the pressure of drilling fluid prior to injection of drilling fluid from the drill string and/or an annular region surrounding a downhole portion of the drill string. The adapter/isolator 60 is shown diagrammatically as separating a downhole portion 402 of the drill string from an uphole portion 400 of the drill string for use in one or both of a transmit mode (coupling data to the drill string) and a receive mode (recovering data from the drill string). As shown, the electronic portion is connected across an electrically insulating/isolating break formed by an isolator by a first wire 528a and a second wire 528b (which may be collectively represented by reference numeral 528). In embodiments using current transformers, these wires may be connected to the current transformer wires. Regarding the transmission mode, an antenna drive section 530 electrically connected between the subsurface digital signal processor 510 and the conductor 528 may be used to directly drive the drill string. In general, to avoid interference, data coupled into the drill string may be modulated with a different frequency than any frequency used to drive dipole antenna 540, and dipole antenna 540 may transmit signal 66 (fig. 1) described above. When the antenna driver 530 is off, an on/off Switch (SW) 550 may selectively connect the wire 528 to a Band Pass Filter (BPF) 552, the Band Pass Filter (BPF) 552 having a center frequency corresponding to the center frequency of the data signal received from the drill string. The BPF 552 is in turn connected to an analog-to-digital converter (ADC) 554, the analog-to-digital converter (ADC) 554 itself being connected to the digital signal processing portion 510. The recovery of the modulated data in the digital signal processing section can be readily configured by a person skilled in the art in view of the particular form of modulation employed.

Still referring to fig. 6, dipole antenna 540 may be connected for use in one or both of a transmit mode (signal 66 is transmitted into the surrounding ground) and a receive mode (receiving an electromagnetic signal such as signal 434 of fig. 5). Regarding the transmission mode, an antenna driving part 560 electrically connected between the underground digital signal processor 510 and the dipole antenna 540 is used to drive the antenna. Furthermore, the frequency of the signal 66 will typically be significantly different from the frequency of the drill string signal to avoid interference therebetween. When the antenna driver 560 is turned off, an on/off Switch (SW) 570 may selectively connect the dipole antenna 540 to a Band Pass Filter (BPF) 572, the Band Pass Filter (BPF) 572 having a center frequency corresponding to a center frequency of a data signal received from the dipole antenna. The BPF 572 is in turn connected to an analog-to-digital converter (ADC) 574, which itself is connected to the digital signal processing portion 510. The transceiver electronics for the digital signal processing section can be readily configured by one of ordinary skill in the art in view of the particular form of modulation employed and in view of this entire disclosure in many suitable embodiments. The design shown in fig. 6 may be modified in any suitable manner in view of the teachings disclosed herein.

Referring to fig. 1 and 7, the latter is a block diagram of components that may constitute an embodiment of an above-ground transceiver device, indicated generally by the reference numeral 600, and coupled to a drill string 16. An above-ground current transformer 602 is positioned, for example, on the drill rig 14 to couple signals to the drill string 16 and/or to recover signals from the drill string 16. The current transformer 602 may be electrically connected for use in one or both of a transmit mode (modulating data onto the drill string) and a receive mode (recovering the modulated data from the drill string). The transceiver electronics package 606 is connected to a current transformer and may be battery powered or rig powered such that a substantially unlimited amount of power may be available. In this regard, the uphole transmission power is typically always greater than the downhole transmission power of the battery-powered downhole transceiver. Thus, the downhole transmission power is selectable within a downhole transmission power range, the downhole transmission power range being lower than the minimum uphole transmission power such that the uphole power is always greater than any selected downhole transmission power. In one embodiment, the maximum downhole transmission power may be as low as 1 watt. Often, it is difficult to obtain a maximum power of over 5 watts on a battery power supply. In one embodiment, higher power levels (e.g., 3 to 5 watts) may be obtained by using a supercapacitor to store energy from the battery. However, due to the limited energy capacity of supercapacitors, the duty cycle will be limited. In contrast, the uphole transmission power (even at a minimum) may be 100 watts. For the transmission mode, an antenna driving part 610 electrically connected between the above-ground digital signal processor 618 and the current transformer 602 is used to drive the current transformer. Further, to avoid interference, data coupled into the drill string may be modulated using a different frequency than that used to drive the dipole antenna 540 (fig. 1 and 6) in the underground housing 54 and than that used by the isolator 60 to drive the signal onto the underground end of the drill string. When the antenna driver 610 is off, an on/off Switch (SW) 620 may selectively connect the current transformer 602 to a Band Pass Filter (BPF) 622, the Band Pass Filter (BPF) 622 having a center frequency corresponding to the center frequency of the data signal received from the drill string. The BPF 622 is in turn connected to an analog-to-digital converter (ADC) 630, which analog-to-digital converter (ADC) 630 is itself connected to the digital signal processing section 618. It will be appreciated that the digital signal processing portion 618 and associated components, including an uphole transceiver, may form part of the processing device 46 (shown using dashed lines) of the drilling rig or be connected to the processing device 46 at a suitable interface 634. The transceiver 606 may send commands to the inground tool to achieve various purposes, such as controlling transmission power, selecting modulation frequencies, changing data formats (e.g., decreasing baud rate to increase decoding range), etc. The transceiver electronics for the digital signal processing section can be readily configured by one of ordinary skill in the art in view of the particular form of modulation employed and in view of this entire disclosure in many suitable embodiments.

Still referring to fig. 1 and 7, in the repeater embodiment, another subsurface isolator device 640 (shown within the dashed box) replaces the current transformer 602 along with another example of the subsurface housing 54. The apparatus 640 may include any suitable embodiment of an underground adapter/isolator according to the present disclosure, including another example of an isolator for use at an underground utility. In this arrangement, the isolator is connected to transceiver 606 (fig. 6) and is serviced as a repeater as a unit inserted into one junction of the drill string (by way of example, 1000 feet from the inground tool). Thus, section 400 'of the drill string may connect the isolator to the drilling rig, while section 402' of the drill string serves as an intermediate section of the drill string between the isolator device 640 and the isolator 60 at the inground tool. The repeater unit may for example be inserted at the joint formed between the drill pipe sections 1 and 2 of fig. 1. An underground housing for use in repeater applications may include a box fitting at one end and a pin fitting at an opposite end. Of course, those of ordinary skill in the art will appreciate that adapters for boxes and pin fittings are well known and readily available. In another embodiment, the isolator device 640 may be inserted into the joint while the repeater electronics are housed in a pressure tube supported by a centralizer (centraliser) within the through passage of the adjacent drill pipe section. In yet another embodiment, the repeater electronics may be disposed in an end-loaded or side-loaded housing and inserted into the drill string in electrical communication with the isolator. Such an end or side loaded housing may include channels that allow drilling fluid to flow therethrough. Of course, in any of these embodiments, the repeater electronics may be electrically connected to the isolator in a manner consistent with the description above. To avoid signal interference and by way of non-limiting example, a repeater may pick up a signal originating from an inground tool or another repeater at one carrier frequency, and to make the signals distinguishable from each other, the repeater electronics may retransmit the signal onto the drill string at a different carrier frequency. As another example, suitable modulation may be used to make the signals distinguishable. Accordingly, the repeater electronics package may be housed in any suitable manner in electrical communication with the signal coupling means of the isolator to generate a repeater signal (which is distinct from the received data signal) based on the received data signal.

Attention is now directed to fig. 8, fig. 8 is a block diagram showing an embodiment of an advanced bi-directional drill string communication system, generally indicated by reference numeral 700. The system 700 includes an uphole transceiver 702 and a downhole transceiver 704. The uphole transceiver 702 may generally include at least the features of the previously described transceiver 600 of fig. 7, while the downhole transceiver 704 may generally include at least the features of the previously described downhole transceiver 56 of fig. 6, thereby including an arrangement for transmitting a positioning signal. Thus, the two-way communication system can transmit data in both directions on the drill pipe/rod making up the drill string 16. Applicants have appreciated that system 700 provides benefits by avoiding at least some signal emissions through the ground, at least because, for example, the signal strength of the electromagnetic signal emitted from dipole antenna 540 (fig. 6) (inversely proportional to the cube of the distance) experiences loss with distance. For a given transmission power, an increase in the communication range will be obtainable by transmitting using the drill string as an electrical conductor. The techniques disclosed below provide even further improvements in using such bi-directional communication via the drill string.

Applicant has appreciated that there are some challenges with respect to transmitting electrical signals through a drill string. For example, the drilling rig may electrically couple electrical/electronic noise from its system into the drill string. As another example, electromagnetic noise may be transmitted along the drilling path, for example, from underground power lines and tracker lines associated with fiber optic cables and the like. The noise may be coupled to the drill string via the conductivity of the soil. As yet another example, signal distortion may occur due to the drill rods making up the drill string, the interconnections between the drill rods, and the soil surrounding the drill string. The effects of noise and distortion on the electrical signal carried by the drill string are discussed in detail subsequently to describe signal degradation, at least three methods and related devices are presented that involve further enhancing such a communication system. As will be seen, these methods involve: (1) noise scanning, (2) equalization, and (3) training or customizing the receiver.

As discussed above, electrical noise in the drill string may be coupled to the drill string from the drilling rig and/or from an underground source in the soil (e.g., an underground power line) via the electrical conductivity of the soil. These noise are dependent on the surrounding environment at the drilling site and, therefore, can vary from site to site. Accordingly, it is assumed that the noise is represented by a function n (t), and can be either wideband or narrowband. By way of non-limiting example, narrowband noise includes the fundamental of 50 or 60 cycles of power line noise, while wideband noise includes Power Line Communications (PLC), motor controller noise, and harmonics of 50 or 60 cycles of power line frequency.

Distortion may be caused by electrical parasitic elements introduced through the drill pipes (e.g., interconnections between drill pipes) and electrical conductivity from the soil surrounding the drill pipes. Fig. 9 shows an approximation model of a drill string in the earth, indicated generally by reference numeral 720. The drill string consists of N drill rods and the conductivity of the soil is difficult to define at least to some extent, however, it can be approximated by the model shown. Such an electrical model may be represented by the following mathematical laplace expression:

wherein a is _i Is constant and is defined by the model's electrical parasitic resistors and capacitors and the conductivity of the soil, as shown, for example, in fig. 9. The term "channel" refers to the entire path length of the interconnected drill pipe sections extending between the downhole transceiver 704 and the uphole transceiver 702. Hereinafter, a channel may refer to the electrical characteristics of the entire drill string. Equation EQ (1) may be referred to as the transfer function of the channel. Equation EQ (1) can be expressed in a more familiar form as shown below:

Equation EQ (2) discloses that the channel acts like a band-limited filter (band limiting filter) on the transmission signal. Equation EQ (2) has a time domain expression as follows:

wherein the method comprises the steps ofRefers to inverse laplace transform. The interaction of noise and distortion with the electrical signals carried by the drill pipe sections making up the drill string will be discussed immediately below.

Attention is now directed to fig. 10a and 10b, fig. 10a and 10b are block diagrams showing details regarding the downhole transceiver 704 and the uphole transceiver 702, respectively. Initially, it should be noted that the transmitter 800 of the uphole transceiver 702 may be of any suitable type, for example, using an H-bridge configuration for driving the current transformer 602 (fig. 7). The signal generated by the transmitter 800 may be received by a receiver 802 (using any suitable type of receiver, including, for example, a front-end protection circuit coupled to a low noise preamplifier followed by a band-pass filter coupled to an analog-to-digital converter and a digital signal processor) in the downhole transceiver 704. In this regard, it should be noted that such a receiver is typically used to receive the positioning signal 66. With respect to the transmitter 800 and receiver 802, applicants have recognized that for communication through to a downhole transceiver, a substantially unlimited amount of power may be available at the drilling rig, as will be discussed further below. The transmitter portion 802 in the downhole transceiver 704 receives sensor data 812, which is converted to digital form. The sensor data is encoded and encrypted by a data encoder/encryption portion 810. In this regard, it should be understood that data encryption is not necessary. While the embodiments described herein employ modifications of phase shift keying by way of non-limiting example, it should be appreciated that any suitable form of modulation currently available or yet to be developed may be used While still relying on the teachings disclosed herein. Other suitable modulation schemes include, for example, frequency Shift Keying (FSK) and manchester encoding. Multiplexer 910 may then selectively couple the data to MPSK (multi-phase shift keying) modulator 912 for modulation onto a carrier. The MPSK modulator can perform 2 ^M Phase modulation, where m= {1,2,3,4}. The multiplexer 914 may then select the modulated signal for electromagnetic coupling to the drill string. The coupled signal may have a mathematical expression of the form:

wherein P is _T Is the transmission power, f _c Is the carrier frequency, theta _k Is the carrier phase representing the data bits and d (t) is the baseband signal. For example, if m=1, then MPSK becomes BPSK (binary phase shift keying), where binary data is mapped according to:

as another example, for m=2, mpsk becomes QPSK (quadrature phase shift keying), which maps two binary data bits into one of four phases. The following shows two bits to carrier phase { θ } _k A mapping of QPSK:

accordingly, in the QPSK embodiment four carrier phase values represent four data symbols.

In equation EQ (4 a), d (t) represents a baseband signal defined as follows:

Wherein T is _b Is a bit duration and p (t) may be defined as follows:

in response to the transmission of the electrical signal on the drill string, the signal decays by noise and distortion when reaching the receiver (e.g., at the opposite end of the drill string). The attenuated received signal can be mathematically described as follows:

wherein P is _L <1 indicates that the transmission signal suffers from power loss in propagating through the drill pipe section, for example leaking into conductive soil. The term n (t) denotes noise introduced from the surrounding environment onto the drill string, which noise adds to the transmitted signal. The function f (t) represents the baseband waveform distorted by the channel and can be defined as follows:

wherein, d (t) is defined in EQ (5 a) and c (t) is defined in EQ (3) by convolution operation. For example, the signal defined in equation EQ (6 a) arrives at the uphole transceiver 702, where the signal may be demodulated and decoded to recover baseband binary data { cos (θ) _k ),sin(θ _k )}。

Fig. 10b is a block diagram illustrating an embodiment of an uphole transceiver 702. In this embodiment, the uphole transceiver comprises an uphole receiver 1000. The latter may be placed in selective communication with the drill string 16 via the multiplexer 1002 and using a suitable coupling device such as a current transformer 602. The receiver 1000 includes a carrier tracking loop and demodulator 1004, the carrier tracking loop and demodulator 1004 tracking the carrier frequency and phase of the received signal and then coherently/synchronously demodulating the carrier. Of course, the particular type of carrier tracking loop selected And the demodulator is complementary to the modulator used in the downhole transceiver. A Data Transition Tracking Loop (DTTL) 1006 may also be employed to track bit timing transitions so that { cos (θ) _k ),sin(θ _k ) Decoding. Thus, in this embodiment, synchronous operation of the uphole receiver may enhance its own communication capabilities. Synchronous detection provides at least the benefit of using relatively narrower bandwidth signal detection. A data decoder/decryptor 1008 is used that is complementary to the uphole data encoder and decryptor 810. The channel bandwidth and signal-to-noise ratio estimator 1010 may track the inverse relationship of bandwidth to signal-to-noise ratio. For example, as distance increases, the level of signal loss correspondingly increases. To maintain a given signal-to-noise ratio with increasing distance, it is often necessary to reduce the bandwidth and/or increase the signal power (if more power is available). With respect to enhancing communication between downhole and uphole transceivers via drill pipe sections, additional measures may be taken to even further reduce the effects of noise and distortion. As discussed in detail below, these measures may include, but are not limited to: (1) noise scanning, (2) equalization, and (3) application of training sequences.

Noise scanning

Referring to fig. 10a, the electrical noise carried by the drill string 16 can greatly reduce the useful range of the transmitted signal. In one embodiment, transmission of drill string signals at frequencies containing noise may be avoided. Thus, noise scanner 1012 can determine which frequencies have the least noise. Note that noise scanner 1012 is also shown in phantom in fig. 10 b. Because the uphole noise and the downhole noise are very different, one or both of these noise scanners may be provided and used. Any of a number of suitable methods may be used to determine which frequencies contain noise and which frequencies do not. By way of non-limiting example, the noise spectrum may be determined using, for example, FFT (fast fourier transform), DFT (discrete fourier transform), or PSD (power spectral density) over any desired bandwidth or at a predetermined frequency. In this regard, the entire contents of commonly owned U.S. published patent application No.2011-0001633 (U.S. Ser. No.12/497,990) filed on 7/6/2009 are incorporated by referenceThe manner of reference is incorporated herein by reference, which describes techniques for determining a noise spectrum. In the present application, noise may be scanned more effectively in the event that transmitters in the uphole and downhole transceivers are disconnected. At transmitter off and assuming at sampling frequency (samples per second) F _s Sampling the noise signal n (t) represented by EQ (6 a)FFT of (1) is

Equation EQ (7) may provide a value of at least [ -0.5Fs,0.5Fs]Is a function of frequency. The desired frequency for transmission may be one having a minimum value |R (f) | ² Is used for the frequency acquisition.

In another embodiment, noise scanner 1012 may include a filter bank, e.g., a set of bandpass filters or a set of Goertzel filters, for determining which frequencies in a set of frequencies contain noise and which frequencies do not contain noise. The bandwidths of the individual filters that make up the filter bank may be customized in any suitable manner. The noise power measured from the kth filter of the filter bank is

Since each filter in the filter bank may be at a frequency of interest, P is generated _n The filter of the minimum value of (2) may be selected as the frequency at which noise is minimal. It should be appreciated that any suitable type of filter may be used, provided that the filter provides the ability to determine power at a particular frequency or within a frequency band. By way of non-limiting example, examples of suitable filters include FIR (finite Impulse response) and IIR (infinite Impulse response) filters.

Signal distortion correction

In view of the above discussion, it has been shown that: at least from a practical point of view, the channel constituted by the removably attached drill pipe segments behaves like a band-limited filter, e.g. a FIR (finite impulse response) filter. Transmitting a signal over this channel causes distortion, as shown by EQ (6 a) and EQ (6 b). Applicant has appreciated that this type of distortion expands the baseband waveform. Such a phenomenon is known as intersymbol interference (ISI) and has the effect of reducing the signal-to-noise ratio (SNR), which shortens the useful range of communication between downhole and uphole transceivers. ISI may be corrected using a compensation response, which may be implemented using an equalizer. As will be seen, the equalizer includes an equalizer response that can be tailored based on a set of equalizer coefficients such that the equalizer response is applicable to a range of variables in the channel transfer function. In practice, the equalizer may be considered as another FIR filter (also called a deconvolution filter) at the receiver, and the coefficients will be determined based on the Minimum Mean Square Error (MMSE) of the difference between the estimated value of the channel response and the measured data. Referring to fig. 10b, an in-phase equalizer 1014 and a quadrature-phase equalizer 1016 selectively receive symbol inputs from switching section 108, the switching section 108 switching in response to DTTL 1006. Typically, the switching is performed in 90 degree increments for this embodiment. Other embodiments may use suitable but different handoff increments. Assuming that the received signal has been successfully demodulated so that the baseband data is recovered, equation EQ (6 a) reduces to in-phase and quadrature-phase components:

Where b (k) is a channel approximation based on an FIR function. It should be appreciated that EQ (9 a) and EQ (9 b) may be processed at the symbol rate (see EQ (4 c)). The character "×" refers to the convolution process.

It is desirable to estimate or characterize the coefficients b (k) for the band-limited channel. In implementationIn the example, by collecting r _I (k) Or r _Q (k) The coefficient b (k) can be determined from n+1 samples of (c). It should be understood that either one may be used, as the channel coefficient b (k) is the same in both cases. Accordingly, r is not required to be used _I (k) And r _Q (k) Both to determine the channel response b (k). In response to this, the control unit,

in vector form (i.e., over n+1 samples), equation EQ (10) can be written as:

r _I (k)＝H _I (k)b(k)+n _I (k)EQ(11a)

r _Q (k)＝H _Q (k)b(k)+n _Q (k)EQ(11b)

wherein r is _I (i) And r _Q (i) Is the (n+1) column vector, H _I (i) And H _Q (i) Is an (n+1) xM matrix, and N _I (i) And n _Q (i) Is the (n+1) column vector. In the form of equations EQ (11 a) and EQ (11 b), the channel coefficients b (k) can be solved using the Minimum Mean Square Error (MMSE) criterion discussed in appendix a. Once estimated to be expressed asThe data symbol cos (θ) can be determined from the following equation _k ) (with minimal ISI):

note that d (k) is always 1 for all k values, so it is omitted from the above equation for clarity. The general form of equation EQ (12) can be used to determine sin (θ) _k ) Or cos (θ) _k ) Minimal ISI (i.e., of the data symbols in the orthogonal channel). The in-phase and quadrature-phase components of equation EQ (6 a) may be processed separately or together as discussed above. Equations EQ (9 a) and EQ (9 b) can be rewritten in complex form to makeThe in-phase and quadrature-phase components of the EQ (6 a) can be processed simultaneously. In complex form, equations EQ (9 a) and EQ (9 b) may be written as

r _c (k)＝z(k)*b(k)+n(k)EQ(13a)

Wherein the method comprises the steps of

Wherein the method comprises the steps ofIn vector form, equation EQ (13 a) can be written as:

r _c (k)＝Z(k)b(k)+n(k)EQ(14)

note that Z (k) is now a matrix of size (n+1) ×m. The channel coefficient b (k) can be determined using equation EQ (a 13) in appendix a. Similarly, complex data symbol z (k) shown in equation EQ (13 b) may be determined as follows:

the complex data symbol z (k) may be determined using equation EQ (a 13) in appendix a.

In general, ISI caused by the FIR channel can be corrected by using an equalizer. Fig. 11a and 11b diagrammatically show a general embodiment of two equalizers that can be used in the context of fig. 10 b. In the case of MPSK, it is noted that the same embodiment of the equalizer is generally used for both in-phase and quadrature-phase equalizers. The first equalizer 1200 in fig. 11a is a linear channel equalizer that uses the current and previous measurements r containing noise _I (k) Or r _Q (k) Or r _c (k) To cancel ISI.

Fig. 11b shows a second equalizer 1300, which is a non-adaptive Decision Feedback (DFE) equalizer, that uses the previous estimated data bits to improve ISI cancellation. The DFE includes a feedforward filter 1302, a threshold detector 1304, and a feedback filter 1308. The feed forward filter 1302 and the feedback filter 1308 function as linear components, while the detector 1304 introduces nonlinear elements of the filter. In an embodiment and by way of non-limiting example, the threshold detector may be set to logic level 1 if the voltage is greater than or equal to zero and set to logic level-1 if the voltage is less than zero. The input to the feedback filter 1308 is the last determined bit from the detector 1304. ISI can be reduced from the estimated bits by adding the output of feedback filter 1308 to the output from feedforward filter 1302. Equalizer 1300 outputs soft estimate 1310 for each data bit and hard limiter estimate 1312 for each data bit. "Soft" data bits refer to bits that may be represented by any suitable voltage value or any suitable magnitude. For example, the soft estimate data bits may have values of { +a, -b }, where "a" represents any voltage or amplitude and b represents any voltage or amplitude. That is, the soft estimation bits are not binary and may be characterized as one of a plurality of different values that satisfy a minimum mean square error condition when the equalizer 1300 converges. The minimum mean square error can be formulated by taking the average of the differences between the output 1310 and the transmitted data sequence. On the other hand, a "hard limiter" data bit is binary and refers to a bit represented by a set of only two values (previously soft estimated bits). For example, the hard limiter estimate bit may have a value of only { +1 or-1 } or { +A or-A }, where A is the amplitude or voltage value. Soft estimates of the data bits output from the equalizer may be provided to a soft decision Forward Error Correction (FEC) decoder. The hard slicer estimate bits output from the equalizer may be provided to a hard decision FEC decoder or a data decryption-encryptor. When the environment provided by the communication channel is known and it is desired that the environment be relatively static/stable, the feedforward transfer function F (z) of the feedforward filter 1302 and the feedback transfer function D (z) of the feedback filter 1308 may be determined in advance so that a non-adaptive equalizer may be used.

Another form of equalizer is an adaptive equalizer that relies on decision or training sequences of the equalizer output to update the coefficients of the feedforward and feedback transfer functions of the equalizer. Fig. 12a is a block diagram of an embodiment of an adaptive feedforward equalizer, indicated generally by the reference numeral 1400. In this embodiment, the equalizer is adapted to a communication channel transfer function based on a selected one of the hard limiter outputs 1312 or through a training bit sequence 1404 (also shown in fig. 10 a). The training bit sequence may be obtained via a switch 1408, which is shown diagrammatically. The feedforward filter 1410 receives an input 1412 from a communication channel. It should be appreciated that feedforward filter 1410 differs from feedforward filter 1302 of FIG. 11b at least because the coefficients of filter 1410 may be adapted to a changing communication channel transfer function. The coefficients of the filter 1410 may be adjusted to drive the input error signal 1414 to a minimum Mean Square Error (MSE) value. The error signal used by the feedforward filter 1410 to adjust its coefficients is represented graphically by a diagonal line that passes through the feedforward filter. Error signal 1414 is formed by subtracting soft estimate 1310 from the equalizer hard limiter output bit sequence or training bit sequence (depending on the setting of switch 1408). When adjusting the coefficients of the filter 1410, the MSE of the error signal 1414 as a function of time will tend to converge or tend to diverge to exhibit a negative or positive slope, respectively. When the MSE of error signal 1414 exhibits a positive slope, the filter adaptation may either restart with a smaller adjustment step or a training sequence may be used. Adaptive convergence of the coefficients of the feedforward filter 1410 occurs when the MSE of the error signal 1414 exhibits a negative slope (i.e., the MSE of the error tends to be smaller). When the MSE of error signal 1414 is horizontal (i.e., the slope is zero) as a function of time, then the minimum mean square error value has been used to converge feedforward filter 1410 and adapt to the communication channel transfer function. When using a training sequence and during an adaptation process using the training sequence, the transmitter must transmit the same training sequence to the receiver over the communication channel when adaptation of the equalizer occurs.

Adaptively adjusting the coefficients of F (z) using a training bit sequence (rather than an estimated bit sequence) may provide better accuracy and better performance of the equalizer, even at low signal-to-noise ratios (SNR). However, it should be remembered that the training interval must be dedicated when training bit sequences are used from system end to end. That is, cooperation between the uphole and downhole transceivers is required for the training process to take place, as the downhole transceiver transmits the training sequence to the uphole transceiver, or vice versa. It should be appreciated that if the downhole transceiver includes an equalizer, the uphole transmitter may transmit the training sequence to the downhole transceiver. On the other hand, if the hard limiter output 1312 of the equalizer is used to adjust the feedforward equalizer 1410 to tune the coefficients of F (z), then a dedicated training time is not needed.

Fig. 12b is a block diagram of an embodiment of an adaptive Decision Feedback (DFE) equalizer, indicated generally by the reference numeral 1500, that uses a training sequence 1404 and, like equalizer 1400, uses a switch 1408 for feedback to switch between hard limiter output 1312 and training sequence 1404. Equalizer 1500 is a DFE equalizer that includes feedback filter 1504. It should be appreciated that feedback filter 1504 differs from feedback filter 1308 of fig. 11b at least because the hard limiter output bits 1312 or training bit sequence of the equalizer may be selectively used to form error signal 1508, which error signal 1508 is then used to adaptively tune the coefficients of feedback filter D (z) 1504. The error signal 1508 is used to adaptively tune the feedforward filter F (z) 1410 and the feedback filter D (z) 1504 according to changes in the communication channel response. The error signal 1508 may be formulated by subtracting the soft estimate output 1310 from the hard limiter output 1312 of the equalizer or from the training sequence 1404 depending on the setting of the switch 1408. The error signal 1508 is then fed to filters D (z) and F (z), shown diagrammatically by diagonal lines or vertical lines passing through F (z) 1410 and D (z) 1504, with the coefficients of the F (z) and D (z) filters being retuned to drive the error signal 1508 to a minimum. This minimum value may be referred to as Minimum Mean Square Error (MMSE). As MMSE increases, the coefficients of the filter are considered to diverge. In this case, the procedure can be reset and restarted with a smaller update step or by using a training sequence for adaptation. When MMSE decreases, the coefficients of the filter are considered to converge. When the curve of MMSE is straight (i.e., the slope is at least approximately zero) over time or the change in sampling index (sample index), then the coefficients of filters F (z) and D (z) are considered to converge and the mean square error signal 1508 is considered to be at a minimum. When the switch 1408 selects the training sequence, the coefficients of F (z) and D (z) are adaptively tuned according to the changing communication channel transfer function by driving the input error signal 1508 (represented graphically by the diagonal or vertical lines passing through F (z) 1410 and D (z) 1504) to a minimum. When an equalizer in the uphole transceiver is trained with a training sequence, the downhole transceiver also transmits the same training sequence to the uphole transceiver over the channel. In another embodiment, the downhole transceiver may include a passive equalizer (subject equal izer) such that the uphole transceiver transmits the training sequence to the downhole transceiver. In such an embodiment, the uphole transceiver may comprise the component parts represented in fig. 10a, and the downhole transceiver may comprise the component parts represented in fig. 10 b. That is, any of the types of equalizers described herein may be disposed in both uphole and downhole transceivers. Again, in the MPSK example, it is noted that the same embodiment of the equalizer is generally used for both in-phase and quadrature-phase equalizers.

In one embodiment, if ISI is caused primarily by the drill pipe, a channel model (i.e., transfer function) for the drill pipe may be developed in advance by predetermining the channel transfer function without introducing noise considerations and without the need to acquire measured data (subject to environmental noise in the drilling environment). In this case, the channel transfer function is a function of the electrical properties of the drill pipe and the number of pipes in the drill string. Therefore, the channel transfer function can be developed in advance as shown in equations EQ (1), EQ (2), and EQ (3).

Receiver training

In one embodiment, the communication system of the present disclosure may employ a training sequence 1404 for training at least an equalizer in the uphole receiver 702 of fig. 10 b. It should be noted that the training sequence is also shown in the equalizer of fig. 12a and 12 b. To enhance communication, a plurality of receiver parameters may be determined by the process. The channel bandwidth determines the frequency range or bandwidth available to reach the uphole transceiver. The feasible frequencies at which the system can operate are then identified as parameters such that the lowest noise frequencies that fall within the channel bandwidth are available for communication. Other parameters include transmission power loss and noise power, which can determine the minimum power that the downhole transmitter uses to transmit to at least the uphole receiver. It will be appreciated that by operating at a minimum power while still maintaining sufficiently reliable communications, a significant increase in battery life in the downhole transceiver may be achieved. It is desirable to select a training sequence of length L with an autocovariance as follows:

Wherein T (i) refers to a training sequence, and T _b Is the bit duration. To enable training, the receiver includes a copy of training sequence 1404 (fig. 10 b) in bit form. After transmitting the training sequence to the receiver, the receiver may then use a copy of the training sequence in the calculation of the channel transfer function and the receiver signal-to-noise ratio (SNR) to compare with the received training sequence. I.e. the difference between the stored training sequence and the received training sequence output from the equalizer. Once the error (the difference between the training sequence and the estimated sequence) reaches the minimum mean square value, the training sequence can also be used to train the adaptive equalizer. Fig. 12a and 12b show how the adaptive equalizer uses a training sequence. Once the adaptive equalizer reaches the optimal, minimum error solution, the channel bandwidth can be estimated as follows:

wherein the method comprises the steps ofIs the discrete fourier transform of the transfer function of the equalizer. The received power for the data component may be determined assuming that the data component and the noise component are orthogonal and exhibit zero average. Assuming that the equalizer has reached the optimal solution, its output may be approximated as:

it should be noted that the number of the components,is an estimate of the training sequence z (k) defined in equation EQ (13 b) and is at least approximately equal to the training sequence when the equalizer reaches the optimal solution. Thus, the power of the signal component may be determined as follows:

Wherein the method comprises the steps ofIs a training sequence stored at the receiver. The received power for the noise component may be determined as follows:

note that d (k) is always 1 for all k values, so it is omitted in EQ (20) for clarity. In equation EQ (20), the second sum term is the autocorrelation of the training sequence, so it can be determined in advance. Further, by assuming that the data component and the noise component are orthogonal and have zero average, the result in the EQ (20) can be obtained. From the received powers for the data component and the noise component defined in EQ (19) and EQ (20), respectively, the signal-to-noise ratio at the receiver is determined as follows:

the transmission frequency and transmission power level of the transmitter may be set to provide reliable and power efficient communication between the transmitter and the receiver by training the receiver equalizer, determining the channel bandwidth and the received signal-to-noise ratio.

System operation

Attention is now directed to fig. 13a, fig. 13a illustrates an embodiment of a method, indicated generally by reference numeral 1700, which is at least applicable to starting and re-initializing a system in response to an error condition. The method begins at 1702 with powering on. After power-up and with the uphole and downhole transmitters disconnected, the downhole transceiver scans 1704 for noise using one of the methods discussed above (e.g., the method described in the above-incorporated US published patent application No. 2011-0001633). It should be noted that in another embodiment, the noise scanner may be in an uphole transceiver. After the noise scan, at 1706, a transceiver containing an appropriate noise scanner may select a transmission frequency determined to contain minimal noise. The selected frequency is then used to send a command to the downhole transceiver at 1708, with sufficient power to arrive. As mentioned above, the applicant has appreciated that a substantially unlimited amount of power is available at the drilling rig, such that communication from the drilling rig to the underground equipment can almost always be established by using only sufficient transmission power. In one embodiment, the uphole transceiver can transmit commands using, at least initially, a maximum transmitter power. Some embodiments may include a maximum power in the range of 2 watts to at least 10 watts. Some embodiments may include, for example, maximum power up to 100 watts or even higher based on the configuration of signal coupling devices and electronics used on the drilling rig. At 1708, the command identifies the frequency at which the downhole transceiver should use for transmitting the training sequence back to the uphole transceiver at the drilling rig. At 1710, the downhole transceiver may transmit a training sequence, for example, using its maximum transmitter power. At 1712, the uphole transceiver trains its receiver equalizer in response to the training sequence, determines the received signal-to-noise ratio, and determines the bandwidth of the channel, as described above. At 1714, if equalizer training fails, operation returns to 1706 to select a new transmission frequency, followed by a repeat of the subsequent steps of the method. By way of non-limiting example, the training failure decision at 1712 may be based on packet error rate, signal-to-noise ratio, or any suitable combination thereof. By way of non-limiting example, in any of the contexts described herein relating to the quality of the signal transmitted onto the drill string, a suitable threshold for establishing unsuitable performance may be 5dB for SNR and 0.2 (twenty percent) for packet error rate/bit error rate. In one embodiment, operation may return to 1704 to repeat the noise scan because the ambient noise conditions may change since the last noise scan. In another embodiment, the operator may be provided with an option to manually set parameters such as transmission frequency and/or manual override (override) automatic frequency selection at any time during operation in response to a training failure. In response to successful training or manual override, the uphole transceiver has at least established a viable transmission frequency, what symbol data rate the downhole transceiver should use and what transmitter power setting should be used to achieve reliable communications while conserving battery power at 1716. These are summarized below:

Select a transmission frequency that is within the channel bandwidth (described by EQ (16)) and contains minimal noise.

Select to use a symbol rate less than the channel bandwidth.

The transmitter power is chosen such that SNR >1.

At 1716, the operating parameters are transmitted to the downhole transceiver. The parameter selection may be a complete set of automatically selected parameters or any combination of automatically and manually selected parameters. As an example of the latter, the frequency may be selected manually, and all other parameters may be selected automatically. Further, the value of the automatically selected parameter may be adjusted in view of the manually selected parameter value. Normal operation may occur at 1720. For example, once the downhole transceiver is configured with these parameters, the downhole transceiver may begin transmitting sensor data (fig. 10 a) up to the rig. It should be appreciated that the process 1700 is automatically repeated at predetermined intervals (e.g., at predetermined lengths of drill string and/or at predetermined time intervals) during operation. In one embodiment, training may be performed at 100 feet (although any suitable distance may be used) extension of the drill string, and may be based on the dynamics of the communication channel. Further, the operator may be provided with a manual selection to initiate the method at any time. In one embodiment, at 1722, communication loss or some degree of attenuation may be detected by the uphole transceiver during continued operation. By way of non-limiting example, packet error rates may be monitored to detect signal attenuation. The Bit Error Rate (BER) may be established instantaneously, for example, by monitoring synchronization bits within the packet structure. In some embodiments, more than one aspect of signal attenuation, such as BER and SNR, may be monitored. Any suitable technique currently available or yet to be developed may be used to monitor the quality of the signal. It should be appreciated that such error rate monitoring may also be applicable to the positioning signal 66 when the positioning signal 66 is modulated with appropriate data. In response to this detection, the operation returns to the noise scan 1704. Otherwise, normal operation resumes at 1720.

Battery life and communication optimization

As evidenced by the foregoing description, applicants have appreciated that the downhole transceiver may utilize sufficient transmission power on the drill string 16 to maintain communication at a sufficiently reliable level. As indicated by fig. 13a, if the subsurface transceiver is subject to sufficient data loss due to distance and/or surface conditions, the uphole transceiver instructs the downhole transceiver to take any number of actions, alone or in combination, for the purpose of improving communication. The available actions include (1) increasing the transmission power, (2) selecting a different transmission frequency, and (3) changing the baud rate of the data being transmitted up the drill string, thus exchanging the baud rate to increase the signal-to-noise ratio. These actions may be employed with a great degree of flexibility, alone or in any suitable combination. For example, step 1706 of FIG. 13a may initially select the transmission frequency at which the lowest noise is available. Based on the training sequence, step 1712 may determine the packet error rate. If the packet error rate is too high, the baud rate may be assigned to a lower value, and the training failure at 1714 may return the procedure to 1706 with a new iteration at a lower baud rate.

One approach to increasing operating time when using an underground battery is to increase the size of the battery. Referring to fig. 1 and in one embodiment, for example, a battery assembly may be carried by the tube segment N to provide a sufficient level of available power. However, additional measures may be taken with respect to conserving battery power.

Referring to fig. 1, transceiver 64 may transmit dipole signal 66 through the ground for, for example, above-ground positioning and depth detection. Of course, the transmission of the dipole signal will consume battery power in the downhole transceiver. As an example, a typical dipole transmitter increases battery consumption by about 0.35 watts when actively driving a dipole antenna. When the antenna is not driven or signals are not coupled to the drill string, the power consumption of the transceiver 64 can be reduced to about 0.15 watts while still allowing power to be used for sensor and processing activities. The power consumption of the downhole transceiver 704 (fig. 10 a) will increase by about a modest 0.1 watt for driving the drill string, for example, using a current transformer or an electrically isolated gap to couple the signal to the drill string.

Referring to fig. 13b, a flowchart, indicated by reference numeral 1730, illustrates an embodiment of a method of dynamically and automatically controlling the transmission of positioning signals. At 1732, the ground walker automatically monitors whether the ground walker is in an active or inactive state. The locator in the active state actively receives and uses the locating signal. However, in the disabled state, the locator may stop components and/or processing related to the detection and processing of the locating signal. The monitoring may be performed in any suitable manner. For example, accelerometer 520 (FIG. 6) may easily detect any movement of the positioner. If it is determined based on accelerometer readings that the positioner has not moved for a period of time (e.g., two minutes), the disabled state may be invoked or reiterated. As another example, an ultrasonic sensor may be used to detect the proximity of the locator to the ground, for example. The disabled state may be invoked or reiterated if the locator sits stationary on a surface (e.g., a grounded surface) for a relatively short period of time (e.g., two minutes). Once a state change is detected, operation proceeds to 1734, at which point a state indication may be transmitted to the drill via telemetry signal 92 (fig. 1), with telemetry signal 92 representing a new activation/deactivation state. In response to the new status indication, at 1736, the current status may be presented on one or more displays in the system, as will be further described.

Referring to fig. 13c in conjunction with fig. 13b, the former illustrates an embodiment of a screen shot that may be presented on display 1740 in response to step 1736 and may represent screen 44 at the rig, screen 86 on device 80, and/or any suitable display in system 10. The display may display a currently automatically selected activation or deactivation state 1742 of the positioning signal and may further provide an activate/deactivate positioning signal override selection 1744 to selectively switch the positioning signal 66 between the activation and deactivation states. The manual selection may be used to override any automatically selected current state of the positioning signal. At 1746, override selections are monitored. If an override is selected, the current state of the positioning signal does not change and operation returns to 1732. If an override is not selected, operation proceeds to 1748 where a new activation/deactivation state is declared. Operation then returns to 1732. In response to changing the activation/deactivation status on the display 44 of the drilling rig, commands may be transmitted from the drill string down to the downhole transceiver 56 (fig. 6) so that the downhole transceiver can respond appropriately. If the operator is aware that the portable device is about to lose telemetry communication with the drilling rig, the operator may ensure that the positioning signal is set to an active state before telemetry is lost. In other cases, the operator may choose to use override selection 1742. For example, an operator may wish to place the locator at a stationary position on the ground and observe the progress of the boring tool on the locator display. If the positioning signal becomes disabled, the operator may use override selection 1744 to cause the downhole transceiver to resume transmission of the positioning signal. Override option 1744 is also useful when the drill rod is added to the drill string, as this can include a significant period of time. Many operators choose to confirm the position and depth of the drilling tool before adding the drill rod. After completion of the confirmation, an operator at either the drill or portable locator may instruct the locating signal to enter disabled to save downhole battery power.

Accordingly, unless the dipole signal 66 is actively needed (e.g., depth measurements are obtained), the downhole transceiver 702 may command the downhole transceiver 704 to turn off the dipole antenna transmitter to conserve battery power. Applicants have appreciated that at least 20% power savings may be achieved when no dipole signal is transmitted and no data is transmitted as an electrical signal onto the drill string in accordance with the teachings disclosed herein. In this regard, the relationship between battery life and power savings is typically non-linear, such that power savings may translate into a significantly larger percentage increase in battery life. In addition, the downhole transceiver or remote station (if used) can identify the characteristics of the dipole signal reaching the locator 80, thus maintaining depth accuracy of the locator. Thus, the power saving characteristics of the dipole signal may be changed instantaneously based on the nearby drilling environment (e.g., extreme depths or high levels of noise/interference). When surface walking positioning is not possible (e.g., during a river crossing), the uphole transceiver may instruct the downhole transceiver to turn off the dipole antenna even until further notification to conserve battery power, thereby forcing the downhole transceiver to at least cease transmission of the positioning signal 66 (fig. 6) to enable a disabled mode of the positioning signal.

To address the power saving issue, the downhole transceiver may be configured to enter a sleep mode in response to detection of no movement for a certain period of time. The time period may be based on a default time period (e.g., 10 minutes) and/or may be programmable. During sleep mode, the downhole transceiver may monitor the angular orientation of the face and wake up in response to rotation detection. In one embodiment, using the receiver 802 (fig. 10 a), the downhole transceiver may periodically monitor the drill string to check for any commands from the uphole transceiver and wake up in response to detecting a command. After waking up, the downhole transceiver may restart the same state of the positioning signal as it entered sleep. The latter is also useful in cases where, for example, the drilling machine encounters mechanical difficulties and is not operational for a certain period of time. In the event that the drill pipe breaks and the downhole transceiver goes to sleep, communication via the drill string may be maintained by pushing the drill string to reduce the gap across the break and restarting communication. The positioning signal may then be activated so that the drilling tool may be retrieved from the surface. Typically, the drilling rig will have sufficient transmission power to reach the downhole transceiver. It should be appreciated that the portable device 80 may also be configured to enter a sleep mode. In response to the operator stopping the portable device and/or entering the portable device into a sleep mode, the portable device is able to send a disable state command to the drilling machine so that the positioning signal can be stopped.

As discussed above with reference to fig. 1 and with additional reference to fig. 6, modulation of the positioning signal 66 is not required. In embodiments where the positioning signal 66 is transmitted without modulation, the applicant has appreciated that for a given level of transmission power applied to the positioning signal, an enhanced depth range and/or homing range may be provided, at least from a practical point of view as a pure tone. The enhanced capability may be due to factors including the ability to avoid spreading the carrier power to the modulation side lobes, and the application of very narrow bandwidth filtering for receiving pure tones at the locator 80. The bandwidth for such a narrow band filter may be, for example, 0.5Hz to 1Hz. It is noted that the lower limit of the range affects the response time. As stated differently, transmitting the unmodulated carrier at a given depth range and/or a given homing range may reduce the transmission power applied to the positioning signal 66, at least for saving battery power. Of course, the system of FIG. 1 provides for simultaneous modulation of the electromagnetic positioning signal and the downhole signal. By transferring, for example, data generated by a downhole sensor from modulation on an electromagnetic positioning signal to modulation on a downhole signal (traveling up the drill string), the electromagnetic positioning signal may be closer or closer to the depth or reception range provided by pure tones (unmodulated positioning signals).

In one embodiment, the portable/surface step locator 80 may provide automatic and/or manual selection of dipole transmission power and/or frequency by transmitting selection information to the drilling rig via telemetry signal 92. At the drilling rig, the uphole transceiver 600 can send a selection command to the downhole transceiver to transmit the positioning signal 66 accordingly. Since accurate depth determination depends on the transmission frequency and dipole strength, depth may be determined by any suitable component of the system, including, but not limited to, a portable locator and an uphole transceiver. In one embodiment, the portable locator 80 may be automatically and/or manually instructed to monitor characteristics of the received dipole signal 66, such as signal strength. If the signal-to-noise ratio is below a certain threshold, the portable locator may then notify the operator and/or automatically send instructions, as described above, with the aim of improving the signal-to-noise ratio. Such automatic monitoring of dipole signals and dipole signal reconfiguration may be performed in the context of lack of knowledge required for a portion of the operator of the portable positioner. For example, in response to detecting a decrease in signal-to-noise ratio, the portable locator may inherently begin scanning for other available frequencies of the dipole signal (determining a current signal-to-noise ratio associated with the other available frequencies), and thereafter select the frequency with the highest signal-to-noise ratio. In one embodiment, when the positioning signal is modulated, substantial attenuation of the positioning signal may be detected based on inability to decode angular orientation facing information, angular orientation information, and/or other status information from the positioning signal. Such attenuation of the positioning signal may occur, for example, in a highly disturbing environment.

Fig. 14 is a flow chart illustrating an embodiment of a method, indicated generally by the reference numeral 1800, suitable for use in operation of the uphole transceiver 702 of fig. 10a in cooperation with the downhole transceiver 704 of fig. 10 a. The method relates in particular to the start-up and the response to the communication loss occurring during normal operation. The method may begin at 1802 with power on or communication loss detected. At 1804, the uphole transceiver scans for noise using one of the methods described above. Typically, this step is performed with the uphole and downhole transmitters disconnected. At 1806, the uphole transceiver sends a command to the downhole transceiver specifying the transmission frequency used by the downhole transceiver and requesting the downhole transceiver to transmit the training sequence shown at 1404 in fig. 10 b. At 1808, the downhole transmitter acknowledges the request by transmitting a training sequence 1404 (fig. 10 a) to the uphole transceiver. At 1820, the mpsk carrier tracking loop and demodulator 1004 (fig. 10 b) attempts to lock onto the carrier frequency and phase of the signal from the downhole transceiver. Step 1822 determines if the carrier tracking loop is successfully locked. If not, operation returns to step 1806. If the carrier tracking loop is successfully locked, operation proceeds to 1824. This latter step determines whether a data conversion tracking loop (DTTL) 1006 in the uphole transceiver has locked onto the data symbol. If not, operation returns to step 1806. If the DTTL was successfully locked, operation proceeds to 1828. At 1828, a determination is made as to whether the downhole receiver was successfully trained in response to the training sequence. If training is successful, operation proceeds to 1830 where at least the channel bandwidth and signal-to-noise ratio at the uphole transceiver are determined at 1830. At 1832, the uphole transceiver determines the most feasible transmission frequency, e.g., based on training results and channel characteristics used by the downhole transceiver, as well as parameters including symbol rate and optimal transmission power (which can be combined with power conservation to ensure reliable communication). It is noted that the selected transmission frequency may be changed at this point in time during operation compared to the transmission frequency previously determined by step 1804. At 1836, the determined parameters are communicated to a downhole transceiver. At 1838, the downhole transceiver reconfigures transmitter operation based on the determined parameters and begins normal operation by transmitting sensor data to the uphole transceiver.

Fig. 15 is a flow chart illustrating an embodiment of a method, generally indicated by reference numeral 1900, representative of a communication protocol between a portable locator 80 and a downhole transceiver 702 for maintaining receipt of the locating signal 66 by the portable locator while transmitting the locating signal 66 (fig. 1 and 6) from the downhole transceiver. At 1910, wear of the positioning signal 66 or substantial signal attenuation is detected by the portable positioner. In one embodiment, the attenuation of the positioning signal may be determined by a Bit Error Rate (BER), which is tracked by the locator when the positioning signal is received. The signal loss may be indicated in response to the bit error rate violating a maximum BER threshold. In another embodiment, the signal attenuation may be based on a determination of a signal-to-noise ratio (SNR) of the positioning signal having a signal loss indicated by the signal-to-noise ratio in response to violating the minimum SNR. In some embodiments, several aspects of signal attenuation, such as BER and SNR, may be monitored. By way of non-limiting example, in the context of any of the techniques described herein, the threshold for establishing unsuitable signal quality may be 5dB for SNR and 0.2 (twenty percent) for BER. Of course, the signal loss (in which the signal can no longer be detected) violates these values. Any suitable technique may be employed for monitoring the quality of the positioning signal. At 1912, the portable locator performs a noise scan to identify the transmission frequency that exhibits the lowest noise level that is available, for example, as described in the above-incorporated US published patent application No. 2011-0001633. For example, in one embodiment, a Discrete Fourier Transform (DFT) may be applied to determine the noise present at the frequency of interest. It should be appreciated that any suitable technique may be employed, including, for example, a Goertzel filter, or as another example, a wavelet transform. At 1914, the portable locator transmits a signal loss command via telemetry signal 92 (fig. 1), the telemetry signal 92 identifying new parameters for locating signal 66, which may include, but are not limited to, transmission power, carrier frequency, baud rate, and modulation mode. For example, the lowest noise available carrier frequency may be initially selected along with the appropriate baud rate. If the bit error rate is too high for the selected baud rate, the baud rate may be reduced and the bit error rate redetermined. In case the baud rate becomes too low, a different modulation mode may be selected. The selection of the new modulation mode may be made in any suitable manner. By way of non-limiting example, another modulation mode that may be selected is Orthogonal Frequency Division Multiplexing (OFDM), wherein closely spaced orthogonal subcarriers may be used to carry data on multiple parallel data streams or channels in a manner known in the art. Thus, by dispersing data over multiple channels, a high immunity can be achieved at a relatively low symbol rate using many frequencies that do not interfere with each other. It is noted that for maximum depth and homing range, the modulation mode may specify that the carrier is not modulated or is substantially pure tone. At 1916, the uphole transceiver receives the signal loss command via the telemetry signal and forwards the command to the downhole transceiver. At 1920, the downhole transceiver receives the signal loss command and reconfigures the dipole transmission parameters accordingly.

Referring again to fig. 1, it should be appreciated that system 10 includes a communication system that is accompanied by numerous benefits. The communication system is comprised of an uphole transceiver located at the drilling rig, a downhole transceiver located downhole proximate to the subterranean tool, and a telemetry transceiver forming part of the surface step locator, thereby forming a first two-way communication link 2000 between the uphole transceiver and the downhole transceiver, the first two-way communication link 2000 using the drill string as an electrical conductor to provide communication between the uphole transceiver and the downhole transceiver. A second bi-directional communication link 2002 is formed between the uphole transceiver and the telemetry transceiver of the surface step locator, which employs wireless electromagnetic communication. Further, a unidirectional communication link 2004 is formed from at least the downhole transceiver of the subterranean tool to the surface step locator. These communication links provide a plurality of communication modes including a first communication mode from the downhole transceiver to the uphole transceiver at the drilling rig via the drill string using the first bi-directional communication link 2000. A second mode of communication is provided from the downhole transceiver to the uphole transceiver via the unidirectional communication link 2004, the telemetry transceiver at the surface step locator, and the second bidirectional communication link 2002. The communication modes may be managed by a communication controller/manager 2010 forming part of the uphole transceiver 702, the communication controller/manager 2010 forming part of the processing device 46 at the drilling rig so that the system can respond dynamically and automatically to any faults occurring in the system.

Referring to fig. 16 in conjunction with fig. 1, the former illustrates an embodiment of a method for operating a communication controller 2010 by way of non-limiting example, generally indicated by reference numeral 2300. During 2304 system startup, the controller may be configured to select the first communication mode as a default mode. Normal operation is entered at 2308. The state of communication mode 1 is then monitored 2312 and the state of communication mode 1 is determined in any suitable manner. For example, a failure state may be specified in response to a complete loss of signal and/or in the event that transmitting a signal in either direction between an uphole transceiver and a downhole transceiver fails to meet a given signal-to-noise ratio and/or exceeds a given bit error rate. Normal operation can be performed at 2308 as long as communication mode 1 is not problematic. If communication mode 1 is problematic based on the determination at 2312, communication mode 2 is entered at 2316 to communicate from the downhole transceiver to the uphole transceiver via locator 80. Normal operation then resumes at 2322. As part of normal operation, step 2326 monitors for a failure condition of communication mode 2. If no abnormal condition is detected with respect to communication mode 2, then a test is made at 2330 to determine if communication mode 1 is again available. If communication mode 1 is not available, normal operation resumes at 2322. On the other hand, if communication mode 1 is available, the controller switches to communication mode 1 at 2334. Returning again to step 2326, if communication mode 2 fails, the system switches to communication mode 1 at 2334. If the switch to communication mode 1 is unsuccessful, an error condition is determined at 2338 and then a transition to manual mode is made at 2342. If no error condition is detected at 2338, operation may proceed to 2346, which may provide the operator with an opportunity to switch to manual control (at 2346, if desired). If the operator does not select manual control, operation returns to 2308. It should be appreciated that method 2300 may run in the background during system operation. In so doing, the method may be performed at a fast rate of multiple iterations per second.

Applicants believe that the systems and methods described herein provide benefits not previously seen. For example, the disclosed advanced communication system facilitates two-way communication by reliably transmitting data as electrical signals directly onto an existing drill string, with no modifications other than by using advanced communication techniques that have not been deemed suitable in the context of the present system, and without the time-consuming limitations imposed by prior art (e.g., in-line-of-pipe arrangements). Applicants have recognized the benefits of using asymmetric power transmission levels in the disclosed drill string communication system. That is, transmission from the uphole transceiver to the downhole transceiver at a high power level provides the ability to reliably establish communication to the downhole transceiver, while transmission from the downhole transceiver to the uphole transceiver may be performed with a set of optimization parameters (including reliable low/minimized power levels) to meet competing concerns of reliable communication and battery power savings. The system of the present disclosure may provide additional benefits by selectively transmitting pure tone positioning signals for purposes of homing and/or positioning from a downhole transceiver to a portable above-ground positioner while allowing simultaneous transmission of data modulated up the drill string directly onto the drill string as an electrical conductor. Applicant is unaware of any existing system that has been configured in this manner. It is believed that the disclosed systems and related methods have never been seen, at least for the following reasons: the ability to provide reliable communications over a normal or extended range through direct electrical signal transmission on a drill string introduces challenges that are not only difficult to address, but those of ordinary skill in the art will immediately recognize that the combined set of challenges is virtually insurmountable.

Preferably including all elements, parts and steps described herein. It should be understood that any of these elements, parts, and steps may be replaced or deleted entirely by other elements, parts, and steps, as will be apparent to those skilled in the art.

Appendix A

Derivation of linear estimates with minimum mean square error.

Given two arbitrary variable vectors { x, y } of size Lx 1 and zero average, the linear and unbiased estimates on x are of the form

Where W is some constant matrix of size l×l. Note that bold-faced words are used for vector variables and uppercase letters in bold-faced words are used for matrix variables. The limitation on the estimation in EQ (A1) is that it must have Minimum Mean Square Error (MMSE). The estimation must therefore meet the following constraints.

Because ofMMSE with zero mean, EQ (A2) is the sum of the individual MMSEs. Let i denote the ith sample in the vector, then a single MMSE is

Note w _i Is the ith row of the matrix W. The square term of the expansion yields:

by matching w _i The bias differentiation is made to minimize the function in EQ (4A) and set it equal to zero:

wherein R is _xy，i ＝E{x(i)y ^* }，R _y ＝E{yy ^* Thus, for w _o，i The best choice to satisfy a linear, unbiased estimate of x with MMSE is

w _o，i R _y ＝R _xy，i EQ(A6)

Collect all { w _o，i ' full estimate is

W _o R _y ＝R _xy EQ(A7)

When R is _y Non-negative and positive definite matrices, then EQ (A7) will have unique solutions as follows:

therefore, equation EQ (A1) can now be rewritten as

The estimates discussed in equations EQ11a, EQ11b and EQ12 above can now be solved because they are of the form:

y＝Bx+nEQ(A10)

matrix R using equation EQ (A10) _y And R is _xy Recalculating:

R _y ＝E{yy ^* }＝E{(Bx+n)(Bx+n) ^* }＝BR _x B ^* +R _n EQ(A11)

R _xy ＝E{xy ^* }＝E{(x)(Bx+n) ^* }＝R _x B ^* EQ(A12)

wherein R is _x ＝E{xx ^* And because of R _n > 0 (i.e., n is a zero-mean random noise vector, where the covariance matrix is R _n ＝E{nn ^* 0) which produces R _y > 0. Thus, R is _y Is reversible.

It is now possible to determine from EQ (A8), EQ (A10) and EQ (A11) that there is a minimum mean square errorIs estimated as the linearity of

The foregoing description of the invention has been presented for purposes of illustration and description. It is not intended to be exhaustive or to limit the invention to the precise form disclosed, and other embodiments, modifications, and variations are possible in light of the above teachings, wherein those skilled in the art will recognize certain modifications, variations, additions and sub-combinations thereof.

Conception of

In this document, at least the following concepts are disclosed.

Concept 1: a drill string communication system that uses a drill string extending from a drilling rig to an earth-boring tool as an electrical conductor to provide communication between the drilling rig and the earth-boring tool, the system comprising:

An uphole transceiver located at the drilling rig and comprising an uphole transmitter coupling an uphole signal with uphole transmission power to the drill string for transmission to the subterranean tool; and

a downhole transceiver located downhole proximate to the subterranean tool and comprising a downhole transmitter coupling a downhole signal to the drill string for transmission to the drill string at the drilling rig at a downhole transmission power selectable within a downhole power transmission range and always greater than any selected downhole transmission power within the downhole power transmission range.

Concept 2: the system of concept 1, wherein the downhole transceiver comprises a battery to provide the downhole transmission power, and the battery imposes an upper limit on at least a selected downhole transmission power.

Conception 3: the system of concept 2, wherein the maximum downhole transmission power is no more than 5 watts.

Conception 4: the system of concept 1, wherein the uphole transceiver is configured to begin communication with the downhole transceiver at least at a maximum uphole transmitter power.

Concept 5: the system of any one of concepts 1 through 4, wherein the maximum uphole transmitter power forms an upper power limit for the uphole transmitter power range.

Conception 6: a method for operating a drill string communication system that uses a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool, the method comprising:

configuring an uphole transceiver at the drilling rig, the uphole transceiver comprising an uphole transmitter that couples an uphole signal to the drill string for transmission to the subterranean tool at an uphole transmission power;

disposing a downhole transceiver downhole proximate the downhole tool, the downhole transceiver including a downhole transmitter; and

the downhole signal is coupled from the downhole transmitter to the drill string for transmission to the drill string at the drilling rig at a downhole transmission power, the downhole transmission power being selectable within a downhole power transmission range, and the uphole transmission power always being greater than any selected downhole transmission power.

Concept 7: a method for operating a drill string communication system that uses a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool, the method comprising:

restarting communication from the drilling rig to the subterranean tool using the uphole transceiver at a maximum uphole transmission power of the uphole transceiver to couple the uphole restarted signal to the subterranean tool in response to a loss of reception of the downhole signal transmitted from the subterranean tool to the drill string using the current set of transmission parameters; and

Based on the response from the subsurface tool to the uphole restart signal, a program is entered to establish a new set of transmission parameters for at least one of the downhole signal and the uphole signal to thereafter establish communication between the drilling rig and the subsurface tool.

Concept 8: the method of concept 7 comprising, as part of the restarted signal, instructing the downhole transceiver to respond with a maximum downhole transmission power.

Conception 9: the method of concept 7 comprising configuring the downhole transceiver to respond to the restarted signal with a maximum downhole transmission power.

Concept 10: a drill string communication system that uses a drill string extending from a drilling rig to an earth-boring tool as an electrical conductor to provide communication between the drilling rig and the earth-boring tool, the system comprising:

an uphole transceiver located at the drilling rig and comprising an uphole transmitter coupling an uphole signal with uphole transmission power to the drill string for transmission to the subterranean tool;

a downhole transceiver located downhole proximate to the subterranean tool and comprising a downhole transmitter coupling a downhole signal to the drill string at a downhole transmission power for transmission to the drill string at the drilling rig and emitting an electromagnetic positioning signal having at least one selectable operating parameter, the downhole transmission power being selectable within a downhole power transmission range; and

A ground walking locator for receiving an electromagnetic positioning signal and for detecting a predetermined attenuation of the received positioning signal, and in response to said detection, the system is configured to automatically generate a reconfiguration command that changes at least one of the following parameters of the electromagnetic positioning signal: carrier frequency, transmission power, baud rate, and modulation mode.

Concept 11: the system of concept 10, wherein the ground step locator monitors the predetermined signal attenuation based on at least one of a signal-to-noise ratio and a bit error rate of the electromagnetic locating signal.

Concept 12: the system of concept 10, wherein the surface step locator is configured to generate and thereafter transmit the reconfiguration command to the drilling rig via telemetry, and the uphole transceiver is configured to transmit the reconfiguration command to the downhole transceiver via the drill string.

Concept 13: a drill string communication system that uses a drill string extending from a drilling rig to an earth-boring tool as an electrical conductor to provide communication between the drilling rig and the earth-boring tool, the system comprising:

an uphole transceiver located at the drilling rig and comprising an uphole transmitter coupling an uphole signal with uphole transmission power to the drill string for transmission to the subterranean tool;

A downhole transceiver located downhole proximate to the subterranean tool and comprising a downhole transmitter coupling a downhole signal to the drill string at a downhole transmission power for transmission to the drill string at the drilling rig and emitting an electromagnetic positioning signal having at least one selectable operating parameter, the downhole transmission power being selectable within a downhole power transmission range; and

a ground walking locator for receiving electromagnetic positioning signals and for detecting reception losses of the electromagnetic positioning signals and, in response to the reception losses, automatically indicating to the drilling machine a signal loss situation.

Concept 14: the system of concept 13, wherein the surface step locator indicates the loss of signal by transmitting a loss of signal command to an uphole transceiver at the drilling rig.

Concept 15: the system of concept 14, wherein the signal loss command specifies a new set of parameters for the electromagnetic positioning signal.

Concept 16: the system of concept 15, wherein the new set of parameters specifies at least one of the following parameters: new transmission power, new carrier frequency, new baud rate, and new modulation mode for electromagnetic positioning signals.

Concept 17: the system of concept 16, wherein the new set of parameters specifies not modulating the new carrier frequency.

Concept 18: a drill string communication system that uses a drill string extending from a drilling rig to an earth-boring tool as an electrical conductor to provide communication between the drilling rig and the earth-boring tool, the system comprising:

an uphole transceiver located at the drilling rig and comprising an uphole transmitter coupling an uphole signal to the drill string for transmission to the subterranean tool; and

a downhole transceiver located downhole proximate to the subterranean tool and comprising a downhole transmitter coupling a downhole signal to the drill string for transmission to an uphole receiver forming part of the uphole transceiver, and wherein the uphole transceiver and the downhole transceiver are configured to cooperate to automatically change at least one operational transmission parameter of the downhole signal based at least in part on signal attenuation of the downhole signal detected by the uphole transceiver.

Concept 19: the system of concept 18, wherein the uphole transceiver and the downhole transceiver are configured to automatically modify a set of operational parameters of the downhole signal in response to the signal attenuation.

Concept 20: the system of concept 19, wherein the modified set of parameters includes two or more of a carrier frequency, a power level, a baud rate, and a modulation mode.

Concept 21: the system of concept 18, wherein at least one of the downhole transceiver and the uphole transceiver comprises a noise scanner for performing a noise sweep for an available transmission frequency of the downhole signal such that a lowest noise transmission frequency is established.

Concept 22: the system of concept 21, wherein the noise scanner is configured to determine the noise spectrum on the available transmission frequency using a selected one of a fast fourier transform, a discrete fourier transform, and a power spectral density.

Concept 23: the system of concept 21, wherein the noise scanner comprises a filter bank having a plurality of bandpass filters to determine the lowest noise transmission frequency.

Concept 24: the system of concept 21, wherein the downhole transmitter and the uphole transmitter are configured to be turned off during the noise scan.

Concept 25: the system of concept 21, wherein the selected one of the uphole transceiver and the downhole transceiver is configured to initiate the noise sweep as part of the start-up procedure.

Concept 26: the system of concept 25, wherein the uphole transceiver is configured to restart the noise sweep in response to signal loss from the downhole transmitter to select at least a new transmission frequency for the downhole signal.

Concept 27: the system of concept 18, wherein the drill string comprises a channel transfer function comprising drill string distortion on each of the uphole signals, and wherein at least the uphole transceiver is configured to characterize the channel transfer function as a band-limited filter having a band-limited response.

Concept 28: the system of concept 27, wherein the band-limited response is further characterized as a finite impulse response.

Concept 29: the system of concept 27, wherein at least the uphole receiver of the uphole transceiver comprises at least one equalizer to compensate for drill string distortion.

Concept 30: the system of concept 29, wherein the equalizer includes an equalizer response, the equalizer response being customizable based on a set of equalizer coefficients such that the equalizer response is adapted to a range of variables in the channel transfer function.

Concept 31: the system of concept 30, wherein the downhole transmitter is configured to transmit a training sequence modulated onto the downhole signal and the downhole receiver is configured to recover the training sequence from the downhole signal to establish a set of equalizer coefficients.

Concept 32: the system of concept 31, wherein the uphole transceiver comprises a copy of the training sequence to compare with a received training sequence, the received training sequence representing a training sequence transmitted by the downhole transmitter and distorted by the channel transfer function.

Concept 33: the system of concept 32, wherein the downhole transceiver comprises a multiplexer that selects between the training sequence and the sensor data to modulate onto the downhole signal.

Concept 34: the system of concept 32, wherein the uphole transceiver is configured to determine the set of coefficients based on a minimum mean square error of a difference between the replica of the training sequence and the received training sequence.

Concept 35: the system of concept 18, wherein the downhole transceiver is configured to receive the sensor data and to modulate the downhole signal based on the sensor data.

Concept 36: the system of concept 34, wherein the downhole transceiver applies multi-phase shift keying to the downhole signal.

Concept 37: the system of concept 18, wherein the uphole transceiver is configured to synchronously detect the downhole signals.

Concept 38: the system of concept 37, wherein the downhole transceiver is configured to apply multi-phase shift keying to modulate the downhole signal, and the uphole transceiver comprises a multi-phase shift keying carrier tracking loop and demodulator for recovering the downhole signal.

Concept 39: the system of concept 38, wherein the downhole transceiver is configured to apply quadrature phase shift keying to the downhole signal.

Concept 40: the system of any of concepts 18 through 39, wherein the drill string includes a channel transfer function including drill string distortion on each of the uphole signals, and at least the uphole transceiver is configured to characterize the channel transfer function as a band-limited filter, and the uphole transceiver includes an in-phase equalizer and an out-of-phase equalizer to compensate for the drill string distortion.

Concept 41: the system of concept 40, wherein the uphole transceiver is configured to synchronously detect the downhole signals and includes a data transition tracking loop to switch between an in-phase equalizer and an out-of-phase equalizer.

Concept 42: an apparatus in a drill string communication system that uses a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool, and that exhibits a channel transfer function when used as the electrical conductor that carries downhole signals that are coupled to the drill string by the inground tool, the apparatus comprising:

an uphole receiver that receives the downhole signal from the drill string as a transmission signal, the transmission signal being affected by a channel transfer function, and the uphole receiver is configured to apply a compensation response to the transmission signal, the compensation response being tailored based on the channel transfer function.

Concept 43: the apparatus of concept 42, wherein the channel transfer function causes distortion of the drill string on the downhole signal, and at least the uphole receiver is configured to characterize the channel transfer function as a band-limited filter response.

Concept 44: the apparatus of concept 43, wherein the band-limited filter response is further characterized as a finite impulse response.

Concept 45: the apparatus of concept 43, wherein the uphole receiver comprises at least one equalizer to compensate for drill string distortion.

Concept 46: the apparatus of concept 45, wherein the equalizer includes an equalizer response, the equalizer response being customizable based on a set of equalizer coefficients such that the equalizer response is adapted to a range of variables in the channel transfer function.

Concept 47: the apparatus of concept 46, wherein the uphole receiver stores a copy of the training sequence, and the uphole receiver is configured to recover a transmitted version of the training sequence from the downhole signal distorted by the channel transfer function for comparison with the copy of the training sequence to establish the set of equalizer coefficients.

Concept 48: the apparatus of concept 47, wherein the uphole receiver is configured to determine the set of coefficients based on a minimum mean square error of a difference between the replica of the training sequence and the transmitted version of the training sequence.

Concept 49: a surface step locator for use in a system employing a drill string extending from a drilling rig to an inground tool configured to transmit electromagnetic locating signals, the surface step locator comprising:

a receiver configured to receive a positioning signal, detect a received attenuation of the positioning signal, and generate a signal loss command in response to the attenuation detection; and

A telemetry transmitter for transmitting signal loss commands to the drilling rig.

Concept 50: the ground walking locator of concept 49 configured to generate the signal loss command in response to a received loss of a locating signal.

Concept 51: the ground walking locator of concept 49 configured to generate the signal loss in response to a predetermined level of attenuation of the locating signal.

Concept 52: the ground walking locator of concept 49 is configured to initially perform a noise scan in response to the detection of the reception loss to identify a new frequency for the electromagnetic locating signal.

Concept 53: the ground walking locator of concept 49, wherein the signal loss command identifies at least one of the following parameters for the electromagnetic locating signal: new transmission power, new carrier frequency, new baud rate, and new modulation mode.

Concept 54: a system for performing at least an underground operation using a drill string extending from a drilling rig to an underground tool as an electrical conductor to provide communication between the drilling rig and the underground tool, the system comprising:

a downhole transceiver located downhole proximate to the subterranean tool and configured to (i) receive at least one sensor signal related to an operational parameter of the subterranean tool, (ii) generate a downhole signal, the downhole signal being transmitted to a drill string at the drilling rig and modulated based on the sensor signal, and (iii) emit an electromagnetic positioning signal for above-ground detection, wherein the positioning signal is at least not modulated by the sensor signal;

An uphole transceiver located at the drilling rig and comprising an uphole receiver configured to receive downhole signals from the drill string and to recover the sensor signals so that information relating to the operational parameters is available at the drilling rig; and

a ground walking locator receives an electromagnetic locating signal for use as at least one of a homing beacon and a tracking signal such that the detection range of the locating signal without modulation is greater for a given transmission power than the detection range of a modulated locating signal modulated by the sensor signal for the same given transmission power.

Concept 55: the system of concept 54, wherein the ground step locator comprises a narrowband filter centered on a carrier frequency of the electromagnetic locating signal.

Concept 56: the system of concept 54 or 55, wherein the surface locator is configured to be in telemetry communication with an uphole transceiver at the drilling rig at least for purposes of obtaining a correlation between sensor related data transmitted from the subterranean tool to a drill string at the uphole transceiver and surface locator generated data transmitted to the uphole transceiver via electromagnetic telemetry signals.

Concept 57: a system for performing at least an underground operation using a drill string extending from a drilling rig to an underground tool as an electrical conductor to provide communication between the drilling rig and the underground tool, the system comprising:

an uphole transceiver located at the drilling rig and comprising an uphole transmitter configured to transmit at least an uphole signal on the drill string to the subterranean tool;

a downhole transceiver positioned downhole proximate to the subterranean tool and configured to receive an uphole signal from the drill string and to selectively emit an electromagnetic positioning signal for above-ground detection;

a ground walker for receiving the electromagnetic positioning signal and for automatically detecting an activated/deactivated state of the ground walker, and in response to detecting a change in the activated/deactivated state, the ground walker being configured to transmit a status indication to the drilling machine indicating a new activated/deactivated state; and

the uphole transceiver and the downhole transceiver are further configured to cooperate to turn off an electromagnetic positioning signal in response to at least a disabled state.

Concept 58: the system of concept 57, wherein the ground step locator is configured to actively use the electromagnetic locating signal during the active state.

Concept 59: the system of concept 57, wherein the ground walker comprises at least one accelerometer that generates an accelerometer output in response to movement of the ground walker, and the ground walker is configured to detect a disabled state based on the accelerometer output.

Concept 60: the system of concept 57, wherein the ground step locator includes a sensor that detects a surface of the locator that is proximate to the ground, and the ground step locator is configured to indicate the disabled state in response to the locator being located on the surface of the ground.

Concept 61: a communication system for performing at least subterranean operations using a drill string extending from a drilling rig to a subterranean tool and a surface walk detector serving as at least one of a homing beacon and a tracking device, the communication system comprising:

an uphole transceiver located at the rig;

a downhole transceiver positioned downhole proximate to the subterranean tool;

a telemetry transceiver forming part of the surface step locator;

a first bi-directional communication link between the uphole transceiver and the downhole transceiver using the drill string as an electrical conductor to provide communication between the uphole transceiver and the downhole transceiver;

a second bi-directional communication link between the uphole transceiver and the telemetry transceiver of the surface step locator employing wireless electromagnetic communication between the uphole transceiver and the telemetry transceiver; and

At least one-way communication link from a downhole transceiver of the subterranean tool to the surface step locator is such that (i) a first communication mode is provided from the downhole transceiver via the drill string to the uphole transceiver at the drilling rig using the first two-way communication link, (ii) a second communication mode is provided from the downhole transceiver to the uphole transceiver via the one-way communication link, the telemetry transceiver at the surface step locator, and the second two-way communication link, and (iii) a controller for managing communication between the downhole transceiver and the uphole transceiver based at least in part on a system state.

Concept 62: the system of concept 61 further comprises:

a communication manager for managing communication from the downhole transceiver at the inground tool to the uphole transceiver at the drilling rig by automatically selecting between the first communication mode and the second communication mode for any given transmission from the inground tool to the drilling rig based at least in part on the current operational status of the first and second bi-directional communication links and the unidirectional communication link.

Concept 63: the system of claim 62, wherein the controller is configured to select the first communication mode as the default mode.

Claims (11)

1. A drill string communication system that uses a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool, the system comprising:

An uphole transceiver located at the drilling rig and comprising an uphole transmitter coupling an uphole signal with uphole transmission power to the drill string for transmission to the subterranean tool;

a downhole transceiver located downhole proximate the subterranean tool and comprising a downhole transmitter coupling a downhole signal to the drill string at a downhole transmission power for transmission to the drill string of the drilling rig and emitting an electromagnetic positioning signal having at least one operating parameter, the downhole transmission power being selectable within a downhole power transmission range; and

a ground walker, wherein the ground walker comprises a receiver configured to receive the electromagnetic locating signal and detect a predetermined decay of the received electromagnetic locating signal, and in response to the detection, the system is configured to automatically generate a signal loss command configured to change at least one of the following parameters of the electromagnetic locating signal: a carrier frequency, a transmission power, a baud rate, or a modulation mode, and a telemetry transmitter configured to transmit the signal loss command to the drilling rig.

2. The system of claim 1, wherein the ground step locator is configured to monitor the predetermined attenuation of the received electromagnetic positioning signal based on at least one of a bit error rate or a signal-to-noise ratio of the electromagnetic positioning signal.

3. The system of claim 1, wherein the uphole transceiver is configured to transmit the signal loss command to the downhole transceiver via the drill string.

4. A drill string communication system that uses a drill string extending from a drilling rig to an inground tool as an electrical conductor to provide communication between the drilling rig and the inground tool, the system comprising:

an uphole transceiver located at the drilling rig and comprising an uphole transmitter coupling an uphole signal with uphole transmission power to the drill string for transmission to the subterranean tool;

a downhole transceiver located downhole proximate the subterranean tool and comprising a downhole transmitter coupling a downhole signal to the drill string at a downhole transmission power for transmission to the drill string of the drilling rig and emitting an electromagnetic positioning signal having at least one operating parameter, the downhole transmission power being selectable within a downhole power transmission range; and

A ground walker, wherein the ground walker comprises a receiver configured to receive the electromagnetic locating signal and detect received wear of the electromagnetic locating signal received and automatically generate a signal wear command in response to the received wear, and a telemetry transmitter configured to transmit the signal wear command to the drilling machine.

5. The system of claim 4, wherein the signal loss command is configured to change at least one operating parameter for the electromagnetic positioning signal.

6. The system of claim 5, wherein the at least one operating parameter comprises at least one of: transmission power, carrier frequency, baud rate or modulation mode for the electromagnetic positioning signal.

7. The system of claim 6, wherein when the at least one operating parameter comprises the carrier frequency, the carrier frequency is designated as not modulated.

8. A surface step locator for use in a system employing a drill string extending from a drilling rig to an inground tool configured to transmit electromagnetic locating signals, the surface step locator comprising:

A receiver configured to receive the electromagnetic positioning signal, detect at least one of a reception loss of the electromagnetic positioning signal or an attenuation of the reception of the electromagnetic positioning signal, and generate a signal loss command in response to the detection; and

a telemetry transmitter configured to transmit the signal loss command to the drilling rig.

9. The ground-based walking locator of claim 8, wherein the receiver is configured to generate the signal loss command in response to a predetermined level of attenuation of the electromagnetic locating signal.

10. The ground walking locator of claim 8, wherein the receiver is further configured to initially perform a noise scan in response to the detection of the reception loss to identify a new frequency for the electromagnetic positioning signal.

11. The ground step locator of claim 8 wherein the signal loss command is configured to change at least one of the following parameters for the electromagnetic positioning signal: transmission power, carrier frequency, baud rate, or modulation mode.