Patent Publication Number: US-2016245075-A1

Title: Cross talk noise reduction technique for downhole instrumentation

Description:
TECHNICAL FIELD 
     This invention relates to electric signal transmission, and more particularly to reducing cross-talk interference between signal conductors. 
     BACKGROUND 
     Wells are commonly used to access regions below the earth&#39;s surface and to acquire materials from these regions, for instance during the location and extraction of petroleum oil hydrocarbons from an underground location. The construction of wells typically includes drilling a borehole and constructing a pipe structure within the borehole. Upon completion, the pipe structure provides access to the underground locations and allows for the transport of materials to the surface. 
     Before, during, and after construction of a well, a variety of tools are conventionally used to monitor various properties of the downhole environment. For example, instruments may be used to monitor the location and/or orientation of a bottom hole assembly during drilling of a borehole. Alternatively, or additionally, monitoring instruments may be lowered into the borehole, where they perform measurements of the downhole environment and transmit these measurements back to the surface. Generally, due to the narrow cross-section of the borehole, tools that are used downhole must have a correspondingly narrow cross-section in order to fit within the borehole. Accordingly, any instruments included in the tool must conform to the dimensions of the tool. Moreover, where a tool includes cabling that links various sensors, power supplies, communications modules, and other components, the cabling may be constrained to narrow channels within the tool. 
    
    
     
       DESCRIPTION OF DRAWINGS 
         FIG. 1A  is a diagram of an example well system. 
         FIG. 1B  is a diagram of an example well system that includes a logging tool in a wireline logging environment. 
         FIG. 1C  is a diagram of an example well system that includes a logging tool in a logging while drilling (LWD) environment. 
         FIG. 2A  shows a cross-section of an example logging tool. 
         FIG. 2B  shows a cross-section of an outer chassis of a logging tool. 
         FIGS. 3A-C  shows cross-sections of example logging tools with multiple cables. 
         FIG. 4A-B  show example replica signals of opposite polarity. 
         FIG. 5A-B  show example signal divider and signal combiner modules. 
         FIG. 6A  shows an example cable arrangement having twisted pair cables. 
         FIG. 6B  shows an example cable arrangement having multiple victim lines. 
     
    
    
     Like reference symbols in the various drawings indicate like elements. 
     DETAILED DESCRIPTION 
       FIG. 1A  is a diagram of an example well system  100   a . The example well system  100   a  includes a logging system  108  and a subterranean region  120  beneath the ground surface  106 . A well system can include additional or different features that are not shown in  FIG. 1A . For example, the well system  100   a  may include additional drilling system components, wireline logging system components, etc. 
     The subterranean region  120  can include all or part of one or more subterranean formations or zones. The example subterranean region  120  shown in  FIG. 1A  includes multiple subsurface layers  122  and a wellbore  104  penetrated through the subsurface layers  122 . The subsurface layers  122  can include sedimentary layers, rock layers, sand layers, or combinations of these other types of subsurface layers. One or more of the subsurface layers can contain fluids, such as brine, oil, gas, etc. Although the example wellbore  104  shown in  FIG. 1A  is a vertical wellbore, the logging system  108  can be implemented in other wellbore orientations. For example, the logging system  108  may be adapted for horizontal wellbores, slant wellbores, curved wellbores, vertical wellbores, or combinations of these. 
     The example logging system  108  includes a logging tool  102 , surface equipment  112 , and a computing subsystem  110 . In the example shown in  FIG. 1A , the logging tool  102  is a downhole logging tool that operates while disposed in the wellbore  104 . The example surface equipment  112  shown in  FIG. 1A  operates at or above the surface  106 , for example, near the well head  105 , to control the logging tool  102  and possibly other downhole equipment or other components of the well system  100 . The example computing subsystem  110  can receive and analyze logging data from the logging tool  102 . A logging system can include additional or different features, and the features of an logging system can be arranged and operated as represented in  FIG. 1A  or in another manner. 
     In some instances, all or part of the computing subsystem  110  can be implemented as a component of, or can be integrated with one or more components of, the surface equipment  112 , the logging tool  102  or both. In some cases, the computing subsystem  110  can be implemented as one or more discrete computing system structures separate from the surface equipment  112  and the logging tool  102 . 
     In some implementations, the computing subsystem  110  is embedded in the logging tool  102 , and the computing subsystem  110  and the logging tool  102  can operate concurrently while disposed in the wellbore  104 . For example, although the computing subsystem  110  is shown above the surface  106  in the example shown in  FIG. 1A , all or part of the computing subsystem  110  may reside below the surface  106 , for example, at or near the location of the logging tool  102 . 
     The well system  100   a  can include communication or telemetry equipment that allows communication among the computing subsystem  110 , the logging tool  102 , and other components of the logging system  108 . For example, the components of the logging system  108  can each include one or more transceivers or similar apparatus for wired or wireless data communication among the various components. For example, the logging system  108  can include systems and apparatus for wireline telemetry, wired pipe telemetry, mud pulse telemetry, acoustic telemetry, electromagnetic telemetry, or a combination of these other types of telemetry. In some cases, the  3   o  logging tool  102  receives commands, status signals, or other types of information from the computing subsystem  110  or another source. In some cases, the computing subsystem  110  receives logging data, status signals, or other types of information from the logging tool  102  or another source. 
     Logging operations can be performed in connection with various types of downhole operations at various stages in the lifetime of a well system. Structural attributes and components of the surface equipment  112  and logging tool  102  can be adapted for various types of logging operations. For example, logging may be performed during drilling operations, during wireline logging operations, or in other contexts. As such, the surface equipment  112  and the logging tool  102  may include, or may operate in connection with drilling equipment, wireline logging equipment, or other equipment for other types of operations. 
     In some examples, logging operations are performed during wireline logging operations.  FIG. 1B  shows an example well system  100   b  that includes the logging tool  102  in a wireline logging environment. In some example wireline logging operations, a the surface equipment  112  includes a platform above the surface  106  is equipped with a derrick  132  that supports a wireline cable  134  that extends into the wellbore  104 . Wireline logging operations can be performed, for example, after a drilling string is removed from the wellbore  104 , to allow the wireline logging tool  102  to be lowered by wireline or logging cable into the wellbore  104 . 
     In some examples, logging operations are performed during drilling operations.  FIG. 1C  shows an example well system  100   c  that includes the logging tool  102  in a logging while drilling (LWD) environment. Drilling is commonly carried out using a string of drill pipes connected together to form a drill string  140  that is lowered through a rotary table into the wellbore  104 . In some cases, a drilling rig  142  at the surface  106  supports the drill string  140 , as the drill string  140  is operated to drill a wellbore penetrating the subterranean region  120 . The drill string  140  may include, for example, a kelly, drill pipe, a bottom hole assembly, and other components. The bottom hole assembly on the drill string may include drill collars, drill bits, the logging tool  102 , and other components. The logging tools may include measuring while drilling (MWD) tools, LWD tools, and others. 
     As shown, for example, in  FIG. 1B , the logging tool  102  can be suspended in the wellbore  104  by a coiled tubing, wireline cable, or another structure that connects the tool to a surface control unit or other components of the surface equipment  112 . In some example implementations, the logging tool  102  is lowered to the bottom of a region of interest and subsequently pulled upward (e.g., at a substantially constant speed) through the region of interest. As shown, for example, in  FIG. 1C , the logging tool  102  can be deployed in the wellbore  104  on jointed drill pipe, hard wired drill pipe, or other deployment hardware. In some example implementations, the logging tool  102  collects data during drilling operations as it moves downward through the region of interest during drilling operations. In some example implementations, the logging tool  102  collects data while the drilling string  140  is moving, for example, while it is being tripped in or tripped out of the wellbore  104 . 
     In some example implementations, the logging tool  102  collects data at discrete logging points in the wellbore  104 . For example, the logging tool  102  can move upward or downward incrementally to each logging point at a series of depths in the wellbore  104 . At each logging point, instruments in the logging tool  102  perform measurements on the subterranean region  120 . The measurement data can be communicated to the computing subsystem  110  for storage, processing, and analysis. Such data may be gathered and analyzed during drilling operations (e.g., during logging while drilling (LWD) operations), during wireline logging operations, or during other types of activities. 
     The computing subsystem  110  can receive and analyze the measurement data from the logging tool  102  to detect properties of various subsurface layers  122 . For example, the computing subsystem  110  can identify the density, material content, or other properties of the subsurface layers  122  based on the measurements acquired by the logging tool  102  in the wellbore  104 . 
     Referring to  FIG. 2 , an example logging tool  102  includes an outer chassis  202  that surrounds several electrical components  204 . The outer chassis  202  is of a generally tubular shape of length  214 , and includes an inner channel  206  for holding the components  204 . These components  204  are interconnected by a cable  208 , an electrical conductor that carries signaling information and/or power between each of the electrical components  204 . In some implementations, other electrical conductors can be used, either alternatively or additionally to cable  208 . Other example electrical conductors include electrically conductive wires, traces, or other structures capable of carrying electric signaling information and/or power. 
     The components  204  provide various functions to the logging tool  102 . In some implementations, components  204  include sensor modules that perform measurements on the surrounding medium. Examples of sensor modules include force sensors, nuclear magnetic resonance sensors, magnetometers, magnetic field sensors, acoustic sensors, temperature sensors, electric field sensors, pressure sensors, optical sensors, proximity sensors, accelerometers, and so forth. Such sensors may be of different types as to the nature of their sensitive material, such as resistance or conductance sensitive, capacitance sensitive, electro-magnetic, photonic, piezoelectric, mechanical (using masses, springs, dampers), and so forth. In some implementations, components  204  include control modules to control the operation of the logging  102  and/or to process measurement data obtained from sensor modules. Example of control modules include: data acquisition and data processing modules, such as those implemented on field-programmable gate arrays (FPGAs), digital signal processors (DSPs), or other data processing devices. In some implementations, components  204  include communications modules to send and/or receive communications signals from other components of the well system, for instance surface equipment  112 . Examples of communications modules may involve different types of signal modulations (AM, FM, SSB, DSB, FSK, PPM, QAM, etc.), protocols (such as TCP/IP, CAN, SPI, etc.), or line codes (such as Manchester, Non-Return-to-Zero, MLT-3, Biphase Mark, and so forth. In some implementations, components  204  include power modules that provide electrical power to logging tool  102 . Examples of power modules include: DC power sources and AC power sources that may operate at different voltages and/or frequencies (e.g., 12V, 24V, +/−5V, +/−15V, 3.3V for DC and 110 VAC, 220 VAC and 440 VAC @60 Hz for AC). In some implementations, components  204  can include additional types of electronic components other than those described above. In some implementations, logging tool  102  includes more than two components  204 , for instance three, four, five, and so forth. In some implementations, components  204  are interconnected using more than one cable  208 , and logging tool  102  can include, for instance, two, three, four, or more cables  208 . In some implementations, one or more cables  208  are included as a part of the component or as a part of the component&#39;s assembly. 
     During use, logging tool  102  must fit into the wellbore  104 , and should be able to pass freely within the confines of the wellbore  104 . Accordingly, the dimensions of the logging tool  102  are constrained by the dimensions of the wellbore  104 , which typically has a diameter in a range from about 5 inches up to about 50 inches. For instance, in order for the logging tool  102  to fit into a wellbore  104 , the outer chassis  202  must have an outer diameter  210  that is less than the diameter of the wellbore  104 . As an example, in some implementations, the wellbore  104  is approximately 5 inches in diameter and the outer diameter  210  of the outer chassis  202  is approximately 2⅞ inches. In other examples, the outer diameter  210  of the outer chassis  202  is between approximately 1 inch and 5 inches. Likewise, the inner diameter  212  of the outer chassis  202  is also constrained. For instance, the inner diameter  212  must be small enough so that the outer chassis  202  is thick enough to protect the components  204  of the logging tool  102 . As an example, in some implementations, the inner diameter  212  of the outer chassis  202  is approximately 3 inches (e.g., for an Open Hole Logging tool). In some implementations, the inner diameter  212  can be less than 3 inches. For example, in some implementations, the inner diameter  212  is approximately 1⅛″ (e.g., for an thru-tubing Cased Hole logging tool.) 
     Due to these constraints, the channel  206  is limited in size, and the components  204  and the cables  208  within the channel  206  are in close proximity with one another. As an example, in some implementations, multiple cables  208  run parallel to each with essentially no separation (i.e., the cables touch each other), and the conductive elements of the cables  208  are separated by the cables&#39; applied coatings (e.g., a Teflon or other insulating coating.) In some implementations, multiple cables  208  run parallel to each other with greater than zero separation (e.g., separated by ⅛ inches, ¼ inches, ⅜ inches, and so forth.) This close proximity can be problematic for sensorial or signaling information carried by the cables  208  due to the effects of crosstalk interference. Crosstalk is a phenomenon by which an electronic signal transmitted on one electrical circuit creates an undesired effect in another electrical circuit. Crosstalk can result from several phenomena, including capacitive, inductive, or conductive coupling from one circuit (or part of a circuit) to another. Referring to  FIG. 3A , an example tool  102  includes four components  204   a - d , and two cables  208   a  and  208   b  carry electronic signals between components  204   a  and  204   b , and between  204   c  and  204   d , respectively. The first cable  208   a  (termed the “contaminating line”) can induce undesired currents on the second cable  208   b  (termed the “victim line”) due to mutual inductance  302  between cables  208   a  and  208   b . Current  304  carried by the contaminating line  208   a  will induce current  306  on the victim circuit  208   b  opposite of the driving current  304  in accordance with Lenz&#39;s Law. In another example, a contaminating circuit can induce undesired currents on the victim circuit due to mutual capacitance  308  between cables  208   a  and  208   b . Current  304  carried by the contaminating line  208   a  will induce current  310  that flows in both directions on the victim line  208   b.    
     In some implementations, the signaling information carried by cables  208  may be relatively weak (e.g., on the order of sub-micro-volts of sub-nano-amperes), and may be highly susceptible to crosstalk resulting from signal information of a similar or greater order of magnitude and current carried in a neighboring cable  208 . This problem is exacerbated when the cables carry signals that have AC components (i.e., time-varying sinusoidal components), and is further exacerbated when the frequency of these components become higher and as the electrical power carried by these components increases. This occurs because higher frequencies may propagate through intrinsic or parasitic capacitances that exist between cables and the other mechanical or electronic components of the logging tool. Further, the more power such signals carry, the more energy may leak out through these mechanisms, causing stronger effects on the victim lines or components in their vicinity. Further, the presence of current loops in the cables or components can magnetically couple signals through the mutual inductances existing between conductive interfaces and other electrical and mechanical elements in their vicinity. These problems can further contaminate the electronic signals carried by the cables  208 , and may impair or prevent accurate signal transmission. Similar problems can also arise in static or  3   o  dynamic magnetic field measurements when the static field measuring sensors are located next to lines carrying DC or AC signals associated with strong currents due to the static or dynamic magnetic fields created by such currents around the cables carrying them. The proposed technique also addresses such cases as the magnetic fields created by the closely-located lines carrying currents travelling in opposite directions will cancel each other. 
     In some scenarios, crosstalk interference can also decrease the signal-to-noise ratio (SNR) of a signal (i.e., the level of a desired signal to the level of background noise.) For instance, some applications require a high SNR (e.g., an SNR of 10 or greater), for example earth rock conductivity measurements, acoustic measurements (e.g., travel time of compressive and shear mechanical waves in rocks), recovery of low-frequency (sonic) or high-frequency (ultra-sonic) acoustic signals in front of well bonded pipes, measurement of rock dielectric properties, measurement of magnetic resonance parameters such as formation bulk relaxation times T 1  and T 2 , measurements of tool-frame components of local earth magnetic field for image orientation purposes, and so forth. In these applications, crosstalk interface can reduce the SNR below usable levels. This reduction in SNR can result in inaccurate signal recovery, and can degrade the performance of the measuring instrument by reducing the accuracy and the precision (i.e., the repeatability) of the affected measurements. 
     In another example, in applications that require a relatively low SNR (e.g., an SNR of 2-5), crosstalk interface can also reduce SNR, and can degrade the performance of the device. As an example, in some implementations, a sensor produces electric signals between 0 microvolts and 1000 microvolts and the physical parameter measurement derived from that electric signal is obtained by taking the logarithm of its signals. If the sensor is known to accurately measure a signal between 50 and 1000 microvolts to within approximately 2% of its true value, an interference level of 25 microvolts occurring in the frequency range of the measured signal represents a considerable part of the sensor&#39;s accuracy range. This can render the accuracy of the sensor&#39;s measurements invalid or may push the sensor outside its known accuracy specifications. 
     In another example, the physical quantity to be detected may be related to the location (i.e., the frequency) of the maximum spectral component in the frequency spectrum produced by a sensor. In some circumstances, if the victim line (carrying the sensor signal) suffers interference from contaminating lines travelling in lines located in their vicinity, the frequency spectra of one or more of the contaminating signals might be stronger than the frequency spectrum produced by the victim signal. This may lead to an inaccurate measurement or to an incorrect detection of an observed event. For instance, in some implementations, the thickness of a well pipe is measured using the method described above, using a piezoelectric (PE) pulse-echo-type sensor. If the contaminating signal has a stronger peak than the sensor signal in the frequency range corresponding to the expected thickness of the well pipe, then the contamination will result in an inaccurate measurement. 
     As additional examples, tools such as magnetic resonance imaging logging (MRIL) and multicomponent induction (MCI) tools include antennae that are in close proximity to conductors carrying analog and/or digital signals. In another example, tools such as oil mud reservoir imager (OMRI) and electrical micro imaging (EMI) tools include magnetometers that are in close proximity to conductors carrying analog and/or digital signals. These components and their corresponding signaling wires are subject to crosstalk interference from nearby contaminating lines, and their performance can be adversely as a result. 
     In order to reduce these crosstalk effects, cables  208  that carry contaminating signals can be routed using physically adjacent cables in pairs that carry replica signals of opposite polarity. Keeping the cables  208  in close proximity will reduce loop area and will cause the magnetic fields induced by the wires carrying the paired signals to cancel. Accordingly, the crosstalk induced both by the differential and common-mode components of these two signals on any other medium or device cancel each other. 
     This technique can be used to reduce the adverse effects of crosstalk interference in a wide variety of applications, including sensorial applications, communications, signaling, event trigger/detection, or any other application in which electronic signals are transmitted. 
     Referring to  FIG. 3B , in an example, cable  208   a  can be replaced by a pair of cables  208   c  and  208   d  that carry electronic signals between components  204   a  and  204   b . Cables  208   c  and  208   d  carry replica signals that are opposite in polarity. Accordingly, current  322  carried by cable  208   c  induces current  324  on cable  208   b  due to mutual inductance  326  between cables  208   b  and  208   c , and current  328  carried by cable  208   d  induces current  330  on cable  208   b  due to mutual inductance  332  between cables  208   b  and  208   d . As currents  322  and  328  are replica signals that are opposite in polarity, induced currents  324  and  330  on cable  208   b  cancel. In a similar manner, current  322  carried by cable  208   c  induces current  334  due to mutual capacitance  336  between cables  208   b  and  208   c , and current  328  carried by cable  208   d  induces current  340  on cable  208   b  due to mutual capacitance  342  between cables  208   b  and  208   d . As currents  322  and  328  are replica signals that are opposite in polarity, induced currents  334  and  340  on cable  208   b  cancel. In this manner, crosstalk effects experienced by  208   b  are canceled. 
     Cables  208  that carry contaminating signals can be routed using this paired arrangement in order to cancel crosstalk effects on other interference-sensitive components. For instance, this arrangement can be used to reduce crosstalk effects on an antenna. Referring  FIG. 3C , an antenna  352  is connected to component  204   c , and cables  208   c  and  208   d  carry electronic signals between components  204   a  and  204   b . In a similar manner as shown in  FIG. 3B  current  322  carried by cable  208   c  and current  328  carried by cable  208   d  are replica signals that are opposite in polarity, and crosstalk effects induced by  208   c  and  208   d  on antenna  352  are cancelled. 
     Replica signals of opposite polarity are signals that, when added together, result in a flat waveform (i.e., a waveform with zero amplitude) with a zero constant (i.e., a DC component of zero). That is, one replica signal is the multiplicative inverse of the other, but is otherwise identical. Replica signals of opposite polarity can be analog signals or digital signals. For example, referring to  FIG. 4A , signal  402  and  404  are analog replica signals of opposite polarity, and when added, result in a flat waveform  406  with a zero constant. In another example, referring to  FIG. 4B , signal  408  and  410  are digital replica signals of opposite polarity, and when added, result in a flat waveform  412  with a zero constant. Replica signals of opposite polarity can be represented as identical signals travelling in opposite directions, or a pair of signals in which one signal is the multiplicative inverse of the other. 
     A single signal can be converted into a pair of replica signals of opposite polarity, then converted back to the original signal in various ways. In an example, referring to  FIG. 5A , a component  204   e  includes a signal generator  502  that generates a signal s. Signal s is converted into a pair of replica signals +s/2 and −s/2 by a signal divider module  504 , which includes a pair of amplifiers  506  and  508  that amplify signal s with a gain of +0.5 and −0.5, respectively. Replica signals +s/2 and −s/2 are carried by cables  208   e  and  208   f , respectively, to component  204   f . Replica signals +s/2 and −s/2 are converted back into the original signal s by a signal combiner module  510 , which includes a subtractor  512  that subtracts signal −s/2 from +s/2, resulting in the original signal s. Signal s is transmitted to a receiver module  514  that detects and interprets the signal s. 
     While the above example includes amplifiers  506  and  508  with gains of +0.5 and −0.5, respectively, other gains can be used, so long as the gain of amplifier  506  is the multiplicative inverse of that of amplifier  508 . In some implementations, if the gains of amplifier  506  and  508  are not +0.5 and −0.5, respectively, signal combiner module  510  includes amplifiers  516  and  518  to convert the signals carried by cables  208   e  and  208   f  back to +s/2 and −s/2, respectively. As an example, if the gains of amplifiers  506  and  508  are 2 and −2, respectively, the gains of amplifiers  516  and  518  are 0.25 and −0.25, respectively. 
     In another example, referring to  FIG. 5B , a component  204   g  includes a signal generator  520  that generates a signal s. Signal s is converted into a pair of replica signals s and −s by a signal divider module  522 , which includes coupled inductors  524  and  526  that induce replica signals s and −s along cables  208   g  and  208   h , respectively (represented as currents traveling in different directions). Replica signals +s and −s are carried by to component  204   h , where they are converted back to the original single signal by a signal combiner module  528 . Signal combiner module  528  includes coupled inductors  530  and  532 , which includes the original signal s. Signal s  3   o  is transmitted to a receiver module  534  that detects and interprets the signal s. 
     While different examples of converting a single are described above, these examples are non-limiting. Other techniques may be used to convert single signals into pairs of replica signals of opposite polarity. For example, in some implementations, the signal divider modules and the signal combiner modules are separate from other electrical components, and can be positioned, for instance, between these other electrical components. In some implementations, signal divider modules and signal combiner modules can include combinations of amplifiers and/or inductors in different arrangements in order to generate replica signals of opposite polarity. 
     In some implementations, paired cables can be twisted together as twisted pairs in order to reduce crosstalk interference of the signals of the paired cables induced by other external sources. For example, as illustrated in  FIG. 6A , cables  602  and  604  carrying corresponding replica signals of opposite polarity can be twisted together into a twisted pair  606 . The resulting twisted pair  606  counters the effect of crosstalk by continuously exchanging the position of cables  602  and  604 , and distributes the effects of crosstalk as common-mode noise instead of as differential noise. 
     While cables have been shown to run parallel between components, this need not be the case. Cables can run parallel along the length of the tool, or can be twisted, bent, or otherwise routed to following any geometric pattern, so long as the cables remain in close proximity. The precise value of this proximity depends on frequency and power of the contaminating and victim signals, and may different from application to application. For each application, the proximity can be determined empirically and/or analytically (e.g., by calculating interference effects using Lenz&#39;s law or other appropriate electromagnetic theory.) 
     In some implementations, multiple victim lines can be protected against crosstalk from contaminating lines by forming twisted pairs. For example, as illustrated in  FIG. 6B , contaminating lines  610  and  612  carry a pair of replica signals of opposite polarity. Multiple victim lines  610  are positioned adjacent to lines  610  and  612 . The crosstalk induced both by the differential and common-mode components of the two signals on the victim lines  610  cancel each other. The number  3   o  of victim lines  610  can vary depending on the application. For example, in some implementations, there are two victim lines. In some implementations, there are more than two victim lines, for example three, four, five, ten, fifteen, twenty, etc.) 
     While the signal carried by a pair of contaminating lines and the signal carried by a victim line are independent (i.e., they do not carry the same signal), contaminating lines and victim lines can be connected to one or more of the same components. For instance, in some implementations, contaminating lines and victim lines originate from a single component, and terminate at a single component. In some implementations, contaminating lines and victim lines originate from a single component, terminate from a single component, or both. In this manner, paired contaminating lines can be used to carry signals between any two components, regardless of the arrangement of the victim line. 
     In some implementations, the victim line and contaminating line carry signals that have similar or identical frequency harmonics. In an example, in some implementations, the contaminating line carries  1553  communications signals (e.g., signals of approximately 435 KHz), and the victim line carries a signaling information from a magnetic resonance tool (e.g., signals of approximately 870 KHz). In some implementations, the contaminating signals are of a higher frequency than the victim signals. For instance, the contaminating signal is approximately two, three, four, or other integer factors higher in frequency than the victim signal. In some implementations, the victim signals are of a higher frequency than the contaminating signals. For instance, the victim signal is approximately two, three, four, or other integer factors higher in frequency than the contaminating signal. As described above, regardless of which signal has a greater frequency, crosstalk on the victim line can be reduced by converting the contaminating signals to pairs of replica signals of opposite polarity, and routing the converted signals using physically adjacent pairs of cables. 
     In some implementations, the proposed techniques are also relevant even in cases where the victim signals and the contaminating signals have substantially different frequencies. For example, in some implementations, crosstalk effects on a victim line can be reduced without the use of frequency-based filters (e.g., low-pass, band-pass, or high-pass filters), thereby avoiding the additional cost and/or complexity associated with filter-based designs. 
     While the outer chassis  202  of logging tool  102  is described above as generally tubular, outer chassis  202  can be other shapes. For instance, in some implementations, outer chassis  202  includes curved, polygonal, and/or irregular features. In some implementations, the channel  206  includes curved, polygonal, and/or irregular features. Further, channel  206  need not extend across the entire length of outer chassis  202 , and can instead extend across a portion of the outer chassis  202 . Further still, channel  206  can have a variety of lengths. For instance, in some implementations, channel  206  is between 6 inches and about 10 feet (e.g., in the case of downhole logging tools). The outer chassis  202  can also be modified in other ways based on the intended application, and is not limited to these examples. 
     While different implementations for reducing crosstalk interference have been described in the context of a downhole logging tool, these implementations are non-limiting, and can be applied to applications beyond logging tools in downhole environments. For instance, a contaminating signal can be converted into a pair of replica signals of opposite polarity, then routed in physically adjacent electrical conductors in a variety of other applications where unwanted cross-talk between signal lines may present an issue, including in above ground logging instruments, telecommunications devices (e.g., signal transmission lines), and underground logging instruments (e.g., underwater sondes, deep water logging tools, NMR logging tools, density logging tools, and other logging tools). For example, the disclosed techniques for cross-talk reduction can be used in applications where space constraints require running multiple cables in close proximity, such as in aerospace vehicles (e.g., airplanes and spacecraft) or in submersibles. 
     In general, in an aspect, a downhole tool includes a plurality of electrical conductors extending through a channel connecting a first portion of the downhole tool with a second portion of the downhole tool. At least some of the plurality of electrical conductors electrically connect one or more electronics modules in the first portion of the downhole tool with one or more electronics modules in the second portion of the downhole tool. The plurality of electrical conductors includes a first electrical conductor, a second electrical conductor, and a third electrical conductor. The second and third electrical conductors are part of an electrical circuit. During operation of the downhole tool, the first electrical conductor carries a first electrical signal, and one of the electronics modules provides a second electrical signal to the second electrical conductor and a third electrical signal to the third electrical conductor such that cross-talk induced by the second electrical signal on the first electrical signal is reduced by cross-talk induced by the third electrical signal on the first electrical signal. 
     Implementations of this aspect may include one or more of the following features: 
     The one electronics module can provide the third electrical signal, where the third electrical signal is a replica of the second electrical signal with opposite polarity. 
     The one electronics module can include a signal generator for generating an input electrical signal and the electronics module can be configured to generate the second and third electrical signals based on the input signal. The one electronics module can include a signal divider which divides the input electrical signal to provide the second and third electrical signals. The one electronics module can include an induction module which induces the second and third electrical signals in the second and third electrical conductors, respectively, based on the input electrical signal. 
     The downhole tool can include a sensor assembly, where the first electrical conductor is a component of the sensor assembly. 
     The first electrical conductor can be an antenna. 
     The sensor can be selected from the group that includes a force sensor, a nuclear magnetic resonance sensor, a magnetometer, a magnetic field sensor, an acoustic sensor, a temperature sensor, an electric field sensor, a pressure sensor, an optical sensor, a proximity sensor, and an accelerometer. 
     The second electrical conductor and the third electrical conductor can extend parallel to each other in the channel. The second electrical conductor and the third electrical conductor can be twisted together to form a twisted pair. 
     The channel can have a length between approximately 6 inches and 10 feet (e.g., about 6, 6.5, 7, 7.5, 8 inches, and so forth). The channel can have an inner diameter of about 3 inches or less (e.g., about 2 inches, between 1-2 inches, between 0.1-1 inch, and so forth). 
     One or more of the signals can be AC signals. One or more of the signals can be DC signals. 
     The first electrical signal can have a signal to noise ratio (SNR) of approximately 10 or greater (e.g., an SNR of 10, 20, 30, 40, and so forth). In some implementations, it is desirable to keep the SNR as high as possible (i.e., to have as little noise as possible). The first electrical signal can have an SNR of between approximately 2 and 5 (e.g., an SNR of 2, 2.5, 3, 3.5, and so forth). 
     The downhole tool can include one or more additional cables extending through the channel. In some implementations, at least ten cables can extend through the channel. 
     In some implementations, the downhole tool is a well-logging tool. In some implementations, the downhole tool is a sonde. 
     In general, in another aspect, a method for reducing cross-talk in a first electrical signal includes transmitting a first electrical signal along a first electrical conductor running through a channel. The method also includes simultaneously to transmitting the first electrical signal, generating a second electrical signal along a second electrical conductor running through the channel and generating a third electrical signal along a third cable running through the channel. The second and third electrical conductors are in sufficient proximity to the first electrical conductor to induce cross-talk in the first electrical conductor, the second and third electrical signals are generated so that cross-talk induced by the second electrical signal on the first electrical signal is reduced by cross-talk induced by the third electrical signal on the first electrical signal. 
     Implementations of this aspect may include one or more of the following features: 
     One or more of the signals can be AC signals. One or more of the signals have be DC signals. 
     The first electrical signal can have a signal to noise ratio (SNR) of approximately 10 or greater (e.g., an SNR of 10, 20, 30, 40, and so forth). In some implementations, it is desirable to keep the SNR as high as possible (i.e., to have as little noise as possible). The first electrical signal can have an SNR of between approximately 2 and 5 (e.g., an SNR of 2, 2.5, 3, 3.5, and so forth). 
     In general, in another aspect, a method of using a downhole tool includes directing one or more electrical signals between different portions of the downhole tool using one or more of the methods for reducing cross-talk as described above. 
     The method of using a downhole tool can include disposing the downhole tool in a borehole, and performing a logging operation with the downhole tool. 
     A number of embodiments have been described. Other embodiments are within the scope of the following claims.