Abstract:
Aspects of this invention include a downhole tool having first and second members disposed to translate substantially linearly with respect to one another. A magnet is deployed on the first member and a plurality of magnetic field sensors is deployed on the second member. The magnetic field sensors are spaced in a direction substantially parallel with a direction of translation between the first and second members. The tool typically further includes a controller disposed to determine a linear position of the first and second members with respect to one another from magnetic flux measurements made at the magnetic field sensors. Exemplary position sensor embodiments of the present invention are non-contact and therefore are not typically subject to mechanical wear. Embodiments of the invention therefore tend to advantageously provide for accurate and reliable linear position measurements.

Description:
RELATED APPLICATIONS 
     None. 
     FIELD OF THE INVENTION 
     The present invention relates generally to downhole tools, for example, including directional drilling tools having one or more steering blades. More particularly, embodiments of this invention relate to a sensor apparatus and a method for determining the linear position of various components, such as steering blades and/or hydraulic pistons used in downhole tools. 
     BACKGROUND OF THE INVENTION 
     Position sensing tools have several important applications in downhole tools used in subterranean drilling. For example, many drilling applications require directional drilling tools to control the lateral drilling direction. Such steering tools commonly include a plurality of force application members (also referred to herein as blades) that may be independently extended out from and retracted into a housing. The blades are disposed to extend outward from the housing into contact with the borehole wall and to thereby displace the housing from the centerline of a borehole during drilling. Blade position sensors are useful for determining blade extension. Accurate blade position measurements facilitate more accurate steering of the drill bit. Additionally, such blades are typically controlled by a hydraulic circuit. The measurement of a piston position within a hydraulic reservoir may be utilized, for example, to calculate the volume of pressurized hydraulic fluid available to actuate the blades. 
     Various position and displacement sensors are known in the downhole arts for measuring the position of pistons, blades, and other movable components on downhole tools (e.g., including wireline tools, logging-while-drilling tools, measurement-while-drilling tools, and steering tools). Such sensors typically make use of analog sensing devices such as potentiometers, pressure transducers, or ultrasonic transducers. For example, Webster, in U.S. Pat. No. 5,603,386 discloses a downhole steering tool in which each blade is fitted with a sensor (such as a potentiometer) for measuring the borehole size and the displacement of the blade. 
     While prior art sensors are known to be serviceable, such as for measuring blade and/or piston position, they are also known to suffer from various drawbacks. For example, potentiometers are known to be susceptible to mechanical wear and temperature drift due to the analog sensing and outputting mechanism utilized. Pressure transducers are known to be inaccurate for position sensing applications (particularly in demanding downhole environments), and the installation of such sensors tends to be complicated and expensive, e.g., requiring o-rings and/or other seals. The above-described drawbacks of prior art sensor arrangements often result in unreliable and inaccurate position data and also tend to increase the fabrication and maintenance expense of downhole tools. 
     Therefore, there exists a need for an improved sensor apparatus and method for accurately determining a position and/or distance of various downhole tool components. In particular, there exists a need for improved downhole tool position sensor deployments, e.g., including wireline, logging-while-drilling (LWD), measurement-while-drilling (MWD), and steering tool deployments. 
     SUMMARY OF THE INVENTION 
     The present invention addresses one or more of the above-described drawbacks of prior art tools and methods. One exemplary aspect of this invention includes a downhole tool having a sensor arrangement for measuring the position of a blade or a hydraulic piston. In one exemplary embodiment, a rotary steerable tool in accordance with this invention includes a substantially linear array of magnetic sensors deployed along an outer surface of a hydraulic housing, and a magnet assembly fixed to the piston whose position is to be measured. The position of the magnet (and therefore the piston) may be measured, for example, by determining the location within the magnetic sensor array that experiences a peak magnetic field induced by the magnet assembly. In one embodiment, magnetic sensor measurements may be advantageously transmitted to a microprocessor that is programmed to apply a curve-fitting program to the sensor data. The position of the magnet assembly may then be calculated, for example, by determining the maxima/minima of an equation that characterizes the magnetic field strength data gathered from the magnetic sensors. 
     Exemplary embodiments of the present invention may advantageously provide several technical advantages. For example, sensor embodiments in accordance with the present invention are non-contact and therefore not typically subject to mechanical wear. Moreover, embodiments of this invention tend to provide for accurate and reliable measurements with very little drift despite the high temperatures and pressures commonly encountered by downhole tools. Additionally, embodiments of the invention are typically small, low mass, and low cost and tend to require minimal maintenance. 
     In one aspect the present invention includes a downhole tool. The downhole tool includes a downhole tool body and first and second members disposed to translate substantially linearly with respect to one another. A magnet is deployed on the first member and a plurality of magnetic field sensors is deployed on the second member. The magnetic field sensors are spaced in a direction substantially parallel with a direction of translation between the first and second members. The downhole tool further includes a controller disposed to determine a linear position of the first and second members with respect to one another from magnetic flux measurements at the magnetic field sensors. 
     In another aspect this invention includes a downhole steering tool configured to operate in a borehole. The steering tool includes at least one blade deployed in a housing and a position sensor disposed to measure the position of the blade relative to the housing. The blade is configured to displace between radially opposed retracted and extended positions in the housing. The position sensor includes a magnet assembly deployed on either the blade or the housing and a linear array of magnetic field sensors deployed on either the blade or the housing such that the linear array is substantially parallel with a direction of extension and retraction of the blade. The magnet assembly and linear array are disposed to translate with respect to one another as the blade is retracted and extended in the housing. At least one of the magnetic field sensors is in sensory range of magnetic flux emanating from the magnet assembly. 
     In still another aspect this invention includes a downhole tool. The downhole tool includes a downhole tool body and a hydraulic fluid chamber deployed in the tool body. The hydraulic fluid chamber includes a piston deployed therein and is disposed to provide pressurized hydraulic fluid to at least one hydraulically actuated tool member. The downhole tool further includes a position sensor disposed to measure a position of the piston in the chamber. The position sensor includes a magnet assembly deployed on the piston and a linear array of magnetic field sensors deployed on the tool body such that the linear array is substantially parallel with a direction of motion of the piston in the chamber. At least one of the magnetic field sensors is in sensory range of magnetic flux emanating from the magnet assembly. 
     The foregoing has outlined rather broadly the features of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other methods, structures, and encoding schemes for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which: 
         FIG. 1  depicts a drilling rig on which exemplary embodiments of the present invention may be deployed. 
         FIG. 2  is a perspective view of the steering tool shown in  FIG. 1 . 
         FIG. 3  depicts an exemplary hydraulic circuit in which exemplary embodiments of the present invention may be deployed. 
         FIG. 4A  depicts one exemplary embodiment of a position sensor, in accordance with the present invention, deployed on a hydraulic piston. 
         FIG. 4B  depicts another exemplary embodiment of a position sensor, in accordance with the present invention, deployed on the hydraulic piston shown on  FIG. 4A . 
         FIG. 5  depicts an exemplary embodiment of a position sensor deployed on a blade. 
         FIG. 6  depicts an exemplary embodiment of a position sensor deployed on a pump. 
         FIG. 7A  depicts a graph of magnetic field strength versus distance for an exemplary data set measured by the sensor arrangement depicted on  FIG. 4A . 
         FIG. 7B  depicts a portion of the graph shown on  FIG. 7A  about the maximum. 
         FIG. 8A  depicts a graph of magnetic field strength versus distance for an exemplary data set measured by the sensor arrangement depicted on  FIG. 4B . 
         FIG. 8B  depicts a portion of the graph shown on  FIG. 8A  about the zero-crossing. 
     
    
    
     DETAILED DESCRIPTION 
     Referring first to  FIGS. 1 to 6 , it will be understood that features or aspects of the embodiments illustrated may be shown from various views. Where such features or aspects are common to particular views, they are labeled using the same reference numeral. Thus, a feature or aspect labeled with a particular reference numeral on one view in  FIGS. 1 to 6  may be described herein with respect to that reference numeral shown on other views. 
       FIG. 1  illustrates a drilling rig  10  suitable for utilizing exemplary downhole tool and method embodiments of the present invention. In the exemplary embodiment shown on  FIG. 1 , a semisubmersible drilling platform  12  is positioned over an oil or gas formation (not shown) disposed below the sea floor  16 . A subsea conduit  18  extends from deck  20  of platform  12  to a wellhead installation  22 . The platform may include a derrick  26  and a hoisting apparatus  28  for raising and lowering the drill string  30 , which, as shown, extends into borehole  40  and includes a drill bit  32  and a directional drilling tool  100  (such as a three-dimensional rotary steerable tool). In the exemplary embodiment shown, steering tool  100  includes one or more, usually three, blades  150  disposed to extend outward from the tool  100  and apply a lateral force and/or displacement to the borehole wall  42 . The extension of the blades deflects the drill string  30  from the central axis of the borehole  40 , thereby changing the drilling direction. Drill string  30  may further include a downhole drilling motor, a mud pulse telemetry system, and one or more additional sensors, such as LWD and/or MWD tools for sensing downhole characteristics of the borehole and the surrounding formation. The invention is not limited in these regards. 
     It will be understood by those of ordinary skill in the art that methods and apparatuses in accordance with this invention are not limited to use with a semisubmersible platform  12  as illustrated in  FIG. 1 . This invention is equally well suited for use with any kind of subterranean drilling operation, either offshore or onshore. Moreover, while the invention is described with respect to exemplary three-dimensional rotary steerable (3DRS) tool embodiments, it will also be understood that the present invention is not limited in this regard. The invention is equally well suited for use in substantially any downhole tool requiring linear position measurement. 
     Turning now to  FIG. 2 , one exemplary embodiment of rotary steerable tool  100  from  FIG. 1  is illustrated in perspective view. In the exemplary embodiment shown, rotary steerable tool  100  is substantially cylindrical and includes threaded ends  102  and  104  (threads not shown) for connecting with other bottom hole assembly (BHA) components (e.g., connecting with the drill bit at end  104 ). The rotary steerable tool  100  further includes a housing  110  deployed about a shaft (not shown in  FIG. 2 ). The shaft is typically configured to rotate relative to the housing  110 . The housing  110  further includes at least one blade  150  deployed, for example, in a recess (not shown) therein. Directional drilling tool  100  further includes hydraulics  130  and electronics  140  modules (also referred to herein as control modules  130  and  140 ) deployed in the housing  110 . In general, the control modules  130  and  140  are configured for sensing and controlling the relative positions of the blades  150 . 
     To steer (i.e., change the direction of drilling), one or more of blades  150  are extended and exert a force against the borehole wall. The rotary steerable tool  100  is moved away from the center of the borehole by this operation, thereby altering the drilling path. In general, increasing the offset (i.e., increasing the distance between the tool axis and the borehole axis via extending one or more of the blades) tends to increase the curvature (dogleg severity) of the borehole upon subsequent drilling. The tool  100  may also be moved back towards the borehole axis if it is already eccentered. It will be understood that the drilling direction (whether straight or curved) is determined by the positions of the blades with respect to housing  110 . Therefore, a more precise determination (measurement) of the positions of the blades  150  relative to the housing  110  tends to yield a more precise and predictable drilling direction. More precise determination of the blade positions also provides for more precise borehole caliper measurements. Additionally, improving the reliability of the position sensor apparatus tends to improve the reliability of the tool (particularly the steering functionality of the tool). 
     Turning now to  FIG. 3 , a schematic of one exemplary hydraulic module  130  ( FIG. 2 ) used to control blade  150  is depicted.  FIG. 3  is a simplified schematic showing only a single blade. It will be understood that steering tools typically employ a plurality of blades, three being most common. Hydraulic module  130  includes a hydraulic fluid chamber  220  including first and second, low- and high-pressure reservoirs  226  and  236 . In the exemplary embodiment shown, low-pressure reservoir  226  is modulated to wellbore (hydrostatic) pressure via equalizer piston  222 . Hydraulic fluid in chamber  236  is pressurized by pump  240 , which is energized by rotating shaft  115 . In the exemplary embodiment shown, hydraulic fluid chamber  220  further includes a pressurizing spring  234  (e.g., a Belleville spring) deployed between an internal shoulder  221  of the chamber housing and a high-pressure piston  232 . As the high-pressure reservoir  236  is filled by pump  240 , high-pressure piston  232  compresses spring  234 , which maintains the pressure in the high-pressure reservoir  236  at some predetermined pressure above wellbore pressure. Thus it will be understood that the volume of pressurized fluid in chamber  236  is related to the position of piston  232  in chamber  220 . 
     Transmission of hydraulic pressure to blade  150  is controlled by solenoid-controlled valves  254  and  256 . Opening valve  254  and closing valve  256  causes high-pressure hydraulic fluid to flow into chamber  264 . As chamber  264  is filled with pressurized fluid, piston  252  is urged radially outward, which in turn urges blade  150  outward from housing  110  (e.g., into contact with the borehole wall). When the blade  150  has been extended to a desired (predetermined) position, valve  254  may be closed, thereby “locking” the blade  150  in position (at the desired extension from the tool body). In order to retract the blade (radially inward towards the tool body), valve  256  is open (while valve  254  remains closed). Opening valve  256  allows pressurized hydraulic fluid in chamber  264  to return to the low-pressure reservoir  226 . Blade  150  may be urged inward (towards the tool body), for example, via spring bias and/or contact with the borehole wall. In the exemplary embodiment shown, the blade  150  is not drawn inward under the influence of a hydraulic force, although the invention is not limited in this regard. 
     Hydraulic module  130  further includes position sensors  300 ,  400 , and  500  in accordance with the present invention. Position sensor  300  includes a magnet assembly  360  deployed in or on piston  232  and a substantially linear magnetic sensor array  340  deployed on chamber  220  in sensory range of magnetic flux emanating from the magnet assembly  360 . Position sensor  300  is disposed to measure the position of high pressure piston  232  in chamber  220  and therefore is further disposed to measure the volume of high pressure hydraulic fluid in reservoir  236 . Position sensor  400  includes magnet assembly  410  deployed in or on piston  252  (i.e., in or on blade  150 ) and a substantially linear magnetic sensor array  440  deployed adjacent chamber  264  in sensory range of magnetic flux emanating from magnet assembly  410 . Position sensor  400  is disposed to measure the position of blade pistons  252  in chamber  264  and therefore is further disposed to measure the extension of the blade  150  relative to the housing  110  (or the tool axis). Position sensor  500  includes magnet assembly  510  deployed in or on piston  242  and a substantially linear sensor array  540  deployed adjacent pump housing  244 . Position sensor  500  is disposed to measure the position of piston  242  in housing  244 . Magnetic sensor arrays  340 ,  440 , and  540  may include substantially any type of magnetic sensor, e.g., including magnetometers, reed switches, magnetoresistive sensors, and/or Hall-Effect sensors. Moreover, each sensor may have either a ratiometric (analog) or digital output. While the exemplary embodiments described below with respect to  FIGS. 4A through 5  advantageously utilize Hall-Effect sensors, the invention is not limited in this regard. 
       FIG. 4A  depicts one exemplary embodiment of position sensor  300 . A linear array  340  of Hall-Effect sensors  350 A-H is deployed in a pressure resistant housing  310 , which is located, for example, along an outer surface of hydraulic housing  305 . While  FIG. 4A  shows an array of eight magnetic sensors, it will be appreciated by those of ordinary skill on the art that this invention may equivalently utilize substantially any suitable plurality of magnetic sensors (with five or more being preferred). In the exemplary embodiment shown, sensor array  340  further includes a microprocessor  355  electronically coupled with the sensors  350 A-H. Within housing  305 , magnet assembly  360  is deployed on movable piston  232 . As described above, sensor array  340  is deployed in close enough proximity to magnet assembly  360  for at least one of sensors  350 A-H to detect magnetic flux emanating from the magnet assembly  360 . In the exemplary embodiment shown on  FIG. 4A , magnet assembly  360  includes first and second magnets  370 A and  370 B (typically, although not necessarily, of equal size and strength) deployed in a magnetically permeable housing  380 . In the exemplary embodiment shown in  FIG. 4A , magnets  370 A and  370 B are deployed such that opposing magnetic poles face one another (e.g., the north pole on magnet  370 A is adjacent to the north pole on magnet  370 B). In such an embodiment, magnetic flux lines  315  emanate outward from between the magnets  370 A and  370 B along center plane  390 . 
     It will be appreciated that magnet assembly  360  produces a substantially radially symmetric magnetic flux about the cylindrical axis of piston  232 . While the invention is not limited in this regard, such a radially symmetric configuration advantageously provides for rotational freedom about the longitudinal axis of the piston  232 . As such, the piston  232  and/or magnet assembly  360  may rotate in housing  305  during drilling (e.g., due to the extreme tool vibration commonly encountered downhole) without substantially effecting the accuracy of the linear position measurements. Moreover, a radially symmetric configuration also advantageously provides for easier tool assembly in that there is no need to key the piston  232  or magnet assembly  360  to a precise rotational position in housing  305 . 
     As described above with respect to  FIG. 3 , piston  232  is disposed to move substantially linearly within housing  305  as indicated by arrows  307  (left and right as depicted in  FIG. 4A .) Magnetic sensor array  340  lies substantially parallel to the direction of movement of piston  232 . Moreover, each magnetic sensor  350 A-H in the sensor array  340  is deployed so that its axis of sensitivity is substantially perpendicular to the array  340  (i.e., perpendicular to the direction of movement of piston  232  and parallel with center plane  390 ). It will be appreciated by those of ordinary skill in the art that a magnetic sensor is typically sensitive only to the component of the magnetic flux that is aligned (parallel) with the sensor&#39;s axis of sensitivity. It will also be appreciated that the exemplary embodiment of magnet assembly  340  shown on  FIG. 4A  results in magnetic flux lines  315  that are substantially perpendicular to the sensor array  340  where the center plane  390  intercepts the array  340 . Therefore, the magnetic sensor  350 A-H located closest to center plane  390  tends to sense the highest magnetic flux (magnetic field strength). For example, magnetic sensor  350 E (as shown on  FIG. 4A ) tends to measure the highest magnetic flux because (i) it closest to magnet assembly  340  and (ii) it is closest to plane  390  (therefore the magnetic flux tends to be substantially parallel with the magnetic sensor&#39;s axis of sensitivity). It is thus possible to approximate the position of the magnet, and thus the piston, by determining which magnetic sensor  350 A-H measures the greatest magnetic field. 
     With reference now to  FIG. 4B , an alternative embodiment  300 ′ is depicted in which magnet assembly  360 ′ includes a cylindrical magnet having a cylindrical axis substantially parallel with direction  307 . Magnet assembly  360 ′ also advantageously produces a substantially radially symmetric magnetic flux about the cylindrical axis of piston  232 . As described above, sensors  350 A-H are disposed so that each sensor&#39;s axis of sensitivity is substantially perpendicular to sensor array  340  (and therefore parallel with center plane  390 ). In this exemplary embodiment, the magnetic sensor closest to center plane  390  tends to measure the lowest magnetic flux. As shown on  FIG. 4B , magnetic sensor  350 E tends to sense the lowest flux despite being closer to magnet assembly  360 ′ since the flux is nearly perpendicular to the sensor&#39;s axis of sensitivity (e.g., as shown at  315 ′). It is thus possible to approximate the position of the magnet, and thus the piston, by determining which magnetic sensor measures the lowest magnetic flux. 
     It will be appreciated that the present invention is not limited to the exemplary magnet assembly, magnet alignment, and magnetic sensor alignment combinations depicted in  FIGS. 4A and 4B . Other combinations will be readily recognized by the artisan of ordinary skill. For example, referring to the exemplary embodiment shown on  FIG. 4B , each sensor  350 A-H in sensor array  340  may alternatively be aligned so that its axis of sensitivity is parallel with the array  340  (and therefore perpendicular to center plane  390 ). In such an embodiment, the position of the magnet assembly  360 ′ would be determined based on the maximum (rather than the minimum) measured flux. Likewise, with respect to the embodiment shown on  FIG. 4A , sensors  350 A-H may also alternatively be aligned so that their axes of sensitivity are parallel with the array  340  (and therefore perpendicular to center plane  390 ). In such an embodiment, the position of the magnet assembly  360  would be determined based on the minimum (rather than the maximum) measured flux. 
     With reference now to  FIG. 5 , sensor embodiment  400  is shown in greater detail. As described above, position sensor  400  is disposed to measure the position of blade  150  ( FIGS. 2 and 3 ). As shown on  FIG. 5 , blade  150  is in its fully retracted position within housing  110 . In the embodiment shown, magnet assembly  410  is fixed to an inner surface of the blade  150  (inside piston  252  as shown on  FIG. 3 ). As hydraulic fluid is pumped into chamber  264 , the blade extends outward from a longitudinal axis of the tool in the direction of arrow  405 . Magnetic sensor array  440  is deployed within the blade housing in close enough proximity to magnet assembly  410  such that at least one of the sensors  450 A-H on sensor array  440  is in sensory range of magnetic flux emanating from the assembly  410 . In the exemplary embodiment shown on  FIG. 5 , magnet assembly  410  is substantially similar to magnet assembly  360 ′, although an assembly similar to magnet assembly  360  may also be equivalently utilized. Sensors  450 A-H may be deployed having substantially any suitable alignment (e.g., parallel or perpendicular to array  440 ). The typical range of motion of a blade in a rotary steerable tool (e.g., tool  100 ) is approximately one inch. Thus, in rotary steerable embodiments sensors  450 A-H are preferably closely spaced (e.g., spaced at an interval of approximately ⅛ inch or less along the length of the array  440 ). However the invention is not limited in this regard. 
     While  FIG. 5  depicts an exemplary embodiment in which the magnet assembly  410  is deployed in the blade  150  (e.g., in piston  252 ) and the array  440  of sensors  450 A-H is deployed on the housing  110 , the invention is expressly not limited in this regard. It will be understood that sensor  400  may be equivalently configured such that magnet assembly  410  is deployed on housing  110  and sensor array  440  is deployed in the blade  150 . 
     Turning now to  FIG. 6 , sensor embodiment  500  is shown in greater detail. Position sensor  500  is disposed to measure the axial position of piston  242  in housing  244 . As shown on  FIGS. 3 and 6 , rotation of shaft  115  causes piston  242  to reciprocate in housing  244  (e.g., due to a cam on the shaft). Magnetic sensor array  540  is deployed on an outer surface of housing  244  in close enough proximity to magnet assembly  510  such that at least one of the sensors  550 A-I is in sensory range of magnetic flux emanating from the assembly  510 . In the exemplary embodiment shown on  FIG. 6 , magnet assembly  510  is substantially similar to magnet assembly  360 ′, although an assembly similar to magnet assembly  360  may also be equivalently utilized. Sensors  550 A-I may be deployed having substantially any suitable alignment (e.g., parallel or perpendicular to array  540 ). 
     With continued reference to  FIGS. 3 and 6 , it will be appreciated that sensor embodiment  500  is disposed to measure several tool parameters. For example, the stroke volume of pump  240  (the volume of fluid pumped per single rotation of shaft  115  in housing  110 ) may be determined in substantially real time during drilling by measuring the axial positions at the top and bottom of the piston stroke. Additionally, the axial position of piston  242  in housing  244  indicates the rotational position of the shaft  115  relative to the housing  110 . The rotation rate of the shaft  115  with respect to the housing  110  may further be determined from the periodic motion of piston  242  in housing  244 . While such rotational position and rotation rate measurements are typically made using other sensor arrangements, it will be appreciated that sensor embodiment  500  advantageously provides for a redundant measure of these parameters. As is known to those of ordinary skill in the downhole arts, redundant measurement capabilities can be highly advantageous in demanding downhole environments in which sensor failures are not uncommon. 
     It will be appreciated that downhole tools must typically be designed to withstand shock levels in the range of 1000 G on each axis and vibration levels of 50 G root mean square. Moreover, downhole tools are also typically subject to pressures ranging up to about 25,000 psi and temperatures ranging up to about 200 degrees C. With reference again to  FIGS. 4A and 4B , sensor array  340  is shown deployed in a pressure resistant housing  310 . Such an arrangement is preferred for downhole applications utilizing solid state magnetic field sensors such as Hall-Effect sensors and magnetoresistive sensors. While not shown on  FIGS. 5 and 6 , sensor arrays  440  and  540  are also preferably deployed in corresponding pressure resistant housings. In the exemplary embodiment shown, housing  310  includes a sealed, magnetically permeable, steel tube that is configured to resist downhole pressures which can damage sensitive electronic components. The sensor arrays ( 340 ,  440 , and  540 ) are also typically encapsulated in a potting material  358  to improve resistance to shocks and vibrations. Magnetic assemblies  360 ,  360 ′,  410 , and  510  are also typically constructed in view of demanding downhole conditions. For example, suitable magnets must posses a sufficiently high Curie Temperature to prevent demagnetization at downhole temperatures. Samarium cobalt (SaCo 5 ) magnets are typically preferred in view of their high Curie Temperatures (e.g., from about 700 to 800 degrees C.). Moreover, magnet assemblies  360 ,  360 ′,  410 , and  510  are also typically (although not necessarily) deployed inside corresponding pistons  232 ,  252 , and  242  in order to provide additional shock and vibration resistance. 
     In each of the exemplary embodiments shown on  FIGS. 4A ,  4 B,  5 , and  6 , the output of each magnetic sensor may be advantageously electronically coupled to the input of a microprocessor. The microprocessor serves to process the data received by the sensor array. Substantially any suitable microprocessor, logic gate, or hardware device able to execute logic may be utilized. Moreover, a hybrid device including multiple magnetic sensors (e.g., Hall-Effect sensors) and a microprocessor in a single package may also be utilized. The invention is not limited in these regards. 
     In preferred embodiments, a suitable microprocessor (such as a PIC16F630/676 Microcontroller available from Microchip) is embedded within the sensor array. For example, as shown on  FIGS. 4A and 4B , a suitable microprocessor  355  is deployed on a printed circuit board with sensors  350 A-H. In such an embodiment, the microprocessor output (rather than the signals from the individual magnetic sensors) is typically electronically coupled with a main processor which is deployed further away from the sensor array (e.g., deployed in control module  140  as shown on  FIG. 2 ). This configuration advantageously reduces wiring requirements in the body of the downhole tool, which is particularly important in smaller diameter tool embodiments (e.g., tools having a diameter of less than about 12 inches). Digital output from the embedded microprocessor also tends to advantageously reduce electrical interference in wiring to the main processor. Embedded microprocessor output may also be combined with a voltage source line to further reduce the number of wires required, e.g., one wire for combined power and data output and one wire for ground. This may be accomplished, for example, by imparting a high frequency digital signal to the voltage source line or by modulating the current draw from the voltage source line. Such techniques are known to those of ordinary skill in the art. 
     In preferred embodiments of this invention, microprocessor  355  ( FIGS. 4A and 4B ) includes processor-readable or computer-readable program code embodying logic, including instructions for calculating a precise linear position of an element, such as a piston or a blade, from the received magnetic sensor measurements. While substantially any logic routines may be utilized, it will be appreciated that logic routines requiring minimal processing power are advantageous for downhole applications (particularly for LWD, MWD, and directional drilling embodiments of the invention in which both electrical and electronic processing power are often severely limited). 
     Turning now to  FIGS. 7A and 7B , a graphical representation of one exemplary mathematical technique for determining the linear position is illustrated. The exemplary method embodiment described with respect to  FIGS. 7A and 7B  determines the linear position via locating the position of a maximum magnetic field in the array  340 .  FIG. 7A  plots the magnetic field measurements made at each of sensors  350 A-H as a function of distance along array  340 . Data points  710  represent the absolute value of the magnetic field strength as measured by the magnetic sensors  350 A-H. Note that in the exemplary embodiment shown, the maximum magnetic field strength (and therefore the position of plane  390 ) is located between sensors  350 E and  350 F. In one exemplary embodiment, the position of plane  390  (and therefore the position of piston  232 ) may be determined as follows. Processor  355  first selects the three consecutive highest magnetic field measurements made by sensors  350 A-H (e.g., as measured by sensors  350 E,  350 F, and  350 G in the exemplary embodiment shown on  FIG. 7A ). These three consecutive measurements are illustrated in more detail in  FIG. 7B . The location of the maximum may then be determined mathematically from the three consecutive magnetic field measurements, for example, as follows: 
     
       
         
           
             
               
                 
                   P 
                   = 
                   
                     L 
                     ⁡ 
                     
                       ( 
                       
                         
                           
                             
                               2 
                               ⁢ 
                               x 
                             
                             + 
                             1 
                           
                           2 
                         
                         + 
                         
                           A 
                           
                             A 
                             + 
                             B 
                           
                         
                       
                       ) 
                     
                   
                 
               
               
                 
                   Equation 
                   ⁢ 
                   
                       
                   
                   ⁢ 
                   1 
                 
               
             
           
         
       
     
     where P represents the linear position of plane  390  in the array, L represents the distance interval between adjacent sensors in the array, A represents the difference in the absolute value of the magnetic field between the first and second of the three consecutive data points, B represents the difference in the absolute value of the magnetic field between the second and third of the three consecutive data points (A and B are shown on  FIG. 7B ), and x is a counting variable having an integer value representing the particular sensor used to measure the first of the three consecutive data points shown on  FIG. 7B  (such that x=1 for sensor  350 A, x=2 for sensor  350 B, x=3 for sensor  350 C, and so on). In the exemplary embodiment shown, x=5 (sensor  350 E). 
     With reference now to  FIGS. 8A and 8B , a graphical representation of another exemplary mathematical technique for determining the linear position is illustrated. Data points  810  represent the magnetic field strength as measured by sensors  350 A-H on  FIG. 4B . In this embodiment, the position of center plane  390  is indicated by zero-crossing  820 , the location on the array at which magnetic flux is substantially null and at which the polarity of the magnetic field changes from positive to negative (or negative to positive). Note that in the exemplary embodiment shown, the position of the zero crossing (and therefore the position of plane  390 ) is located between sensors  350 D and  350 E. In the exemplary embodiment shown on  FIG. 8B , processor  355  first selects adjacent sensors (e.g., sensors  350 D and  350 E) between which the sign of the magnetic field changes (from positive to negative or negative to positive). The position of the zero crossing  820  may then be determined, for example, by fitting a straight line through the data points on either side of the zero crossing (e.g., between the measurements made by sensors  350 D and  350 E in embodiment shown on  FIG. 8B ). It will be appreciated that the shape and strength of the magnet(s) may be advantageously configured, for example, to produce a highly linear flux regime in the vicinity of the zero-crossing. The location of the zero crossing  820  may then be determined mathematically from the magnetic field measurements, for example, as follows: 
     
       
         
           
             
               
                 
                   P 
                   = 
                   
                     L 
                     ⁡ 
                     
                       ( 
                       
                         x 
                         + 
                         
                           A 
                           
                             A 
                             + 
                             B 
                           
                         
                       
                       ) 
                     
                   
                 
               
               
                 
                   Equation 
                   ⁢ 
                   
                       
                   
                   ⁢ 
                   2 
                 
               
             
           
         
       
     
     where P represents the linear position of plane  390 , L represents the distance interval between adjacent sensors in the array, A and B represent the absolute values of the magnetic field measured on either side of the zero crossing (A and B are shown on  FIG. 7B ), and x is a counting variable having an integer value representing the first of the two adjacent sensors positioned on either side of the zero crossing  820  on  FIG. 7B  (such that x=1 for sensor  350 A, x=2 for sensor  350 B, x=3 for sensor  350 C, and so on). In the exemplary embodiment shown, x=4 (sensor  350 D). 
     It will be appreciated that position sensing methods described above with respect to  FIGS. 7A through 8B  advantageously require minimal computational resources (minimal processing power), which is critical in downhole applications in which 8-bit microprocessors are commonly used. These methods also provide accurate position determination along the full length of the sensor array. For example, an accurate position may be determined even when the magnetic field maximum or zero crossing are located near the ends of the array (near the first or last sensor in the array). The zero crossing method (e.g., as shown on  FIGS. 8A and 8B ) tends to be further advantageous in that a wider sensor input range is available (from the negative to positive saturation limits of the sensors). Even if one or more of the sensors saturate, position determination is typically unaffected since the sensors on either side of the zero crossing are subject to a relatively low magnetic field strength as compared to those sensors further away from the zero crossing. Moreover, the computed position tends to be less sensitive to the distance between the magnet(s) and the array (since the method locates a zero crossing rather than a magnetic field maximum). 
     While the above described exemplary embodiments pertain to steering tool embodiments including hydraulically actuated blades, it will be understood that the invention is not limited in this regard. The artisan of ordinary skill will readily recognize other downhole uses of position sensors in accordance with the present invention. For example, position sensors in accordance with this invention may be utilized to measure the extension of caliper probes used in wireline applications (one such caliper probe is disclosed in U.S. Pat. No. 6,339,886). Additionally, position sensors in accordance with this invention may also be utilized to measure hydraulic volume in an inflatable packer assembly, such as are commonly utilized in MWD, LWD, and wireline applications (one such packer assembly is disclosed in U.S. Pat. No. 5,517,854). 
     Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alternations may be made herein without departing from the spirit and scope of the invention as defined by the appended claims.