Patent Publication Number: US-6714138-B1

Title: Method and apparatus for transmitting information to the surface from a drill string down hole in a well

Description:
FIELD OF THE INVENTION 
     The current invention is directed to a method and apparatus for transmitting information from a down hole location in a well to the surface, such as that used in a mud pulse telemetry system employed in a drill string for drilling an oil well. 
     BACKGROUND OF THE INVENTION 
     In underground drilling, such as gas, oil or geothermal drilling, a bore is drilled through a formation deep in the earth. Such bores are formed by connecting a drill bit to sections of long pipe, referred to as a “drill pipe,” so as to form an assembly commonly referred to as a “drill string” that extends from the surface to the bottom of the bore. The drill bit is rotated so that it advances into the earth, thereby forming the bore. In rotary drilling, the drill bit is rotated by rotating the drill string at the surface. In directional drilling, the drill bit is rotated by a down hole mud motor coupled to the drill bit; the remainder of the drill string is not rotated during drilling. In a steerable drill string, the mud motor is bent at a slight angle to the centerline of the drill bit so as to create a side force that directs the path of the drill bit away from a straight line. In any event, in order to lubricate the drill bit and flush cuttings from its path, piston operated pumps on the surface pump a high pressure fluid, referred to as “drilling mud,” through an internal passage in the drill string and out through the drill bit. The drilling mud then flows to the surface through the annular passage formed between the drill string and the surface of the bore. 
     Depending on the drilling operation, the pressure of the drilling mud flowing through the drill string will typically be between 1,000 and 25,000 psi. In addition, there is a large pressure drop at the drill bit so that the pressure of the drilling mud flowing outside the drill string is considerably less than that flowing inside the drill string. Thus, the components within the drill string are subject to large pressure forces. In addition, the components of the drill string are also subjected to wear and abrasion from drilling mud, as well as the vibration of the drill string. 
     The distal end of a drill string, which includes the drill bit, is referred to as the “bottom hole assembly.” In “measurement while drilling” (MWD) applications, sensing modules in the bottom hole assembly provide information concerning the direction of the drilling. This information can be used, for example, to control the direction in which the drill bit advances in a steerable drill string. Such sensors may include a magnetometer to sense azimuth and accelerometers to sense inclination and tool face. 
     Historically, information concerning the conditions in the well, such as information about the formation being drill through, was obtained by stopping drilling, removing the drill string, and lowering sensors into the bore using a wire line cable, which were then retrieved after the measurements had been taken. This approach was known as wire line logging. More recently, sensing modules have been incorporated into the bottom hole assembly to provide the drill operator with essentially real time information concerning one or more aspects of the drilling operation as the drilling progresses. In “logging while drilling” (LWD) applications, the drilling aspects about which information is supplied comprise characteristics of the formation being drilled through. For example, resistivity sensors may be used to transmit, and then receive, high frequency wavelength signals (e.g., electromagnetic waves) that travel through the formation surrounding the sensor. By comparing the transmitted and received signals, information can be determined concerning the nature of the formation through which the signal traveled, such as whether it contains water or hydrocarbons. Other sensors are used in conjunction with magnetic resonance imaging (MRI). Still other sensors include gamma scintillators, which are used to determine the natural radioactivity of the formation, and nuclear detectors, which are used to determine the porosity and density of the formation. 
     In traditional LWD and MWD systems, electrical power was supplied by a turbine driven by the mud flow. More recently, battery modules have been developed that are incorporated into the bottom hole assembly to provide electrical power. 
     In both LWD and MWD systems, the information collected by the sensors must be transmitted to the surface, where it can be analyzed. Such data transmission is typically accomplished using a technique referred to as “mud pulse telemetry.” In a mud pulse telemetry system, signals from the sensor modules are typically received and processed in a microprocessor-based data encoder of the bottom hole assembly, which digitally encodes the sensor data. A controller in the control module then actuates a pulser, also incorporated into the bottom hole assembly, that generates pressure pulses within the flow of drilling mud that contain the encoded information. The pressure pulses are defined by a variety of characteristics, including amplitude (the difference between the maximum and minimum values of the pressure), duration (the time interval during which the pressure is increased), shape, and frequency (the number of pulses per unit time). Various encoding systems have been developed using one or more pressure pulse characteristics to represent binary data (i.e., bit  1  or  0 )—for example, a pressure pulse of 0.5 second duration represents binary 1, while a pressure pulse of 1.0 second duration represents binary 0. The pressure pulses travel up the column of drilling mud flowing down to the drill bit, where they are sensed by a strain gage based pressure transducer. The data from the pressure transducers are then decoded and analyzed by the drill rig operating personnel. 
     Various techniques have been attempted for generating the pressure pulses in the drilling mud. One technique involves the use of axially reciprocating valves, such as that disclosed in U.S. Pat. Nos. 3,958,217 (Spinnler); 3,713,089 (Clacomb); and 3,737,843 (Le Peuvedic et al.), each of which is hereby incorporated by reference in its entirety. Another technique involves the use of rotary pursers. Typically, rotary pulsers utilizes a rotor in conjunction with a stator. The stator has vanes that form passages through which the drilling mud flows. The rotor has blades that, when aligned with stator passages, restrict the flow of drilling mud, thereby resulting in an increase in drilling mud pressure, and, when not so aligned, eliminate the restriction. Rotation of the rotor is driven by the flow of drilling mud or an electric motor powered by a battery. Typically, the motor is a brushless DC motor mounted in an oil-filled chamber pressurized to a pressure close to that of the drilling mud to minimize the pressure gradient acting on the housing enclosing the motor. 
     In one type of rotary pulser, sometimes referred to as a “turbine” or “siren,” the rotor rotates more or less continuously so as to create an acoustic carrier signal within the drilling mud. A siren type rotary pulser is disclosed in U.S. Pat. Nos. 3,770,006 (Sexton et al.) and 4,785,300 (Chin et al.), each of which is hereby incorporated by reference in their entirety. Encoding can be accomplished based on shifting the phase of the acoustic signal relative to a reference signal—for example, a shift in phase may represent one binary bit (e.g., 1), while the absence of a phase shift may indicate another bit (e.g., 0). 
     In another type of rotary pulser, in which the rotor is typically driven by the mud flow, the rotor increments in discrete intervals. Operation of a latching or escapement mechanism, for example by means of an electrically operated solenoid, may be used to actuate the incremental rotation of the rotor into an orientation in which its blades block the stator passages, thereby resulting in an increase in drilling mud pressure that may be sensed at the surface. The next incremental rotation unblocks the stator passages, thereby resulting in a reduction in drilling mud pressure that may likewise be sensed at the surface. Thus, the incremental rotation of the rotor creates pressure pulses that are transmitted to the surface detector. A rotary pulser of this type is disclosed in U.S. Pat. No. 4,914,637 (Goodsman), incorporated by reference herein in its entirety. 
     Unfortunately, conventional rotary pulsers suffer from disadvantages that result from the fact that the characteristics of the pressure pulses cannot be adequately controlled in situ to optimize the transmission of information. For example, under any given mud flow situation, each increment of the rotor of an incremental type rotary pulser will result in a constant amplitude pressure pulses being generated at the pulser. As the drilling progresses, the distance between the pulser and the surface detector increases, thereby resulting in increased attenuation of the pressure pulses by the time they reach the surface. This can make it more difficult for the pressure pulses to be detected at the surface. Moreover, from time to time, extraneous pressure pulses from other sources, such as mud pumps, may become more pronounced or may occur at a frequency closer to that of the pressure pulses containing the data to be transmitted, making data acquisition by the surface detection system more difficult. In such situations, data transmission could be improved by increasing the amplitude or varying the frequency or even the shape of the pressure pulses generated by the pulser. 
     In prior art systems, such situations can only be remedied by removing the pulser, which requires cessation of drilling and withdrawal of the drill string from the well so that physical adjustments can be made to the pulser, for example, mechanically increasing the size of the rotor increment so as to increase the amplitude and duration of the pulses, or adjusting the motor control to alter the pulser speed. 
     Note that although increasing the magnitude of the rotor increment will increase the duration, and often the amplitude, of the pressure pulses, it will also increase the time necessary to create the pulse, thereby reducing the data transmission rate. Thus, optimal performance will not be obtained by generating pressure pulses of greater than necessary duration or amplitude, and there are some situations in which it may be desirable to decrease the amplitude of the pressure pulses as the drilling progresses. Current systems, however, do not permit such optimization of the data transmission rate. 
     Conventional pulsers suffer from other disadvantages as well. For example, due to the high pressure of the drilling mud, rotary seals between the rotor shaft and the stationary components are subject to leakage. Moreover, the brushless DC motors used to drive the rotor consume relatively large amounts of power, limiting battery life. While brushed DC motors consume less power, they cannot be used in an oil-filled pulser housing of the type typically used in an MWD/LWD system. 
     Consequently, it would be desirable to provide a method and apparatus for generating pressure pulses in a mud pulse telemetry system in which one or more characteristics of the pressure pulses generated at the pulser could be adjusted in situ at the down hole location—that is, without withdrawing the drill sting from the well. It would also be desirable to provide a pulser having a durable seal that was resistant to leakage and powered by a low power consuming brushed DC motor. 
     SUMMARY OF THE INVENTION 
     It is an object of the current invention to provide an improved method of transmitting information from a portion of a drill string operating at a down hole location in a well bore to a location proximate the surface of the earth. This and other objects are achieved in a method of transmitting information from a portion of a drill string operating at a down hole location in a well bore to a location proximate the surface of the earth comprising the steps of (i) generating pressure pulses in the drilling fluid flowing through the drill string that are encoded to contain the information to be transmitted, and (ii) controlling a characteristic of the pressure pulses, such as amplitude, duration, frequency, or phase, in situ at the down hole location. 
     In one embodiment, the method comprises the steps of (i) directing drilling fluid along a flow path extending through the down hole portion of the drill string, (ii) directing the drilling fluid over a rotor disposed in the down hole portion of the drill string, the rotor capable of at least partially obstructing the flow of fluid through the flow path by rotating in a first direction and of thereafter reducing the obstruction of the flow path by rotating in an opposite direction, (iii) creating pressure pulses encoded to contain the information in the drilling fluid that propagate toward the surface location, each of the pressure pulses created by oscillating the rotor by rotating the rotor in the first direction through an angle of rotation so as to obstruct the flow path and then reversing the direction of rotation and rotating the rotor in the opposite direction so as to reduce the obstruction of the flow path, and (iv) making an adjustment to at least one characteristic of the pressure pulses by adjusting the oscillation of the rotor, the adjustment of the oscillation of the rotor performed in situ at the down hole location. 
     In a preferred embodiment, the method includes the step of transmitting instructional information from the surface to the down hole location for controlling the pressure pulse characteristic. In one embodiment, the instructional information is transmitted by generating pressure pulses at the surface and transmitting them to the down hole location where they are sensed by a pressure sensor and deciphered. 
     The invention also encompasses an apparatus for transmitting information from a portion of a drill string operating at a down hole location in a well bore to a location proximate the surface of the earth, the drill string having a passage through which a drilling fluid flows, comprising (i) a housing for mounting in the drill string passage, first and second chambers formed in the housing, the first and second chambers being separated from each other, the first chamber filled with a gas, the second chamber filled with a liquid, (ii) a rotor capable of at least partially obstructing the flow of the drilling fluid through the passage when rotated into a first angular orientation and of reducing the obstruction when rotated into a second angular orientation, whereby rotation of the rotor creates pressure pulses in the drilling fluid, (iii) a drive train for rotating the rotor, at least a first portion of the drive train located in the liquid filled second chamber, (iv) an electric motor for driving rotation of the drive train, the electric motor located in the gas-filled first chamber. 
     In a preferred embodiment, the apparatus also includes a stator in which the passage is formed. A seal is fixedly attached at one end to the rotor and at the other end to the stator, so that the seal undergoes torsional deflection as the rotor oscillates. The clearance between the rotor and stator is tapered so as to prevent jamming by debris in the drilling fluid. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     FIG. 1 is a diagram, partially schematic, showing a drilling operation employing the mud pulse telemetry system of the current invention. 
     FIG.  1 ( a ) is a graph showing the amplitude and shape of the pressure pulses in the drilling fluid as-generated at the pulser (lower curve) and as-received at the surface pressure sensor. 
     FIG. 2 is a schematic diagram of a mud pulser telemetry system according to the current invention. 
     FIG. 3 is a diagram, partially schematic, of the mechanical arrangement of a pulser according to the current invention. 
     FIGS. 4-6 are consecutive portions of a longitudinal cross-section through a portion of the bottom hole assembly of the drill string shown in FIG. 1 incorporating the pulser shown in FIG.  3 . 
     FIG. 7 is a transverse cross-section taken through line VII—VII shown in FIG. 4, showing the pressure compensation system. 
     FIG. 8 is a detailed view of the portion of the pulser shown in FIG. 5 in the vicinity of the magnetic coupling. 
     FIG. 9 is a transverse cross-section taken through line IX—IX shown in FIG. 6, showing the pressure sensor. 
     FIG.  9 ( a ) is an exploded, isometric view of the pressure sensor shown in FIG.  9 . 
     FIG. 10 is a transverse cross-section taken through line X—X shown in FIG. 4, showing the stator. 
     FIG. 11 is a transverse cross-section taken through line XI—XI shown in FIG. 4, showing the rotor and stator. 
     FIG. 12 is a longitudinal cross-section taken through line XII—XII shown in FIG. 11 showing the rotor and stator. 
     FIG. 13 is a cross-section taken along line XIII—XIII shown in FIG. 12 showing portions of the rotor and stator. 
     FIG.  13 ( a ) is a view similar to FIG. 13 showing an alternate embodiment of the rotor blade shown in FIG.  13 . 
     FIGS.  14 ( a ) and ( b ) are isometric views of two embodiments of the seal shown in FIG.  12 . 
     FIGS.  15 ( a )-( c ) show the rotor in three orientations relative to the stator. 
     FIG. 16 is a graph showing the timing relationship of the electrical power e transmitted from the motor driver to the motor (lower curve) to the angular orientation of the rotor θ (middle curve) and the resulting pressure pulse ΔP generated at the pulser (upper curve). 
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENT 
     A drilling operation incorporating a mud pulse telemetry system according to the current invention is shown in FIG. 1. A drill bit  2  drills a bore hole  4  into a formation  5 . The drill bit  2  is attached to a drill sting  6  that, as is conventional, is formed of sections of piping joined together. As is also conventional, a mud pump  16  pumps drilling mud  18  downward through the drill string  6  and into the drill bit  2 . The drilling mud  18  flows upward to the surface through the annular passage between the bore  4  and the drill string  6 , where, after cleaning, it is recirculated back down the drill string by the mud pump  16 . As is conventional in MWD and LWD systems, sensors  8 , such as those of the types discussed above, are located in the bottom hole assembly portion  7  of the drill string  6 . In addition, a surface pressure sensor  20 , which may be a transducer, senses pressure pulses in the drilling mud  18 . According to a preferred embodiment of the invention, a pulser device  22 , such as a valve, is located at the surface and is capable of generating pressure pulses in the drilling mud. 
     As shown in FIGS. 1 and 2, in addition to the sensors  8 , the components of the mud pulse telemetry system according to the current invention include a conventional mud telemetry data encoder  24 , a power supply  14 , which may be a battery or turbine alternator, and a down hole pulser  12  according to the current invention. The pulser comprises a controller  26 , which may be a microprocessor, a motor driver  30 , which includes a switching device  40 , a reversible motor  32 , a reduction gear  44 , a rotor  36  and stator  38 . The motor driver  30 , which may be a current limited power stage comprised of transistors (FET&#39;s and bipolar), preferably receives power from the power supply  14  and directs it to the motor  32  using pulse width modulation. Preferably, the motor is a brushed DC motor with an operating speed of at least about 600 RPM and, preferably, about 6000 RPM. The motor  32  drives the reduction gear  44 , which is coupled to the rotor shaft  34 . Although only one reduction gear  44  is shown, it should be understood that two or more reduction gears could also be utilized. Preferably, the reduction gear  44  achieves a speed reduction of at least about 144:1. The sensors  8  receive information  100  useful in connection with the drilling operation and provide output signals  102  to the data encoder  24 . Using techniques well known in the art, the data encoder  24  transforms the output from the sensors  8  into a digital code  104  that it transmits to the controller  26 . Based on the digital code  104 , the controller  26  directs control signals  106  to the motor driver  30 . The motor driver  30  receives power  107  from the power source  14  and directs power  108  to a switching device  40 . The switching device  40  transmits power  111  to the appropriate windings of the motor  32  so as to effect rotation of the rotor  36  in either a first (e.g., clockwise) or opposite (e.g., counterclockwise) direction so as to generate pressure pulses  112  that are transmitted through the drilling mud  18 . The pressure pulses  112  are sensed by the sensor  20  at the surface and the information is decoded and directed to a data acquisition system  42  for further processing, as is conventional. As shown in FIG.  1 ( a ), the pressure pulses  112  generated at the down hole pulser  12  have an amplitude “a”. However, since the down hole pulser  12  may be as much as 5 miles from the surface, as a result of attenuation, the amplitude of the pressure pulses when they arrive at the surface will be only a′. In addition, the shape of the pulses may be less distinct and noise may be superimposed on the pulses. 
     Preferably, a down hole static pressure sensor  29  is incorporated into the drill string to measure the pressure of the drilling mud in the vicinity of the pulser  12 . As shown in FIG. 2, the static pressure sensor  29 , which may be a strain gage type transducer, transmits a signal  105  to the controller  26  containing information on the static pressure. As is well known in the art, the static pressure sensor  29  may be incorporated into the drill collar of the drill bit  2 . However, the static pressure sensor  29  could also be incorporated into the down hole pulser  12 . 
     In a preferred embodiment of the invention, the down hole pulser  12  also includes a down hole dynamic pressure sensor  28  that senses pressure pulsations in the drilling mud  18  in the vicinity of the pulser  12 . The pressure pulsations sensed by the sensor  28  may be the pressure pulses generated by the down hole pulser  12  or the pressure pulses generated by the surface pulser  22 . In either case, the down hole dynamic pressure sensor  28  transmits a signal  115  to the controller  26  containing the pressure pulse information, which may be used by the controller in generating the motor control signals  106 . The down hole pulser  12  may also include an orientation encoder  24  suitable for high temperature applications, coupled to the motor  32 . The orientation encoder  44  directs a signal  114  to the controller  26  containing information concerning the angular orientation of the rotor  36 , which may also be used by the controller in generating the motor control signals  106 . Preferably, the orientation encoder  44  is of the type employing a magnet coupled to the motor shaft that rotates within a stationary housing in which Hall effect sensors are mounted that detect rotation of the magnetic poles. 
     A preferred mechanical arrangement of the down hole pulser  12  is shown schematically in FIG. 3 mounted in a section of drill pipe  64  forming a portion of the bottom hole assembly  7  of the drill string  6 . The drill pipe  64  forms a central passage  62  through which the drilling mud  18  flows on its way down hold to the drill bit  2 . The rotor  36  is preferably located upstream of a stator  38 , which includes a collar portion  39  supported in the drill pipe  64 . The rotor  36  is driven by a drive train mounted in a pulser housing. The pulser housing is comprised of housing portions  66 ,  68 , and  69 . The rotor  36  includes a rotor shaft  34  mounted on upstream and downstream bearings  56  and  58  in a chamber  63 . The chamber  63  is formed by upstream and downstream housing portions  66  and  68  together with a seal  60  and a barrier member  110  (as used herein, the terms upstream and downstream refer to the flow of drilling mud toward the drill bit). The chamber  63  is filled with a liquid, preferably a lubricating oil, that is pressurized to an internal pressure that is close to that of the external pressure of the drilling mud  18  by a piston  162  mounted in the upstream oil-filed housing portion  66 . 
     The rotor shaft  34  is coupled to the reduction gear  46 , which may be a planetary type gear train, such as that available from Micromo, of Clearwater, Fla., and which is also mounted in the downstream oil-filled housing portion  68 . The input shaft  113  to the reduction gear  46  is supported by a bearing  54  and is coupled to inner half  52  of a magnetic coupling  48 , such as that available through Ugimag, of Valparaiso, Ind. The outer half  50  of the magnetic coupling  48  is mounted within housing portion  69 , which forms a chamber  65  that is filled with a gas, preferably air, the chambers  63  and  65  being separated by the barrier  110 . The outer magnetic coupling half  50  is coupled to a shaft  94  which is supported on bearings  55 . A flexible coupling  90  couples the shaft  94  to the electric motor  32 , which rotates the drive train. The orientation encoder  44  is coupled to the motor  32 . The down hole dynamic pressure sensor  28  is mounted on the drill pipe  64 . 
     In operation, the motor  32  rotates the shaft  94  which, via the magnetic coupling  48 , transmits torque through the housing barrier  110  that drives the reduction gear input shaft  113 . The reduction gear drives the rotor shaft  34 , thereby rotating the rotor  36 . 
     Pressurizing the chamber  63  with oil to a pressure close to that of the drilling mud  18  reduces the likelihood of drilling mud  18  leaking into the chamber  63 . In addition, it reduces the forces imposed on the housings portions  66  and  68 , which are subject to erosion. Moreover, as discussed further below, in a preferred embodiment of the invention, a novel flexible seal  60  seals between the rotor  36  and the stator  38  at the upstream end of the housing portion  66  to further prevent leakage. 
     According to one aspect of the current invention, although the rotor  32  and reduction gear  46  are mounted in the oil-filled chamber  63 , the motor  32  is mounted in the air filled chamber  65 , which is maintained at atmospheric pressure. This allows the use of a brushed reversible DC motor, which is capable of the high efficiency and high motor speeds preferably used according to the current invention. This high efficiency results in consumption of relatively little power, thereby conserving the battery  14 . The high speed allows a faster data transmission rate. It also results in a motor drive train with high resistance to rotation which, as discussed below, permits the rotor to maintain its orientation without the use of mechanical stops. Moreover, the use of the magnetic coupling  48  allows the motor  32  to transmit power to the rotor shaft  34  even though the chambers  63  and  65  in which the rotor shaft and motor are mounted are mechanically isolated from each other, effectively eliminating any leakage path between the oil-filled and air-filled chambers. Although in the preferred embodiment, the separate chambers  63  and  65  are formed in contiguous housing portions separated by a barrier  110 , the chambers could also be formed in spaced apart housing portions. 
     A preferred embodiment of the down hole pulser  12 , installed in the bottom hole portion  7  of the drill string  6 , is shown in FIGS. 4-14. As previously discussed, the outer housing of the drill string  6  is formed by the section of drill pipe  64 , which forms the cental passage  62  through which the drilling mud  18  flows. As is conventional, the drill pipe  64  has threaded couplings on each end, shown in FIGS. 4 and 6, that allow it to be mated with other sections of drill pipe. As shown in FIG. 4, at its upstream end, the down hole pulser  12  is supported within the drill pipe  64  by the stator collar  39 . As shown in FIG. 6, the downstream end of the pulser  12  is attached via coupling  180  to a centralizer  122  that further supports it within the passage  62 . The stator  38 , which is mounted within the stator collar  39 , is coupled to the housing portions  66 ,  68  and  69 . 
     As shown in FIG. 4, the upstream and downstream housing portions  66  and  68  forming the oil filled chamber  63  are threaded together, with the joint being sealed by O-rings  193 . The rotor  36  is located immediately upstream of the stator  38  and includes a rotor shaft  34 , which is mounted within the oil-filled chamber  63  by the upstream and downstream bearings  58  and  56 . A nose  61 , which is threaded onto the upstream end of the rotor shaft  34 , forms the forward most portion of the pulser  12 . The downstream end of the rotor shaft  34  is attached by a coupling  182  to the output shaft of the reduction gear  46 . 
     As shown in FIG. 7, an opening  161  is formed in housing portion  66  that allows the chamber  63  to be filled with oil, after which the opening  161  is closed by a plug  160 . Three pistons  162  slide in cylinders  164  formed in the housing portion  66  to create the pressure equalization system. The drilling mud  18  flowing through the passage  62  displaces the pistons  162  radially inward until the pressure of the oil inside the chamber  63  is approximately equal to that of the outside drilling mud. 
     As shown in FIG. 8, the air-filed housing portion  69  is threaded onto the downstream oil-filed housing portion  68 , with O-rings  191  sealing the threaded joint. The housing barrier  110  closes the downstream end of the oil-filled housing portion  68 , with O-rings  114  providing a seal between the barrier  110  and the housing portion  68 . A passage  108  in the barrier  110  facilitates filling the chamber  63  with oil and is thereafter closed with a plug  102 . The input shaft  113  of the reduction gear  46  is supported within the housing barrier  110  by the bearings  54  at its upstream end. The inner half  52  of the magnetic coupling  48  is attached to the downstream end of the input shaft  113 . The outer half  50  of the magnetic coupling  48  is attached to the upstream portion of shaft  94 , which is disposed in the air-filled chamber  65 . Thus, although shaft  94  transfers power to shaft  113 , there is no physical connection extending through the two chambers that could create a leakage path. Shaft  94  is mounted on bearings  55  supported on the downstream end of the housing barrier  110  and is driven by a clevis  92  and pin  96  that permits axial displacement between the two halves of the shafting. The clevis  92  is attached by a clamp  106  to a flexible coupling  90 , which accommodates radial misalignment of the components. 
     As shown in FIG. 5, the motor  32  and orientation encoder  44  are also mounted within the air-filled chamber  65  formed by the housing portion  69 , with the output shaft of the motor  32  being coupled to the clevis  92  via the flexible coupling  90 . As shown in FIGS. 5 and 6, the controller  26  is comprised of a central support plate  170  on which printed circuit boards are mounted, such as printed circuit boards  171 . The support plate  170  is supported on upstream and downstream ends  174  that are supported within the housing portion  69  and sealed by O-rings. The downstream support end  174  is coupled to an adapter  180  that mates to the upstream end of the centralizer  122 . A housing  199  is threaded onto the downstream end of the housing portion  69  and mates with the centralizer  122 . O-rings seal both the joint between the housing portion  69  and housing  199  and the joint between the housing  199  and the centralizer  122 . 
     The printed circuit boards  171  contain electronics components that are programed with associated information and soft-ware for operating the pulser  12 . Such software will include that necessary to translate the digital code from the data encoder  24  into operating instructions for the motor  32 . In some embodiments, this software will also include that necessary to analyze the signals from the down hole static pressure sensor  29  and/or the orientation encoder  44  and/or the dynamic down hole pressure sensor  28 , including that required to decipher encoded instructions from the surface that are received by the down hole dynamic sensor, and to control the operation of the motor  32  based on these signals, as explained further below. The creation of such software is well within the routine capabilities of those skilled in the art, when armed with the teachings disclosed herein. 
     A coupling  124  is formed on the downstream end of the centralizer  122  that allows it to be mechanically coupled with other portions of the bottom hole assembly  7 , which include the power supply  14  and data encoder  24 . An electrical connector  126  is mounted at the downstream end of the centralizer that allows the down hole pulser  12  to receive electrical signals from the power supply and data encoder  24 . A central passage  120  in the centralizer  122  allows conductors  128  from the connector  126  to extend to a connector  195  for the pulser  12 , which are then transmitted to the controller  26  via conductors, not shown. 
     As shown in FIG. 6, the down hole dynamic pressure sensor  28  is mounted in a recess  132  in the centralizer section  122 , although other locations could also be utilized. As shown best in FIGS.  9  and  9 ( a ), the down hole dynamic pressure sensor  28  is comprised of a diaphragm  144  formed by a circular face portion  145  and a rearwardly extending cylindrical skirt portion  148 . The diaphragm  144  must be sufficiently strong to withstand the pressure of the drilling mud  18 , which can be as high as 25,000 psi. However, it should also have a relatively low modulus of elasticity so as to be sufficiently elastic to dynamically respond to the pressure pulsations, the magnitude of which may be low at the pressure sensor  28 . Preferably, the diaphragm  144  is formed from titanium. Threaded holes are formed in the front surface of the diaphragm face  145  to facilitate removal of the sensor assembly  28 . 
     The piezoelectric element  150  is mounted adjacent, and in surface contact with, the diaphragm  144 . While piezoelectric elements can be made from a variety of materials, preferably, the piezoelectric element  150  is a piezoceramic element, which has a relatively high temperature capability (by contrast, piezoplastics, for example, cannot be used at temperatures in excess of 150° F.) and creates a relatively high voltage output when subjected to a minimum amount of strain. According to the piezoelectric phenomenon, certain crystalline substances, such as quartz and come ceramics, develop an electrical field when subjected to pressure. The piezoceramic element  50  according to the invention is preferably formed by forming a dielectric material, such as lead Metaniebate or lead zirconate titanate, into the desired shape, in this case, a thin disk. Electrodes are then applied to the material. The dielectric material is heated to an elevated temperature in the presence of a strong DC electric field, which polarizes the ceramic so that the molecular dipoles are aligned in the direction of the applied field, thereby imparting dielectric properties to the element. A piezoceramic element  150  has several attributes that make it especially suitable for down hole pressure pulsation sensing. It is compact. In one embodiment of a pressure pulsation sensor  16 , the piezoceramic element  50  is approximately only 0.8 inch in diameter and 0.02 inch thick. Piezoelectric elements consume relatively little electric power compared to strain gage based pressure transducers. Also, unlike strain gage based pressure transducers, the piezoceramic element  150  is not affected by static pressure, which would otherwise create a DC offset, because the voltage change that occurs when a piezoceramic element is stressed is transient, returning to zero in a short time even if the stress is maintained. Suitable piezoceramic elements are available from Piezo Kinetics Incorporated, Pine Street and Mill Road, Bellefonte, Pa. 16823. 
     The dynamic pressure sensor  28  also includes a plug  146  mounted behind the piezoceramic element  50 . The plug  146  is preferably formed from an electrically insulating material, such as a thermoplastic. It has external threads formed on its outside surface that mate with internal threads formed on a skirt portion of the diaphragm  144 . A dowel pin  154  is disposed in mating holes prevents rotation of the sensor assembly  28 . 
     In the preferred embodiment of the current invention, the piezoceramic element  150  is maintained in intimate surface contact with the diaphragm  144  by compressing the edges of the element between the rear face of the diaphragm and the plug  146 . The plug  146  is threaded into the diaphragm skirt  148  so that it rests on the piezoelectric element  150 , not the rear surface of the diaphragm face  145 , thereby leaving a gap between the plug and the diaphragm face. In operation, the high pressure of the drilling mud causes static deflection of the diaphragm face  145 , while pressure pulsations in the drilling mud cause vibratory deflection of the diaphragm face. Compressing the edges of the ceramic element  150  against the face of the diaphragm  144  ensures that the ceramic element will undergo vibratory deflections in response to vibratory deflections of the diaphragm face  145 , thereby enhancing the sensitivity of the sensor. 
     However, although the compressive force supplied by the plug  146  is sufficient to restrain the piezoceramic element  150  axially—that is, in the direction parallel to the axis of the diaphragm skirt  148 —it does not prevent relative sliding motion of the piezoceramic element in the radial direction—that is, in the plane of the element  150 . This prevents the piezoceramic element  150  from experiencing a large, static, tensile strain as a result of the static deflection of the diaphragm face  145 , such as would occur if the piezoceramic element  150  were glued or otherwise completely restrained with respect to the diaphragm face  145 . Such large tensile strains could result in failure of the piezoelectric element  150 , which is relatively brittle. In one embodiment of the invention, the plug  146  is threaded into the diaphragm skirt  148  so as to apply a 100 pound preloaded to the piezoelectric element  150 . 
     In operation, the high pressure of the drilling mud  18  causes static deflection of the diaphragm face  145 , while pressure pulsations in the drilling mud cause vibratory deflection of the diaphragm face which are transmitted to the piezoceramic element  150 . These vibratory deflections cause the voltage from the piezoceramic element  150  to varying in proportion to the deflection. 
     The conductor lead  156  from the piezoceramic element  150  extends through a potted grommet  157  on an intermediate support plate  155  formed in the plug  146 , and then through the passage  120  in the centralizer  122  before terminating at the controller  26 . As previously discussed, the printed circuit boards  171  of the controller  26  incorporate the electronics and software necessary to receive and analyze the voltage signal from the piezoceramic element  50 —for example, so as to determine the amplitude of the pressure pulses generated by the pulser  12  or to decode other instructions from the surface for operation of the pulser. 
     The construction and operation of the rotor  36  and stator  38  are shown in more detail in FIGS. 10-14. As shown in FIG. 10, the stator  38  is comprised of the collar  39  and an inner member  37 . Radially extending vanes  31  form axially extending passages  80  that are spaced circumferentially around the stator  38 . When the passages  80  are unobstructed, they allow drilling mud  18  to flow through the pulser  12  with minimum pressure drop. The rotor  36  is comprised of a sleeve  33  mounted by a key onto the rotor shaft  34  and from which blades  35  extend radially. Although four stator passages  80  and four rotor blades  35  are illustrated, other quantities of stator passages and rotor blades could also be used. 
     As discussed in detail below, preferably, the down hole pulser  12  operates by oscillating rotational motion—rotating first in one direction and then in an opposite direction. This mode of operation prevents flow blockages and jams. In a system that uses continuous rotation in a single direction, it is possible for a piece of debris to become lodged between the rotor and stator. This will have the effect of jamming the rotor and simultaneously obstructing one of the passages for the flow of drilling mud. In the current invention, any such obstruction will be alleviated during the normal course of operation, without disruption of data transmission, because reversal of the direction of rotor rotation during the next cycle will free the debris, allowing it to be carried away by the flow of drilling mud. This effect can be enhanced by shaping the rotor blades so that the clearance between the rotor and stator are increased when rotation occurs in one direction, as discussed below. 
     According to the preferred embodiment, the radial length l 2  of one of the edges  47  of each of the rotor blades  35 , shown as the trailing edge in FIG. 11, is slightly longer than the radial length l 1  of the opposite edge  45 , shown as the leading edge FIG.  11 —it should be appreciated that which edges are leading and trailing reverses each time the direction of rotation of the rotor reverses. Preferably, l 2  is about 0.010 inch longer than l 1 . In addition, as shown in FIG. 13, the downstream face  41  of each of the rotor blades  35  is preferably oriented at an angle φ with respect to the upstream face of the stator  38  so that the circumferential gap G by which the rotor blades are axially displaced from the stator increases from edge  47  to edge  45 . Preferably, the angle φ is at least about 5° so that the gap G 2  at edge  45  is at least about 0.040 inch larger than the gap G 1  at edge  47 , with G 1  preferably being about 0.080 inch. These two features—the unequal edge length and unequal axial gap—prevent jamming of the rotor since any debris trapped between the stator  38  and a rotor blade  35  during rotation in one direction will tend to be automatically dislodged when the rotor reverses its direction of rotation during the next cycle since such reversal will increase the radial and axial clearance between the rotor blades  35  and the stator  38  and thus allow the drilling fluid  18  to wash away the debris. 
     In an alternate embodiment, the downstream face  41 ′ of the rotor blade is concave, as shown in FIG.  13 ( a ), so that any debris sufficiently small to pass between the axial gap G 3  between the edges  45  and  47  of the blades  35 ′ and the stator  38  will end up being lodged in an area of increased axial gap G 4  and, thus, less likely to prevent rotation of the rotor. 
     As shown in FIG. 12, a novel annular seal  60  extends from the upstream end of the rotor  33  to the stator  38 . As a result of the pressure equalization system, described above, the pressure is approximately the same both inside and outside of the seal  60 . The upstream end of the seal  60  is secured by an interference fit onto a ring  85 , which, in turn, is press fit into the rotor sleeve  33  by a shim  87 . An O-ring  84  provides a seal between the ring  85  and the rotor shaft  34 . Note that although it rotates along with the rotor  36 , the O-ring  84  is considered a “stationary seal” because there is no relative rotation between the two members across which the seal is formed, in this case, the ring  85  and the rotor shaft  34 . Similarly, the downstream end of the seal  60  is press fit into the bore of the stator  38  by another shim  87 . O-rings  86  mounted in stationary seal rings  89  form stationary seals between the seal rings  89  and the stator  38 . In the illustrated embodiment, rotating seals  88  are mounted in the two downstream stationary seal rings  89  and form “rotating” seals between the rotating rotor shaft  34  and the stationary stator  38 . However, in many applications, the rotating seals  88  could be dispensed with so that there were no rotating seals and sealing accomplished exclusively with stationary seals—that is, seals between components that did not “rotate” relative to each other. 
     According to a preferred embodiment of the current invention, the seal  60  is generally cylindrical and preferably has helically extending corrugations so as to form a bellows type construction to facilitate torsion deflection without buckling, as well as axial expansion, as shown in FIG.  14 ( a ). Alternatively, a seal  60 ′ having axial corrugations, which facilitate torsional deflection, could be employed, as shown in FIG.  14 ( b ). The seal  60  is preferably made from a resilient material, such as an elastomer, most preferably nitrile rubber, that is able to withstand the torsional deflects resulting from repeated angular oscillations—for example, through an angle of 45° associated with the operation of the rotor  36 , discussed below. Note that since the rotor  36  does not create pressure pulses by continuously rotating in a given direction, but rather by rotating in a first direction and then reversing and rotating in the opposite direction so as to only oscillate, conventional rotating seals can be dispensed with, as discussed above. 
     The operation of the rotor  36  according to the current invention, and the resulting pressure pulses in the drilling mud  18  are shown in FIGS. 15 and 16, respectively. Preferably, the circumferential expanse of the rotor blades  35  is about the same as, or slightly less than, that of the stator vanes  31 . Thus, when the rotor  36  is a first angular orientation, arbitrarily designated as the 0° orientation in FIG.  15 ( a ), the rotor blades  35  provide essentially no obstruction of the flow of drilling mud  18  through the passage  80 , thereby minimizing the pressure drop across the pulser  12 . However, when the rotor  36  has been rotated in the clockwise direction by an angle θ 1 , the rotor blades  35  partially obstruct the passages  80 , thereby increasing the pressure drop across the pulser  12 . (Whether a circumferential direction is “clockwise” or “counterclockwise” depends on whether the viewer is oriented upstream or downstream from the pulser  12 . 
     Therefore, as used herein, the terms clockwise and counterclockwise are arbitrary and intended to convey only opposing circumferential directions.) If the rotor  36  is thereafter rotated back to the 0° orientation, a pressure pulse is created having a particular shape and amplitude a 1 , such as that shown in FIG.  16 . If, in another cycle, the rotor  36  is rotated further in the circumferential direction from the 0° orientation to angular orientation θ 2 , the degree of obstruction and, therefore, the pressure drop will be increased, resulting in a pressure pulse having another shape and a larger amplitude a 2 , such as that also shown in FIG.  16 . Therefore, by adjusting the magnitude and speed of the rotational oscillation θ of the rotor  36 , the shape and amplitude of the pressure pulses generated at the pulser  12  can be adjusted. Further rotation beyond θ 2  will eventually result a rotor orientation providing the maximum blockage of the passage  80 . However, in the preferred embodiment of the invention, the expanse of the rotor blades  35  and stator passages  80  is such that complete blockage of flow is never obtained regardless of the rotor orientation. 
     The control of the rotor rotation so as to control the pressure pulses will now be discussed. In general, the controller  26  translates the coded data from the data encoder  24  into a series of discrete motor operating time intervals. For example, as shown in FIG. 16, in one operating mode, at time t 1 , the controller  26  directs the motor driver  30  to transmit an increment of electrical power of amplitude e 1  to the motor  32 . After a short time lag, due to inertia, the motor  32  will begin rotating in the circumferential direction, thereby rotating the rotor  36 , which is assumed to initially be at the 0° orientation, in the same direction. 
     At time t 2 , after an elapse of time interval Δt 1 , the controller will direct the motor driver  30  to cease the transmission of electrical power to the motor  32  so that, after a short lag time due to inertia, the rotor  36  will stop, at which time it will have reached angular orientation θ 1 , which, for example, may be 20°, as shown in FIG.  15 ( b ). This will result in an increase in the pressure sensed by the surface sensor  20  of a 1 . At time t 3 , after an elapse of time interval Δt 2 , the controller  26  directs the motor driver  30  to again transmit electrical power of amplitude e 1  to the motor  32  for another time interval Δt 1 , but now in the opposite—that is, the counterclockwise—direction, so that the rotor  36  returns back to the 0° orientation, thereby returning the pressure to its original magnitude. The result is the creation of a discrete pressure pulse having amplitude a 1 . Generally, the shape of the pressure pulse will depend upon the relative lengths of the timer intervals Δt 1  and Δt 2  and the speed at which the rotor moved between the 0° and θ 1  orientations—the faster the speed, the more square-like the pressure pulse, the slower the speed, the more sinusoidal the pressure pulse. 
     It will be appreciated that the time intervals Δt 1  and Δt 2  may be very short, for example, Δt 1  might be on the order of 0.18 second and Δt 2  on the order of 0.32 seconds. Moreover, the interval Δt 2  between operations of the motor could be essentially zero so that the motor reversed direction as soon as stopped rotating in the first direction. 
     After an elapse of another timer interval, which might be equal to Δt 2  or a longer or shorter time interval, the controller  26  will again direct the motor driver  30  to transmit electrical power of e 1  to the motor  32  for another time interval Δt 1  in the clockwise direction and the cycle is repeated, thus generating pressure pulses of a particular amplitude, duration, and shape and at particular intervals as required to transmit the encoded information. 
     The control of the characteristics of the pressure pulses, including their amplitude, shape and frequency, afforded by the present invention provides considerably flexibility in encoding schemes. For example, the coding scheme could involve variations in the duration of the pulses or the time intervals between pulses, or variations in the amplitude or shape of the pulses, or combinations of the foregoing. In addition to allowing adjustment of pressure pulse characteristics (including amplitude, shape and frequency) to improve data reception, a more complex pulse pattern could be also be effected to facilitate efficient data transmission. For example, the pulse amplitude could be periodically altered—e.g., every third pulse having an increased or decreased amplitude. Thus, the ability to control one or more of the pressure pulse characteristics permits the use of more efficient and robust coding schemes. For example, coding using a combination of pressure pulse duration and amplitude results in fewer pulses being necessary to transmit a given sequence of data. 
     Although the rotational movement of the rotor in each direction necessary to create a pressure pulse discussed above was effected by a continuous transmission of electrical power e so as to energize the motor over time interval Δt 1 , in order to minimize power consumption, the motor could also be energized over time interval Δt 1  by transmitting a series of very short duration power pulses, for example on the order of 10 milliseconds each, that spanned time interval Δt 1  so that, after the initial pulse of electrical power, each pulse of electrical power during Δt 1  was transmitted while the rotation of the motor was coasting down, but had not yet stopped, from the previous transmission a pulse of electrical power. 
     As discussed above, the controller  26  could direct power to the motor  32  over a predetermined time interval Δt 1  so as to result in an assumed amount of rotation θ. Alternatively, the controller could control one or more characteristics of the pressure pulses by making use of information concerning the angular orientation of the rotor  36 , such as the angular orientation itself or the change in angular orientation, provided by the orientation encoder  44 . This allows the controller  26  to operate the motor until a predetermined angular orientation, or change in angular orientation, was achieved. For example, the controller  26  could rotate the motor continuously until a given orientation was reached and then cease operation, if necessary taking into account inertia in the system to estimate the final orientation achieved. Or the controller  26  could repeatedly rotate the motor over discrete short time intervals until the orientation encoder  44  indicated that the desired amount of rotation had been obtained. 
     Significantly, according to one aspect of the current invention, as a result of the resistance to rotation by the rotor drive train, ceasing rotation of the motor  32  will cause the rotor  36  to remain at angular orientation θ 1  throughout the time period Δt 2 . Thus, the magnitude of the angular oscillation of the rotor  36  is set without the use of mechanical stops to stop rotation of the rotor at a predetermined location. Nor are stops used to maintain the rotor  36  in a given orientation. Such stops, when used continuously, are a source of wear and failure. Nevertheless, mechanical safety stops could be utilized to ensure that rotation beyond a maximum amount, such as that capable of being safety accommodated by the seal  60 , did not occur. 
     Significantly, the control over the characteristics of the pressure pulses afforded by the current invention allows adjustment of these characteristics in situ in order to optimize data transmission. Thus, it is not necessary to cease drilling and withdraw the pulser in order to adjust the amplitude, duration, shape or frequency of the pressure pulses as would have been required with prior art systems. 
     Operation in the mode discussed above can be continued so that the pulser  12  continuously oscillates over angle θ 1 , generating a series of pressure pulses the amplitude, shape, duration and frequency of which is set by the timing of the signals operating the motor. 
     However, after a period of time, one or more of the characteristics of the pressure pulses thus generated may create problems in terms of data reception at the surface pressure sensor  20 . This can occur for a variety of reasons, such as a change in mud flow conditions (such as flow rate or viscosity), or an increase in the distance between the pulser  12  and the surface pressure sensor  20  as drilling progresses, thereby increasing pressure pulse attenuation, or the introduction of noise or other sources of pressure pulsations into the drilling mud. According to the current invention, the controller  26  will then direct the motor driver  30  to alter one or more characteristics of the pressure pulses as appropriate. 
     For example, the amplitude of the pressure pulses could be increased by increasing the time interval Δt 1 ′ during which the motor operates (for example, by increasing the duration over which electrical power of amplitude e 1  is transmitted to the motor). The increased motor operation increases the amount of rotation of the rotor  36  so that it assumes angular orientation θ 24 , for example 40°, as shown in FIG.  15 ( c ), thereby increasing the obstruction of the stator passages  80  by the rotor blades  35  and the pressure drop across the pulser  12 . Counter rotation of the rotor  36  back to the 0° orientation will result in the completion of the generation of a pressure pulse of increased amplitude a 2 . Operation is this mode will improved reception of data by the surface pressure sensor  20 . 
     Alternatively, data reception at the surface may be improved by altering the shape of the pressure pulse. For example, suppose that, after a period of time, the pressure pulses of increased amplitude a 2  also became difficult to decipher at the surface. According to the invention, the controller  26  could then direct the motor driver  30  to increase the amplitude of the electrical power transmitted to the motor to amplitude e 2  while also decreasing the time interval Δt 1 ″ during which such power was supplied. The transmission of increased electrical power will increase the speed of rotation of the rotor  36  so that it assumes angular orientation θ 2  sooner and also returns to its initial position sooner, resulting in a pressure pulse that more nearly approximates a square wave. This type of operation is depicted by the dashed lines in FIG.  16 . 
     Alternatively, if it were desired to increase the frequency of the pressure pulses, for example, to avoid confusion with noise existing at a certain frequency, the time intervals Δt 1  and Δt 2  during which the rotor is operative and inoperative, respectively, could be shortened or lengthened by the controller  26 . Further, in situations in which there were no problems with data reception, the time intervals could be shortened to increase the rate of data transmission, resulting in the transmission of more data over a given timer interval. 
     Various schemes can be developed for controlling the pressure pulses according to the current invention. For example, the controller  26  could be programmed to automatically increase the pressure pulse amplitude, or automatically make the shape of the pressure pulse more square-like, as the drilling time increased, or as the depth of the bottom hole assembly or its distance from the surface increased. The controller  26  could increase the pulse amplitude as a function of the magnitude of the static pressure of the drilling mud in the vicinity of the pulser  12  as sensed by the static pressure transducer  29 —the higher the pressure, the greater the amplitude. 
     According to a preferred embodiment, proper control is effected by monitoring the pressure pulses generated by the down hole pulser  12  so as to create a feed back loop. This can be done by having the controller  26  make use of the signal from the down hole dynamic pressure sensor  28  and operate the motor so as to satisfy one or more predetermined criteria for the pressure pulse characteristics. For example, the controller  26  could ensure that the pressure pulse amplitude is maintained within a predetermined range or exceeds a predetermined minimum as the drilling progresses and despite changes in drilling mud flow conditions. 
     As another example, the controller  26  can analyze the characteristics of extraneous pressure pulses in the drilling mud sensed by the pressure sensor  28 , for example from the mud pumps, by temporarily ceasing operation of the down hole pulser  12 . The controller can then compare the pressure pulses generated by the down hole pulser  12  to those extraneous pressure pulses that were within a predetermined frequency range around that of the frequency of the pressure pulses generated by the pulser. The controller  26  would then increase or decrease the frequency of the pressure pulses generated by the down hole pulser  12  whenever the amplitude of such extraneous pressure pulses exceeded a predetermined absolute or relative amplitude. Alternatively, the shape of the pressure pulses generated by the down hole pulser  12  could be varied to better able the surface detection equipment to distinguish them from extraneous pressure pulses. 
     In one preferred embodiment of the invention, the down hole dynamic pressure sensor  28  is capable of receiving instructional information from the surface for controlling the pressure pulses. In one version of this embodiment, the information contains direct instructions for setting the timing of the power signals to be supplied by the motor driver  30 . For example, the instructions might call for the controller  26  to increase the magnitude of the electrical power supplied to the motor by a specific amount so that the rotor rotated more rapidly thereby altering the shape of the pressure pulses, or increase the duration of each interval during which the motor was energized thereby increasing the duration and amplitude of the pressure pulses, or increase the time interval between each energizing of the motor thereby decreasing the frequency, or data rate. 
     In another version, instructional information is provided that allows the controller  26  to make the necessary adjustment in motor control based on the sensed characteristics of the pressure pulses generated by the pulser  12 . For example, the information transmitted to the pressure sensor  28  could be revised settings for a particular pressure pulse characteristic, such a new range of pressure pulse amplitude within which to operate or a new value for the pressure pulse duration or frequency. Using logic programmed into it, the controller  26  would then adjust the operation of the motor  32  accordingly until the signal from pressure sensor  28  indicated that the new setting for the characteristic had been achieved. 
     In one version of this embodiment, the instructional information is transmitted to the controller  26  by the surface pulser  22 , which generates its own pressure pulses  110  encoded so as to contain the instructional information. The pressure pulses  110  are sensed by the down hole pressure sensor  28  and, using software well know in the art, are decoded by the controller  26 . The controller  26  can then effect the proper adjustment and control of the motor operation to ensure that the pressure pulses  112  generated by the down hole pulser  12  have the proper characteristics. 
     In one version, this is accomplished by having the controller  26  automatically direct the down hole pulser  12  to transmit pressure pulses  112  in a number of predetermined formats, such as a variety of data rates, pulse frequencies or pulse amplitudes, at prescribed intervals. The down hole pulser  12  would then cease operation while the surface detection system analyzed these data, selected the format that afforded optimal data transmission, and, using the surface pulser  22 , generated encoded pressure pulses  110  instructing the controller  26  as to the down hole pulser operating mode to be utilized for optimal data transmission. 
     Alternatively, the controller  26  could be informed that it was about to receive instructions for operating the down hole pulser  12  by sending to the controller the output signal from a conventional flow switch mounted in the bottom hole assembly, such as a mechanical pressure switch that senses the pressure drop in the drilling mud across an orifice, with a low ΔP indicating the cessation of mud flow and a high ΔP indicating the resumption of mud flow, or an accelerometer that sensed vibration in the drill string, with the absence of vibration indicating the cessation of mud flow and the presence of vibration indication the resumption of mud flow. The cessation of mud flow, created by shutting down the mud pump, could then be used to signal the controller  26  that, upon resumption of mud flow, it would receive instructions for operating the pulser  12 . 
     According to the invention, the mud pump  16  can be used as the surface pulser  22  by using a very simple encoding scheme that allowed the pressure pulses generated by mud pump operation to contain information for setting a characteristic of the pressure pulses generated by the down hole pulser  12 . For example, the speed of the mud pump  16  could be varied so as to vary the frequency of the mud pump pressure pulses that, when sensed by the down hole dynamic pressure sensor  29 , signal the controller  26  that a characteristic of the pressure pulses being generated by the down hole pulser  12  should be adjusted in a certain manner. 
     Although the foregoing aspect of the invention has been discussed by reference to transmitting instructions from the surface down hole to the controller via pressure pulses, other methods of transmitting instructions down hole could also be utilized. For example, the starting and stopping of the mud pump in a prescribed sequence could be used to transmit instructions to the controller  26  by means of a conventional flow switch, such as that discussed above, that sensed the starting and stopping of mud flow. As another example, information can be communicated by modulating the speed of rotation of the drill string in a predetermined pattern so as to transmit encoded data to the controller. In such an communications scheme, triaxial magnetometers and/or accelerometers, such as those conventionally used in positional sensors in bottom hole assemblies, can be used to detect rotation of the drill string. The output signals from these sensors can be transmitted to the controller, which would deciphered encoded instructions from these signals. 
     Although, according to the current invention, pressure pulses are preferably generated using the oscillating rotary pulser  12  described above, the principle of controlling one or more characteristics of the pressure pulses transmitted to the surface by sensing the generated pressure pulses or by transmitting instructions to the down hole pulser is also applicable to other types of pulsers, including reciprocating valve type pulsers and convention rotary pulsers, provided that, by employing the principals of the current invention, they can be adapted to permit variations in one or more characteristics of the pressure pulses. For example, a special controller, motor driver, variable speed motor and down hole dynamic pressure transducer constructed according to the teachings of the current invention could be incorporated, as required, into a conventional siren type rotary pulser system, discussed above. This would allow the surface detection system to transmit information, by way of pressure pulses generated at the surface as discussed above, to the controller of the down hole pulser instructing it, for example, to increase the rotational speed of the siren because data reception at the surface was being impaired by inference from extraneous pressure pulses at a frequency close to that of the siren frequency. The controller would then instruct the motor driver to increase the electrical power to the motor so as to increase the siren frequency. Alternatively, the controller could instruct the motor so as to adjust the phase shift of the pressure pulses relative to a reference signal that is used to encode the data. As another example, a conventional rotary pulser employing an escapement mechanism actuated by an electrically operated solenoid, such as that discussed above, could be modified with a controller that varied the operation of the solenoid so as to vary the duration or frequency of the pulses, for example, based on a comparison between the sensed duration or frequency of the pressure pulses generated by the down hole pulser or based upon instructions from the surface system deciphered by the down hole dynamic pressure transducer. 
     Thus, although the current invention has been illustrated by reference to certain specific embodiments, those skilled in the art, armed with the foregoing disclosure, will appreciate that many variations could be employed. For example, although the invention has been discussed with reference to a reversible electric motor, other motors, such as hydraulic motors capable of being quickly energized, could also be utilized. 
     Therefore, it should be appreciated that the current invention may be embodied in other specific forms without departing from the spirit or essential attributes thereof and, accordingly, reference should be made to the appended claims, rather than to the foregoing specification, as indicating the scope of the invention.