Patent Publication Number: US-7219747-B2

Title: Providing a local response to a local condition in an oil well

Description:
BACKGROUND 
   Wired pipe for use in drilling oil wells has become available. The use of data delivered through the wired pipe raises new challenges. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS  
       FIG. 1  shows a system for surface real-time processing of downhole data. 
       FIGS. 2 and 3  are schematic diagrams of control systems for providing a local response to a local condition in an oil well. 
       FIG. 4  illustrates portions of a drill string. 
       FIG. 5  illustrates an axial motion modulator. 
       FIG. 6  illustrates a torque modulator. 
       FIG. 7  illustrates a dynamic bumper sub using a solenoid. 
       FIG. 8  illustrates a dynamic bumper sub using a hydraulic pump. 
       FIG. 9  illustrates hydraulic logic for the dynamic bumper sub shown in  FIG. 8 . 
       FIG. 10  illustrates a dynamic clutch sub. 
       FIG. 11  illustrates a dynamic vibrator sub. 
       FIG. 12  illustrates a dynamic bending sub. 
       FIG. 13  illustrates a localized boundary condition in a drill string. 
       FIG. 14  illustrates apparatus for affecting a localized boundary condition in a drill string. 
       FIGS. 15A and 15B  illustrate a heat energy modulator. 
       FIG. 16  illustrates a heat energy modulator 
       FIG. 17  illustrates a sonic energy modulator. 
       FIG. 18  illustrates a flow chart for a system that provides local responses to local conditions in an oil well. 
   

   DETAILED DESCRIPTION 
   As shown in  FIG. 1 , oil well drilling equipment  100  (simplified for ease of understanding) includes a derrick  105 , derrick floor  110 , draw works  115  (schematically represented by the drilling line and the traveling block), hook  120 , swivel  125 , kelly joint  130 , rotary table  135 , drill string  140 , drill collar  145 , LWD tool or tools  150 , and drill bit  155 . Mud is injected into the swivel by a mud supply line (not shown). The mud travels through the kelly joint  130 , drill string  140 , drill collars  145 , and LWD tool(s)  150 , and exits through jets or nozzles in the drill bit  155 . The mud then flows up the annulus between the drill string and the wall of the borehole  160 . A mud return line  165  returns mud from the borehole  160  and circulates it to a mud pit (not shown) and back to the mud supply line (not shown). The combination of the drill collar  145 , LWD tool(s)  150 , and drill bit  155  is known as the bottomhole assembly (or “BHA”). A communications media  170  may provide communications among components in the borehole or on the surface and between those components and a surface real-time processor  175 . A terminal  180  may be provided to allow a user to view data retrieved from the borehole and surface components and to provide control inputs where appropriate. A power source  185  provides power to the components in the system. In one embodiment of the invention, the drill string is comprised of all the tubular elements from the earth&#39;s surface to the bit, inclusive of the BHA elements. In rotary drilling the rotary table  135  may provide rotation to the drill string, or alternatively the drill string may be rotated via a top drive assembly. The term “couple” or “couples” used herein is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect electrical connection via other devices and connections. 
   The drill string may be a “wired” drill string, in which joints of drill pipe are wired to pass power and communications signals to connected joints of drill pipe. Typically, node subs are located in the drill string which amplify signals as they pass. Such a wired drill string may be part of the communications media  170 . 
   It will be understood that the term “oil well drilling equipment” or “oil well drilling system” is not intended to limit the use of the equipment and processes described with those terms to drilling an oil well. The terms also encompass drilling natural gas wells or hydrocarbon wells in general. Further, such wells can be used for production, monitoring, or injection in relation to the recovery of hydrocarbons or other materials from the subsurface. 
   A number of significant factors may detract from the rapid, cost-efficient, and safe drilling of a quality borehole. Many of these factors may be characterized as undesirable and non-productive dynamic behavior of the drill string. 
   An ideally desired dynamic behavior of the drill string, for most cases, includes the continuous and constant instantaneous speed rotation of the bit, along with a continuous and constant instantaneous rate of progression (or rate of penetration “ROP”) of the bit through the formation. “Constant” for both speed and ROP does not necessarily mean unvarying over the entire well, but means, rather, the optimum of such values for the particular bit characteristics, formation being drilled, and other parameters (e.g. hole angle) of the moment. Over the drilling process, the ideal constants will likely undergo step changes and continuous changes over time. However, in segments of the drilling process between the step changes (e.g. formation boundaries), these constants should not change during the course of one or several drill bit revolutions. In short, the potential energy available in the drill string in its weight X displacement, and in its torque available X rotation angle, ideally will be consumed solely in the breaking and clearing of rock at the bit face in a continuous manner. 
   The reality of mechanical systems used in drilling, however, involves variables and degrees of freedom such that this ideal drill string behavior is often not obtained. The drill string&#39;s limberness, the complex curvatures of the borehole, and the variable boundary conditions (e.g. hole gauge and friction factors) provide for multiple dynamic systems up and down the drill string and borehole. Any arbitrary section of drill string and borehole may be characterized as such a dynamic system, with mass and inertia, stiffness factors, particular degrees of freedom and boundary conditions, and with energy inputs which are, at their simplest, the rotation and/or sliding from the surface, and may additionally include complex excitations which may modulate this energy, such as the bit engagement with a formation. The multiple dynamic systems up and down the drill string may be significantly coupled to or relatively uncoupled from each other. These systems and degrees of coupling may evolve and change over time and as the hole is drilled and the conditions change. There may be multiple responses to the energy input into each of these dynamic systems, which in addition to the desired 1:1 transmittal of rotary and translation energy to the bit, may include well-known detrimental conditions such as drill string whirl, bit bounce, torsional stick/slip of the bit and torsional waves up and down the string, and translational or torsional stick/slip of the drill string. These dynamic conditions may sap energy from the drilling process and frictional losses to the borehole wall, with the associated drill string (and borehole casing) abrasive wear, may cause higher than normal stresses in drill string components, and detract from the ideal bit-on-bottom behavior discussed above. In worst cases, these non-ideal dynamic conditions may include excitation to resonance, which may accelerate failures. 
   For example, there are various dynamics induced by the bit/formation interaction which may detract from the ideal drilling process. The tri-cone bottom-hole pattern can cause axial excitations at a frequency of 3 times bit RPM, which typically is in the 3–20 Hz base frequency range, with higher harmonics. These excitations may represent no more than the bit traversing circularly undulating (i.e. lobed) hole bottom with each revolution, while still remaining ideally engaged with the rock. But depending upon all the variables of the dynamic system, a bit-bounced dynamic could begin, with the bit losing ideal engagement with the bottom of the hole. Displacements could be on the order of 0.1 to 1 or even several inches. By placing a dynamic axial actuator in the BHA, the moment that this bit bounce condition is detected, a control signal can be sent initiating dynamic output from the axial actuator (i.e. displacements) synchronous with and opposite to the motion from the bit bounce, canceling or dampening the dynamic behavior. Alternatively, requiring less energy, and recognizing a “normal” condition of bit undulation while remaining ideally engaged, the axial actuator could dynamically and synchronously respond to absorb the displacement emanating from the bit and isolate this displacement from the rest of the string. In doing so this bit-induced dynamic is removed and not fed back into the dynamic system, thereby preventing a resonant condition and an inefficient drilling condition. 
   Generally, these destructive dynamic conditions may be characterized as (i) undesirable energy in the drill string or (ii) unfavorable drill string boundary conditions. Undesirable energy in the drill string may be undesirable axial energy, that is, undesirable energy flowing substantially longitudinally along the drill string, undesirable torque, that is, undesirable energy causing the drill string to twist in a ways that are not intended, or undesirable flexing of the drill string. Unfavorable drill string boundary conditions include friction, suction or any other condition that limits free motion of the drill string in the borehole and therefore limits the maximum transfer of energy from the drill string to the process of breaking and clearing of rock at the bit face in a continuous manner. Other drill string boundary conditions which may at times be unfavorable include particular combinations of hole gauge or shape, hole curvature or straightness, and drill string elements in contact, near contact, or not near contact with the borehole, which together contribute to the degree of freedom (particularly in radial or lateral axes) of the drill string in the borehole. 
   Often, these conditions are local in nature. That is, undesirable axial energy and undesirable torque energy tends to move in waves, or perturbations moving up and down the string at rates corresponding to the sonic velocity (which may vary) in and along the drill string. Even recognizing that such waves may travel significant distances along the string, each wave of such energy affects only a small portion of the drill string at any given moment. And importantly, controlled actions taken locally involving energy addition, damping, and/or modulations can have a useful affect in regard to these undesirable energy waves. Similarly, undesirable drill string boundary conditions tend to be localized. For example, a short segment of a drill string may experience friction at a point where the borehole bends. The friction may be localized to the area of the bend. 
   The system described herein provides local responses to oil well conditions which may be but are not necessarily local. The system identifies the oil well (i.e. borehole and/or drill string) condition at one or more locations, or for the borehole/drill string in aggregate, using sensors distributed along the drill string and provides one or more local responses using controllable elements distributed along the drill string. One way to visualize the system is as a “muscular” drill string, with the individual controllable elements being analogous to muscles in a human body. When it is desirable for the human body to perform a function, for example because of what the human body senses, a set of muscles are commanded to act. In most cases, only a few of the body&#39;s muscles are involved and the remaining muscles are not commanded. 
   An example system for providing a local response to a local condition, illustrated in  FIG. 2 , includes one or more energy modulators  205 , which are described in more detail with respect to  FIGS. 4 ,  5  and  6 , distributed along the drill string  140 . Generally, the energy modulators add, subtract or otherwise modify energy in the drill string, with each energy modulator being designed to address a specific drill string condition. 
   The energy modulators  205  may communicate with a real-time processor, e.g., the surface real-time processor  175  via the communications media  170 , which may control at least some of the functions of the modulators  205 . A set of sensor modules  210  is also distributed along the drill string  140  and may communicate with the surface real-time processor  175  via the communications media  170 . In this example system, the surface real-time processor  175  acts as a “brain,” receiving inputs from the sensor modules  210  and controlling the muscles associated with the energy modulators  205 . It should be noted that the term “real-time” as used herein to describe various processes is intended to have an operational and contextual definition tied to the particular processes, such process steps being sufficiently timely for facilitating the particular new measurement or control process herein focused upon. For example, in the context of drill pipe being rotated at 120 revolutions per minute (RPM), and a undesirable drill string behavior or perturbation corresponding to three cycles per bit revolution, then a “real time” series of process steps of detection and response, canceling or damping a significant portion of this undesirable energy, would occur sufficiently timely in context of the ⅙ of a second duration for one of those perturbation cycles. 
   In another embodiment, illustrated in  FIG. 3 , the “muscles” are not controlled exclusively through commands from the surface real-time processor  175 . In this embodiment, sensors and energy modulators are formed into an autonomous network that may operate with little or no supervision from the surface real-time processor  175 . As in the previous embodiment, energy modulators  305  and sensor modules  310  are distributed along the drill string  140 . Each sensor module  310  includes one or more sensors. As indicated in  FIG. 3 , the sensors in each sensor module  310  can be of many types, including pressure sensors, temperature sensors, strain sensors, force sensors, rotation sensors, translation sensors, accelerometers, shock sensors or counters, borehole proximity or caliper sensors, and many other types of sensors that are useful in drilling and logging of boreholes. Each energy modulator  305  may have an associated control unit  315  which may monitor the signals from one or more of the sensor modules  310  in the system. The high speed communications media  170  threading the entire system allows each control unit  315  to monitor sensor modules  310  located at positions all along the drill string  140 . The control units  315  command the muscles of the system to respond automatically to the stimuli detected by the sensor modules  310 , with the possibility of a manual over-ride from the surface equipment. In its simplest embodiment, the control units  315  would employ a weighted sum voting procedure to decide whether to activate a particular muscle, and in what manner it should be activated. In the embodiment shown in  FIG. 3 , which shows three energy modulators  305  and three sensor modules  310 , each sensor module  310  contains two different kinds of sensors. Each sensor module  310  provides a weighted output through the communications media  190  to each of the three control units  315  for the energy modulators  305 . The weights may be determined with help of one or more drill string/borehole models, and/or by a function e.g., by training the system (as in a neural network), or by specification based on simulated responses. For example, in one embodiment, when the sum of the weights exceeds a pre-set threshold, a specific action is to be taken by the energy modulator  305 . This action is directed by a series of commands from the control unit  315 . While, for simplicity, the weights needed for just one response are shown in  FIG. 3 , a separate set of weights may be used for each response. These activities and functions can be carried out in the surface real-time processor using an arrangement as shown in  FIG. 2 . 
   A more general approach involves the use of a joint inversion of data collected from the sensor modules  310  to determine the desired action to be taken by the energy modulators  305 . If the variables v 1 , v 2 , . . . , v N  are related by N functions ƒ 1 , ƒ 2 , . . . , ƒ N  of the N variables x 1 , x 2 , . . . , x N  by the relation 
   
     
       
         
           
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   Then the process of determining specific values of x 1 , x 2 , . . . , x N  from given values of v 1 , v 2 , . . . , v N  and the known functions, ƒ 1 , ƒ 2 , . . . , ƒ N  is called joint inversion. The process of finding specific functions g 1 , g 2 , . . . , g N  (if they exist) such that 
             (           x   1               x   2             …           …             x   N           )     =     (             g   1     ⁡     (       v   1     ,     v   2     ,   …   ⁢           ,     v   N       )                   g   2     ⁡     (       v   1     ,     v   2     ,   …   ⁢           ,     v   N       )               …           …               g   N     ⁡     (       v   1     ,     v   2     ,   …   ⁢           ,     v   N       )             )           
so that (v 1 , v 2 , . . . , v N )=g k (ƒ k (v 1 , v 2 , . . . , v N )) for 1≦k≦N is also called joint inversion. This process is sometimes carried out algebraically, sometimes numerically, and sometimes using Jacobian transformations, and more generally with any combination of these techniques.
 
   More general types of inversions are indeed possible, where 
             (           v   1               v   2             …           …             v   N           )     =     (             f   1     ⁡     (       x   1     ,     x   2     ,   …   ⁢           ,     x   M       )                   f   2     ⁡     (       x   1     ,     x   2     ,   …   ⁢           ,     x   M       )               …           …               f   N     ⁡     (       x   1     ,     x   2     ,   …   ⁢           ,     x   M       )             )           
where M&gt;N
 
   but in this case, there is no unique set of functions g 1 , g 2 , . . . , g M . 
   In general, as shown in  FIG. 4 , sensor modules  310  in a first portion of the drill string  140  detect parameters of the drill string in a second portion of the drill string  140 . The detected parameters may be lumped parameters. 
   For example, assigning a friction coefficient to a precise point of measurement may not be useful. Defining such a coefficient may be more useful in describing the relation between force and sliding resistance over an area of the drillstring. Another example would be the relative deflection of a drill string from one point A along the drill string to another point B along the drill string. The concept of deflection may have little or no meaning at any point along the drill string. Furthermore, the deflection of the drill string from point x to point x+dx, where dx is an infinitesimally small distance, is itself infinitesimal; i.e. deflection is a continuous function. Thus, the deflection from A to B is a lumped parameter of the drill string. 
   In addition, the drill string may be modeled as a set of mass-spring-dashpot elements linked end to end, i.e. in series. Each of the mass-spring-dashpot elements may correspond to an arbitrary portion of the drill string, where the portion may be very small, on the order of inches or fractions of inches, or very large, on the order of hundreds or even thousands of feet. In that case the detected lumped parameters may be the parameters associated with each of the mass-spring-dashpot elements, such as, for example, spring constant, dashpot damping coefficient, etc. 
   Moreover, some parameters may be effectively measured at a single point and treating them as lumped parameters may not be necessary or as effective or useful. For example, temperature and strain can be associated with an infinitesimally small region of a drill string. 
   Further, energy modulators in a third portion of the drill string  140  may affect the parameters of the drill string  140  in the second portion of the drill string. The first, second and third portions of the drill string may overlap and may be identical, as shown in  FIG. 4 . 
   The energy modulators  205  and  305  fall into two general categories: energy modulators that produce, absorb or modify kinetic energy and energy modulators that produce, absorb or modify other kinds of energy. Among the energy modulators that produce kinetic energy are axial motion modulators, torque modulators, flex modulators, radial modulators and lateral motion modulators. Among the energy modulators that produce other kinds of energy are energy modulators that produce heat, light, electromagnetic fields and other forms of energy. 
   An example of an energy modulator that affects kinetic energy, specifically axial energy, is an axial motion modulator, as illustrated in  FIG. 5 . The axial motion modulator  505  counters a large axial motion  510  (for example the bit bouncing upwards) by an opposite axial motion  515  provided by the axial motion modulator  505 . Alternatively, the axial motion modulator could absorb, rather than counteract, the large axial motion  510 , as discussed below. As a consequence, the axial motion above the axial motion modulator  520  is reduced in intensity. The high-speed communications media  170  allows data from the axial motion modulator  505  to processed as shown in  FIG. 2  or  FIG. 3 . Similarly, the high-speed communications media  190  allows control of the actions of the axial motion modulator  505  and, in particular, control of the opposite axial motion  515  produced by the axial motion modulator  505 . A separate power connection  530  may be provided to allow the axial motion modulator to react with sufficient energy. 
   Another example of an energy modulator that affects kinetic energy, specifically torque, is a torque modulator  605 , as shown in  FIG. 6 . The torque modulator  605  transfers a controllable amount of torque from one side of the torque modulator  605  to the other side. As a consequence, a large torsional perturbation  610  experienced above the torque modulator  605 , for example as a result of the bit hitting a brief formation hard spot, could be reduced to a smaller amount of torque  615  below the torque modulator. The share of torque transferred by the torque modulator  605  would be controlled by a real-time processor e.g., the surface real-time processor  175  based on data transferred back and forth across the high-speed communications media  170 . Further, a power connection to the surface  620  may be included to provide enough power for the torque modulator  605  to perform its function. Other embodiments of the invention may provide partial or full power to one or more energy modulators, for example the torque modulator  605 , via other sources of energy e.g., a battery that is local to the torque modulator, a fuel cell, or power derived from the surface rotation or the mud flow in the borehole. 
   One example of an axial motion modulator  505  is a dynamic bumper sub. Conventionally, bumper subs provide a compliant axial linkage between BHA elements, usually with a spring and passive damping with fluid being forced through an orifice during relative motion. 
   One embodiment of a dynamic bumper sub provides, in addition to, and from an axial load path standpoint, in parallel with, the spring and passive damping elements, an active element. One example of an active element, shown in  FIG. 7 , is a fast responding axial solenoid assembly included in an annular package within the dynamic bumper sub. 
   Referring to  FIG. 7 , a dynamic bumper sub  700  using a solenoid is shown in cross section relative to a centerline  701 . The bumper sub  700  includes a housing structure  702  connected to a pipe section  703  by a rotary shouldered connection. An electronics housing  704  may be positioned between the housing structure  702  and the pipe section  703 . A printed circuit board  705  may be contained within the electronics housing  704 . O-ring seals  706  and  707  prevent environmental fluids from entering the interior of the electronics housing  704 . Electric power and communication wires  708 , (which may be part of the communications media  170 ) may extend from the pipe section  703  to a connector in the electronics housing  704 . A second set of electric power and communication wires  709  may extend from an electric connector in the electronics housing  704  into the housing structure  702 . Electric connector  710  may be positioned at the top of the electronics housing  704  and electric connector  711  is positioned at the bottom of the electronics housing  704 . A third set of electric power and communication wires  733  may extend from the second set to the bottom of the mandrel spring block section  714 , and may extend to the bottom end (pin connection) of the bumper sub for continuity of power and communications to the next lower drill string element. The third set of electric power and communication wires  733 , as shown, has a curly conduit section that bridges the gap between the mandrel structure  712  and the housing structure  702  to allow relative axial movement between the structures. In this particular embodiment, and in all embodiments of the invention, wires may be routed along exterior or interior of, along milled grooves within, and/or through holes drilled within the mechanical components and structures to traverse those components and structures. The wires may be secured in place by potting, banding, taping, and other techniques as known in the art and not specifically shown in the drawings. Connectors may be single conductor or multi-conductor, and may hermetically sealed where required, and are available from suppliers including Kemlon and GreenTweede. 
   A mandrel structure  712  is made up within the housing structure  702 . The mandrel structure  712  may include a mandrel piston section  713  and a mandrel spring block section  714 . The mandrel spring block section  714  may be threaded into the mandrel piston section  713  with o-ring seal  715  between. The mandrel structure  712  may be slidably mounted within the housing structure  702  to allow axial translation of the mandrel structure  712  relative to the housing structure  702 . Lines  716  and  717  may be integrated between the housing structure  702  and the mandrel structure  712  to prevent relative rotational movement between the structures while allowing axial translation. 
   The bumper sub  700  may also include a solenoid  718  for axially displacing the mandrel structure  712  relative to the housing structure  702 . As illustrated, the solenoid  718  may include an electrical conductor wound many times around the interior of the housing structure  702 . In an alternative embodiment, the electrical conductors may be wound around the mandrel and/or both the mandrel structure  712  and the housing structure  702 . Electric power may be communicated to the solenoid  718  through the second set of electric power and communication wires  709 . The amount of current flowing to the solenoid, and therefore the amount of force generated by the solenoid, may be controlled by the printed circuit board  705 , which may receive its instructions, for example, from the surface real-time processor, via the electric power and communications wires  708 . The number of windings, the size of the wire used to form the windings, and the amount of current flowing through the windings may be chosen so that the solenoid can provide sufficient force to counteract forces traveling along the drill string. The amount of force generated by a solenoid is an increasing function of the number of windings and is also directly proportional to the current flowing through the windings. The wire making up the windings may be sized to sustain the amount of current required to produce the requisite amount of force. The printed circuit board  705  may also include one or more of the sensors discussed, preferably including axial acceleration sensors, which may be useful in control of the bumper sub. 
   The bumper sub  700  may further include an electronically controlled hydraulic dampener. A balance chamber  719  is separated from a spring chamber  720  by a throttle control  721 . The balance chamber  719  may have a balance piston  722  which separates mud fluids in an upper portion of the balance chamber  719  from hydraulic fluid contained within the bottom portion of the balance chamber  719 . Mud fluid circulating through the inner diameter of the mandrel structure  712  may be communicated to the upper portion of the balance chamber  719  through balance port  723 . Hydraulic fluid in the lower portion of the balance chamber  719  may fluidly communicate with the hydraulic fluid in the spring chamber  720  through the throttle control  721 . The throttle control  721  may be electronically controlled by the second set of electric power and communication wires  709  to control the cross-sectional area of the orifice through which hydraulic fluid flows through the throttle control  721 . A spring  724  may be positioned within the spring chamber  720 , wherein it engages the mandrel spring block section  714  and the housing structure  702 . Thus, the spring  724  may bias axial movement of the mandrel structure  712  out of (telescope) the housing structure  702 . O-ring seals  725  are positioned between the mandrel spring block section  714  and the housing structure  702  to seal the lower portion of the spring chamber  720 . The bumper sub  700  may also have a fill plug  726  through which hydraulic fluid may be injected into the balance chamber  719  and spring chamber  720 . 
   Given the mud and circulation fluids flow through the inner diameter of the bumper sub  700 , a flow deflector  727  may be connected to the housing structure  702  to protect the junction between the housing structure  702  and the mandrel structure  712  from the erosive power of the mud flow. The lower portion of the mandrel structure  712  may also have a pin connector  728  for making up the bumper sub  700  to drill string. 
   The inward stroke of the mandrel structure  712  into the housing structure  702  is limited by contact between a stroke shoulder  729  and the housing and  730 . Outward stroke of the mandrel structure  712  relative to the housing structure  702  is limited by contact between the lower end of the mandrel piston section  713  and the housing structure  702  at the throttle control  721 . 
   The electronic control of the force generated by the solenoid and the hydraulic dampener provides dynamic control of the properties of the dynamic bumper sub  700 . 
   The dynamic bumper sub  700  may also include a mini-sensor set  732 . The sensors of the sensor set  732  may be positioned in the exterior of the mandrel spring block section  714  where it extends below the housing structure  702 . The sensor set  732  may be electrically connected to the third set of electric power and communication wires  733 . One or more of the sensors discussed may be included within this mini-sensor set  732 , preferably including an axial acceleration sensor which preferably in conjunction with a similar such sensor in the electronics section printed circuit board  715  may be useful in controlling the bumper sub. 
   In another embodiment of the axial motion modulator  505 , an annular hydraulic piston assembly is built into the pipe section. The annular piston may engage a cylinder whose volume is rapidly modulated per the control signal (provided over the data interface  525 ), with the change in volume accomplished, for example, by opening and closing large volume valves. A high-volume electrically driven positive displacement hydraulic pump may be running continuously and valve-end to the cylinder as required. 
   With an electric motor driving at, for example, 3,000 RPM, and, for example, quantity 16 of 0.5 inch diameter pump pistons disposed in an annular array on a four inch nominal diameter (e.g. within a 6.75 inch collar section), and a swash plate stroke of 0.2 inches, around 31 cubic inches of fluid per second can be produced. The response frequency and amplitude would depend then upon the annular piston area. An annular piston with a differential area of one square inch, and a maximum stroke of, for example, one inch could respond full stroke (one way) within 0.03 seconds, which would be sufficient for offsetting typical bit-bounce frequencies. Multiple such units could be employed to increase volume capacity and/or to increase the annular piston differential area and thereby the force capability. Valving and/or use of two such pump units could be employed to actively drive the annular piston in both directions. 
   Another example would include a hydraulic pump, as described above, but rather than the pump output directly acting upon the annular piston, the pump output would be directed to fill a large annular storage chamber, pressured above ambient by its own spring and piston system. The volume held in the storage chamber might be many times that required to be used for countering a typical dynamic condition flare-up and, therefore, the hydraulic oil could be applied to the task of displacing the bumper sub&#39;s annular piston (under pressure of the storage system spring) at a volumetric rate limited only by the hydraulic flow path resistances (i.e. not limited by the output rate of pumps). A two foot length of 6¾ inch collar would allow for on the order of 400 cubic inches of fluid storage, which, without considering refill rate by the pumps, would provide for 200 roundtrip one-inch stroke cycles with a one-inch area annular piston described above. The required system response to canceling unwanted dynamics requires many of the other system elements discussed earlier, including preferably the nearby sensing capability, the high-speed communications media  170  for sensor modules and control signals to and from a surface real-time computer  175 , and a significant electrical power source to drive the motor, as illustrated in  FIG. 5 . 
   An example of such a dynamic bumper sub is illustrated in  FIG. 8 . Referring to  FIG. 8 , a cross-sectional, side view about center line  801  of a dynamic bumper sub  800  using hydraulic actuation is illustrated. The sub  800  has a housing  802  and a mandrel  803  that slides in the axial direction relative to the housing  802 . Two chambers may be defined between the mandrel  803  and the housing  802 : a telescoping chamber  804  and a retracting chamber  805 . A mandrel flange  806  may extend radially outward from the mandrel  803  to divide the two chambers. Further, the mandrel flange  806  may have an o-ring seal  807  around its circumference to prevent leakage between the chambers. The mandrel  803  may telescope out of the housing  802  when hydraulic fluid is pumped into the telescoping chamber  804  and the mandrel  803  retracts into the housing  802  when hydraulic fluid is pumped into the retracting chamber  805 . A spring (not shown) may be located in the retracting chamber  805  to resist the telescoping of the mandrel  803  out of the housing  802 . In that case, it may not be necessary to pump hydraulic fluid into the retracting chamber  805 . 
   A spring chamber  808  may also defined between the mandrel  803  and the housing  802 . A housing flange  812  may extend radially inward from the housing  802  to divide the retracting chamber  805  from the spring chamber  808 . The housing flange  812  may have an o-ring seal  813  at its interior circumference to prevent fluid flow between the chambers. A spring  809  may be positioned within the spring chamber  809  to bias the mandrel  803  in the telescoping direction. Two splines  810  and  811  may be configured between the mandrel  803  and the housing  802  to prevent the members from rotating relative each while allowing relative movement in the axial direction. The bottom of the spring chamber  808  is in fluid communication with the annulus on the exterior of the sub to allow mud fluid to flow into the chamber. 
   The sub  800  may include a motor  815  for producing the hydraulic pressure needed to charge the chambers. The motor  815  includes a stator  816 , which is mounted to the housing  802 , and a rotor  817 , which is positioned coaxially on the outside of the stator  816 . The rotor  817  is mounted on an annular drive shaft  818  that is supported by bearings  819 . At the opposite end from the rotor  817 , a swash plate  820  is connected to the drive shaft  818 . Because the drive shaft  818  is longer on one side than the other (i.e. the cylindrical structure has a mitered lower end face), the swash plate  820  moves up and down relative to the housing  802  as the motor  815  spins the swash plate  820 . A plurality of pump rams  821 , 16–20 pump rams in one embodiment, may be positioned radially around the housing  802  immediately below the swash plate  820  within smoothly drilled bores in the housing structure. The heads of the pump rams  821  are engaged by the swash plate  820  so that as the swash plate  820  moves up and down during its rotation, individual pump rams  821  are charged and released. When the swash plate  820  rotates 360 degrees, each of the individual pump rams  821  are charged once. 
   The motor  815  may also be protected with an oil that is pressure balanced through a balance chamber  833 . The balance chamber  833  has a balance piston  834  separating oil in an upper portion from mud in a lower portion. The lower portion of the balance chamber  833  fluidly communicates with the ID of the sub via balance port  835 . The upper portion of the balance chamber  833  fluidly communicates with the space containing the motor  815 , and with the region of the pump ram heads (i.e. pump ram inlets). 
   The pump rams  821  pump hydraulic fluid into an annular, spring loaded, hi-pressure storage chamber  822  that may be defined within the housing  802 . The hi-pressure storage chamber  822  is a reservoir from which hydraulic fluid under high pressure is drawn to charge the telescoping chamber  804  and the retracting chamber  805 . In other embodiments, the hi-pressure storage chamber  822  is omitted. A manifold is positioned within a valve block  823 , wherein the manifold connects the various valves and conduits required to circulate the hydraulic fluid in accordance with the required hydraulic logic described more fully below. Conduits may be hydraulic hoses, or other means known in the art of communicating hydraulic fluid flow including via holes drilled through or grooves milled upon the structures shown, and/or reliefs between diameters or faces of adjacent components, all such communication paths including appropriate cooperative seals to contain the hydraulic fluid to its designated path. In particular, one set of inlet and exhaust conduits connects the manifold to the telescoping chamber  804  and another set of inlet and exhaust conduits connects the manifold to the retracting chamber  805 . A recirculation conduit  900  (See  FIG. 9A ) connects the manifold to the inlet region of the pump rams  821 . 
   The dynamic bumper sub  800  may also have an electronics housing  830  that protects a printed circuit board  831 , which may contain electronic components for control and sensing elements as described in an earlier bumper sub embodiment. A power and control wire  832  communicates between the electronics housing  830  and the motor  815 . 
   Referring to  FIGS. 9A and 9B , the hydraulic logic for the manifold and system of the dynamic bumper sub  800  shown in  FIG. 8  are illustrated in schematic form. In particular,  FIG. 9  shows that the manifold may have three inlet ports: port  1 , port  2 , and port R. When port  1  is open, fluid is pumped into the telescoping chamber  804 . When port  2  is open, fluid is pumped into the retracting chamber  805 . As indicated above, this portion of the hydraulic logic may not be necessary if a spring is located in the retracting chamber  805 . When port R is open, fluid is recirculated to the pump rams  821  through recirculation conduit  900 . This is useful when the hi-pressure storage  822  is full. When all three of the ports are closed (port X), the pump rams  821  refill the hi-pressure storage  822  from the vent reservoir. The manifold also has two vent ports: vent  1  and vent  2 . When vent  1  is open, fluid bleeds out of the telescoping chamber  804 . When vent  2  is open, fluid bleeds out of the retracting chamber  805 . Through the manifold, the vents are connected to a vent reservoir that is also connected to the recirculation conduit  900 . A schematically shown balance chamber  901 , which may be identical with (or in direct fluid communication with) balance chamber  833  shown in  FIG. 8 , is connected to the recirculation conduit  900 . As shown in  FIG. 9B , the ports and vents are electrically controlled so that the vents are logically tied to the ports. Specifically, when port  1  is open, vent  2  is open. When port  2  is open, vent  1  is open. When port R is open, vents  1  and  2  are open. When all three ports are closed, vents  1  and  2  are open. A volume balance preferably is maintained during operation, wherein the volumes of telescoping chamber  804  and retracting chamber  805  added together remain constant, and volumes of hi-pressure storage chamber  822  and balance chamber  833  added together remain constant, and those two aggregate volumes, themselves added together, remains constant (allowing however for volume changes due to slight seal leakage over time and bulk compression/expansion of the hydraulic oil under ambient pressure and temperature conditions. The electrical controls may be actuated via the communications media  170  by the surface real-time processor  175 , which provides dynamic control of the properties of the bumper sub  800 . 
   An example of a torque modulator  1605  is a dynamic clutch. A dynamic clutch could be employed in the BHA or elsewhere in the drill string to help mitigate torsional dynamic behaviors of the string typically evolving from the bit or other element of the string instantaneously being slowed or stopped from its normal rotation rate. The clutch could be used in conjunction with a rotary steerable device or a mud motor. Gear-type clutches are known for use in drilling tools for engaging and disengaging rotational coupling between drill string members. One embodiment of the dynamic clutch preferably employs friction plates, which may be held in engagement by an electrical actuator or electrical over hydraulic actuator. Control or modulation of the electrical signal by the surface real-time processor  175  via the high-speed communications media  170  allows controlled or modulated release of engagement and re-engagement, de-coupling and then re-coupling the rotary engine of the drill string above the clutch, to the string, or BHA below the clutch. 
     FIG. 10  is a cross-sectional, side view of an embodiment of a dynamic clutch sub  1000  having a center line  1001 . The sub has a box connector  1002  at the top for making up to pipe string. A housing  1003  is threaded onto the exterior of the box connector  1002  wherein o-ring seals  1004  complete the connection. An electronics insert  1005  may be connected to the interior of the box connector  1002 . A printed circuit board  1006  may be housed within the electronics insert  1005 . The printed circuit board may be controllable via the communications media  170  by the surface real-time processor  175  using arrangements such as those shown in  FIGS. 2 and 3 . The printed circuit board  1006  may include one or more sensors as discussed, preferably for sensing rotational orientation, rotary speed, tangential accelerations, or torsional strains, as may be useful in control of a dynamic clutch sub. A balance chamber  1010  may be defined between the box connector  1002  and the housing  1003 . The balance chamber  1010  may be split into a mud fluid section in the top and a hydraulic fluid section in the bottom by a balance piston  1011 . The upper section of the balance chamber  1010  fluidly communicates with the exterior (annulus between the sub and casing, not shown) of the sub  1000  via balance port  1012 . Hydraulic fluid may be injected into the balance chamber  1010  through a fill plug  1013 . The balance chamber  1010  may also have a spring in the upper mud portion to bias the balance piston  1011 . 
   A rotating mandrel  1015  may be made up to the inside of the box connector  1002  and the housing  1003 . The rotating mandrel  1015  may have two parts, a friction section  1016  and a pin connector  1017 . The friction section  1016  and the pin connector  1017  may be threaded into each other and o-rings  1018  may complete the connection. A friction plate  1019  may have a ring-like structure and may be attached to an upward facing surface of the friction section  1016 . A radial bearing  1020  may be positioned between the friction section  1016  and the box connector  1002 . A thrust bearing  1022  may be positioned between the bottom end of the friction section  1016  and a housing flange  1021  that extends radially inward from a lower end of the housing  1003 . A radial bearing  1023  may be positioned between pin connector  1017  and the housing flange  1021 . A thrust bearing  1024  may be positioned between an upward face of the pin connector  1017  and the housing flange  1021 . 
   A bearing chamber  1025  may be defined between the housing  1003 , the box connector  1002 , and the rotating mandrel  1015 . An upper end of the bearing chamber  1025  may be sealed by rotary seals  1026  between the friction section  1016  and the box connector  1002 . A lower end of the bearing chamber  1025  may be sealed by rotary seals  1027  between the pin connector  1017  and the housing  1003 . The bearing chamber  1025  may be fluidly connected to the balance chamber  1010  via gap  1028 . The balance chamber  1010  enables hydraulic fluid to be maintained in and around the bearing regardless of the pressure being generated on the exterior of the sub  1000 . 
   An array of solenoids  1007  may be connected to the bottom of the box connector  1002 . A communication/power bus  1008  communicates control signals between the printed circuit board  1006  and the array of solenoids  1007 , and in one embodiment also communicates rotary electrical interface  1030  between the opposing faces of the box connector  1002  structure and the rotating mandrel  1015 . This rotary electrical interface may comprise simply a relative rotation sensor. In other embodiments, the communication power bus  1008  also extends through this rotary electrical interface  1030  into the rotating mandrel  1015  for connection to a sensor set (not shown) which may preferably sense similar parameters to those named earlier which may be included with printed circuit board  1006 , but here such parameters associated with the rotating mandrel. And this extension of communication/power bus  1008  may further extend along the mandrel  1015  and connect to other drill string elements connected to the bottom of the sub. In such embodiments the rotary electrical interface  1030  may comprise an inductive type or brush type interface. An array of pistons  1009  may extend from the array of solenoids  1007  and have clutch plates  1014  attached thereto. The clutch plates  1014  may be positioned opposite the friction plate  1019  so that when the array of solenoids  1007  is engaged, the clutch plates  1014  extend to contact and press against the friction plate  1019 . This action restricts relative rotational movement between the rotating mandrel  1015  and the box connector  1002 . A return spring  1029  may be positioned between a flange on the housing  1003  and the clutch plates  1014  to release the clutch plates  1014  from the friction plate  1019  when the array of solenoids  1007  is deactivated. The clutch plates  1014  may also engage in a spline  1028  between the clutch plates  1014  and the housing  1003  to prevent rotational movement while allowing axial movement. 
   The amount of torque translated from one side of the dynamic clutch sub to the other depends on the control signals applied to the array of solenoids  1007 . The control signals may be provided by an independent controller on PCB  1006  or may be provided through the PCB  1006  and the communications media  170  by the surface real-time processor  175 . A set or series of clutch and friction plates operating together (not shown) may alternatively be employed, to increase the contact area and thereby reduce the contact pressure requirement in achieving the mechanical torque capacity required. In another embodiment (not shown), the return springs  1029  may be positioned so as to create a default contact condition between clutch plates  1014  and friction plates  1019 , thus allowing for slippage and relative rotation only when the solenoids are activated. 
   An example of the utility of a dynamic clutch arises when a bit engages a particularly hard formation top and briefly stalls. Without a clutch, and recognizing that the drill string is being rotated from perhaps 15,000 feet away, this brief stall would create a drill string wind-up event, which, depending upon the duration of the stall, would represent energy stored from a part of a revolution to several revolutions of angular perturbation. The resultant stored energy, upon release, would potentially overspeed the bit (with possible damage resulting), and a torsional “unwind” wave would be launched up the drill pipe. These torsional waves could contribute to overtightening and/or loosening pipe connections, which could lead to failure. A conventional torque limiter would mitigate this to an extent, and the clutch would slip or ratchet until actions are taken by the driller to reset (e.g. pick up off bottom). An electronic feedback control system provides a deliberate and calibrated release of the torque with torque transmittal through the clutch being maintained through the event (while allowing for rotational slipping) and allowing for the bit to resume rotation on its own, or perhaps under a controlled increase in torque transmitted through the clutch. A more sophisticated control process might include an automated command to the rotary table, the draw works, or a downhole dynamic bumper sub, to cause a release in weight on bit. 
   Another example of the clutch&#39;s utility is in the modulation of the speed of the bit. In certain circumstances (e.g. the tri-cone lobe effect as noted above) the prevailing bit RPM may initiate a resonant condition. In such circumstances it might make sense to deliberately vary the RPM over time, or even modulate the instantaneous RPM for variations within the duration of a single revolution. The clutch could likewise be engaged to accomplish this. 
   Yet another type of energy modulator is a vibrator sub. Drill string tools are known which can electrically or mechanically excite vibrations in the drill string. For example, it is known to utilize a piezo-ceramic stack in an annular configuration to convert electrical power into vibrational energy, which is amplified via a spring/mass (“compliant element/tail mass”) system associated with that stack. In the current invention, such a system could be excited to a particular frequency or modulation scheme in a controlled manner with that controlled vibrational energy coupled into the drill string for the dynamic compensation or cancellation purposes of the invention. 
   Drill string tools are known which are driven by the mud flow and utilize simple spring and valve systems to create periodic impacts, which perturbations can be coupled axially and/or torsionally along the drill string. Such devices may be generically called fluid hammers. The current invention improves on this type of device. Whereas these vibration subs provide an impact periodicity which is related to the flow rate, the current invention can harness the energy of the flow and apply that energy as a controlled frequency torsional or axial output. One device would include a center slide hammer element (either a central sonde, or annular configuration) which has two stable states, up and down, depending upon the presence or absence of a particular pressure-drop inducing feature (i.e. a pilot), which itself can be activated or deactivated rapidly either via electric solenoid, or a hydraulic system controlled by electric solenoid. In transitioning from state to state, a pressure drop over the slide hammer element would cause it to slide up or down. With the pilot mechanism frequency able to be controlled and modulated, a controlled hammer vibration can be established, and this dynamic hammer can be utilized to inject energy into the drill pipe dynamic system in a controlled manner for the dynamic compensation or cancellation purposes of the invention. 
   Establishing mechanical vibrations in the drill string will be dependent upon the mass, stiffness, degrees of freedom, and boundary conditions of the local drill string dynamic system. The local dynamic system characteristics may be modeled generically, and as part of a real time process the system could be periodically characterized by analyzing the system dynamic response (via several strategically placed sensors) to particular known vibrational input frequencies, and developing or updating a local transfer function. The particular control inputs then for the dynamic compensation or cancellation purposes or other purposes under the invention would be tailored and controlled in real time recognizing the overall system dynamic response, not just the response of the vibration input device. 
   Referring to  FIG. 11 , an example vibrator sub  1100  is illustrated in cross-section with center line  1101 . A portion of a pin sub  1102  is also shown to which the vibrator sub  1100  is made up. The vibration sub  1100  has a housing  1103  made of two sections which are threaded together. The upper housing  1104  has a female thread into which male threads on the lower housing  1105  are threaded. O-ring seals  1106  complete the connection. An electronics insert  1107  may be positioned between the upper housing  1104  and the lower housing  1105 , and may be clamped in and keyed to the upper housing  1104  via locking ring  1109 . A printed circuit board  1108  may be contained within the electronics insert  1107 . A connector  1112  extends from the pin sub  1102  for electrical communication with the electronics insert  1107 . The printed circuit board may be controllable via the communications media  170  by the surface real-time processor  175  using arrangements such as those shown in  FIGS. 2 and 3 . The printed circuit board may include one or more of the sensors discussed, and may preferably include an axial vibration sensor or accelerometer useful for control of the vibrator sub. A balance chamber  1110  may be defined between upper housing  1104 , lower housing  1105 , and electronics insert  1107 . The balance chamber  1110  may be divided into a mud portion above and a hydraulic portion below by a balance piston  1111 . The mud portion of the balance chamber  1110  above the balance piston  1111  communicates with the borehole annulus mud via balance port  1112 . The oil side of the balance chamber  1110  below the balance piston  1111  communicates with the inner diameter of the vibration sub  1100  via balance port  1108 . Hydraulic fluid is inserted into the balance chamber  1110  through fill plug  1113 . 
   A mandrel  1114  may be made up within a lower housing  1105 . The upper portion of the mandrel  1114  is inserted between lower housing  1105  and electronics insert  1107 , wherein o-ring seals  1115  seal the connection between the mandrel  1114  and the electronics insert  1107 . A stack chamber  1116  may be defined between the lower housing  1105  and the mandrel  1114 . The stack chamber  1116  may be in fluid communication with the balance chamber  1110  via a gap  1117  between the mandrel  1114  and the lower housing  1105 . The two chambers may be in further fluid communication to the balance chamber  1110  (oil side) through port  1118  in an upper portion of the lower housing  1105 . 
   Within the stack chamber  1116 , an annular stack of piezo electric crystals  1119  may be secured to the mandrel  1114 . An annular tail mass  1120  may be positioned immediately on top of the piezo electric crystals  1119 . Tension bolts  1121  may extend through the tail mass  1120  and the piezo electric crystals  1119  and thread directly into the bottom of the stack chamber  1116  defined by the mandrel  1114 . The tension bolts  1121  keep the piezo electric crystals  1119  and tail mass  1120  in compression. An electrical communication/power bus  1122  extends from the electronics insert  1107  to the piezo electric crystals  1119 . 
   A spring chamber  1123  may also defined between the lower housing  1105  and the mandrel  1114 . A spring  1124  may be positioned within the spring chamber  1123  to engage the mandrel  1114  at the bottom and the lower housing  1105  at the top. The spring chamber  1123  may be sealed by o-ring seals  1125  at the bottom. The spring chamber  1123  may be in fluid communication with the stack chamber  1116  through a gap  1126  between the mandrel  1114  and the lower housing  1105 . A spline  1127  may be configured in the gap  1126  to prevent relative rotational movement between the mandrel  1114  and the lower housing  1105  while allowing relative movement in the axial direction. 
   An upper portion of the mandrel  1114  may have a notch  1128  for receiving multiple keys  1129  which extend from the lower housing  1105 . The keys may be secured in the lower housing  1105  by sealed plugs  1130 . The keys  1129  prevent rotation and retain the mandrel  1114  within the housing  1103  when the vibration sub  1100  is in tension. The vibration sub  1110  is placed in tension, for example, when pipe string is made up to the pin connector  1131  and suspended below the vibration sub  1100  and especially when the pipe string is being tripped in or out of the borehole. 
   The vibration sub  1100  may also include a mini-sensor set  1132 . The sensors of the sensor set  1132  are positioned in the exterior of the mandrel  1114  where the mandrel extends below the housing  1103 . The sensor set  1132  may be electrically connected to the communication/power bus  1122  by copper with a seal plug, and preferably includes the sensors as noted above that might be useful in monitoring and/or controlling the vibration sub. 
   As before, the characteristics of the dynamic vibration sub may be controlled via the circuit board  1108  and the communications media  170  by the surface real-time processor  175 . 
   Another type of energy modulator, shown in  FIG. 12  in cross-section with center line  1201 , is a dynamic bending sub which provides the ability to dynamically bend a limber collar. The dynamic bending sub  1200  includes a box connector  1202  and a pin connector  1240  for making up to pipe string. A power and communications connector  1204  may be included to allow connection of power and communication signals from the pin connector above in the drill string. In this embodiment, and generally for all the energy modulator embodiments disclosed herein, the power and communications signals received through the power and communications connector (here  1204 ) may be routed through the dynamic bending sub and to a connector at the pin end (here  1207 ) to provide the signals to the next lower drill pipe in the drill string. The dynamic bending sub  1200  may include an electronics insert  1206 , which may include a printed circuit board (“PCB”)  1208 . The PCB may be controllable through the communications media  170  by the surface real-time processor. The PCB may include one or more sensors useful in the monitoring or control of dynamic bending, including preferably an orthogonal pair of radial acceleration sensors. 
   The dynamic bending sub  1200  may be configured as a length of drill collar (for identification purposes herein identified as “drill pipe”  1210  into which cutouts  1212  around the diameter of the drill pipe  1210  have been cut. The cutouts  1212  make the dynamic bending sub  1200  more flexible or limber. Tension cables or rods  1214  may extend from near the box connector  1202  to near the pin connector  1240  at a predetermined number, preferably 4, locations around the diameter of the drill pipe  1210 . In one embodiment, the locations are equally spaced around the diameter of the drill pipe  1210 . In other embodiments the spacing is not equal. 
   Each tension cable or rod  1214  is preferably secured at one end with cross bolts  1216  within the body of the drill pipe  1210  and, in one embodiment, to a linear actuator  1218 , which is housed within the body of the drill pipe  1210 . In one embodiment (shown), the tension cables or rods  1214  run in the open above the cut-out  1212  diameter. In another embodiment (not shown), the tension cable or rods run in grooves cut axially along and just below the cut-out  1212  diameter. 
   The dynamic bending sub  1200  may also include one or more, preferably 4, sensors  1220  spaced around the diameter of the drill pipe  1210 . The sensors  1220  detect bending moments in the drill pipe  1210 , and may include, for example strain gauges. 
   Power and communications cables  1222  extend from the PCB  1208  to the sensors  1220  and to the linear actuators  1218  and provide a capability for the PCB, and in some embodiments the surface real-time processor  175  through the communications media, to receive signals from the sensors  1220  and commands to the linear actuators  1218 . 
   For example, it may be desirable to bend the dynamic bending sub  1200  along a plane that cuts through the drill pipe  1210  in a bending direction approximately half way between two of of four equally spaced tension cables or rods  1214 . In that case, the PCB would command the two linear actuators attached to the tension cables or rods  1214  on the bending direction side of the drill pipe  1210  to contract, generating additional tension in the tension cables or rods  1214  on that side of the drill pipe  1210 . The PCB would also command the two other linear actuators attached to the other tension cables or rods  1214  to extend, reducing the tension in the tension cables or rods  1214  on that side of the drill pipe  1210 . As a result, the dynamic bending sub  1200  would bend in the bending direction. 
   An alternative embodiment, also illustrated in  FIG. 12 , replaces the linear actuator  1218  with a cross-bolt  1224 . Thus, in this embodiment both ends of the tension cables or rods  1214  are secured within the drill pipe  1210 . The variation in tension in the tension cables or rods  1214  is provided by a number of rotary actuators with eccentric cams  1224 . The rotary actuators with eccentric cams  1224  include a fixed stator  1226  and a rotating rotor  1228 . The degree and rate of rotation of the rotor  1228  with respect to the stator  1226  may be controlled by the PCB through power and communications cables  1230 . The rotor  1228  engages a barrel cam  1232 , with an eccentric surface, mounted on bearings  1234  so the barrel cam  1232  turns as the rotor  1228  turns. A lateral push pin  1236  may be pressed against the eccentric surface of the barrel cam  1232  by a spring (not shown). The lateral push pin  1236  extends through the outside diameter of the drill pipe  1210 , with the penetration sealed by o-rings (not shown), and engages the tension cable or rod  1214 . Consequently, as the rotor  1228  turns, under control of the PCB  1208 , the cam  1232  turns causing the lateral push pin  1236  to ride along the eccentric surface of the cam  1232  and to move in and out against the tension cable or rod  1214 . By turning the rotor to a particular orientation, a particular amount of strain can be induced in the tension cable or rod  1214 . Further, by turning the rotor  1228  continuously the amount of strain induced in the tension cable or rod  1214  can be varied periodically. 
   In general, when tension is increased in a tension cable or rod  1214  on one side of the drill pipe  1210  tension may be decreased by a similar amount in the tension cable or rod  1214  on the opposite side of the drill pipe  1210 . 
   The axial motion modulator  505 , the torque modulator  605  and the flex modulator also provide the ability to deliberately create axial, torsional and flex perturbations in the drill string, and by doing so repeatedly, to establish controlled standing waves in the string. The first objective of such controlled perturbations or standing waves might be to precisely cancel perturbations or standing waves evolving from the drilling process which otherwise might be detrimental. Such detrimental standing waves may evolve from the bit/formation interaction as discussed above, from whirl, from the periodic impact of uncentralized pipe in an overgage hole, from mud motor nutation, and other sources. 
   In the case of standing waves, at least two sensors, and preferably more must be distributed along the drillstring. The outputs of these sensors are monitored as a function of time and upgoing and downgoing waves may preferably be separated out. Any stationary part (i.e., not upgoing and not downgoing) corresponds to standing wave along the drillstring axis. With appropriate sensors, these techniques can be applied to any kind of wave (e.g., torsional). 
   Additional applications for such techniques include maintaining the string in a more dynamic state relative to the borehole wall, which may reduce frictional drag and/or improve borehole quality. In some circumstances, deliberately modulating the bit speed and/or weight on bit may increase rate of penetration. 
   With real time monitoring by proximate sensors, resonant conditions may also be deliberately approached, enabling energy to accumulate in the dynamic system over multiple cycles for a controlled use which might require more energy than otherwise available. 
   The axial motion modulator  505 , the torque modulator  605 , and the vibration modulator can also be used to provide vibration isolation to critical downhole elements, such as, for example, a particle accelerator tube. In this case, a system of sensors situated on both sides of the element to be protected would be used to sense the drillstring dynamics and, via a downhole microprocessor and controller, modulate the motion of the package to be protected so as to effectively isolate it from the undesired drillstring motions. 
   The axial motion modulator  505 , the torque modulator  605 , the vibration sub and other controllable elements such as the rotary table and the top drive, can be characterized as “major controllable elements,” because they add, dampen or modulate kinetic energy in the drilling equipment. A different type of control can be provided by actions of “distributed control elements” positioned at distributed locations along the drill string which add, dampen or modulate other forms of energy, such as thermal, electromagnetic, light, acoustic, and other forms of energy. 
   Such actions fall generally in the category of changing the boundary conditions of the drill string. It is conventional to take actions with respect to the entire drill string to affect boundary conditions of a part of the drill string or all of the drill string. The apparatus and method illustrated in  FIGS. 2 and 3  allow the system to affect local boundary conditions by taking an action or actions with respect to one segment of the drill string, where a segment is an arbitrary portion of the drill string, without taking actions with respect to other segments of the drill string. 
   For example, radial actuators (e.g., integral with upsets every few pipe connections) may extend stabilizer blades, feet, or rollers to reduce the surface area in contact with the formation, and/or stabilize the string, and/or reduce friction. An example, shown in  FIG. 13 , shows a drill string  1305  pressed against the side of a borehole  1310  producing friction between the drill string and the borehole along that segment of the drill string. Controllable elements  1315  and  1320  are coupled to the drill string. When controllable elements  1315  and  1320  are activated, as shown in  FIG. 14 , they extend stabilizer blades, feet, or rollers. As a result, friction between the drill string and the borehole wall is reduced. Thus, actuating controllable elements  1315  and  1320  in that segment of the drill string changes a boundary condition (friction) of the drilling equipment in that segment, without the need for actuating controllable elements in other segments of the drill string. 
   In addition to the controllable elements illustrated in  FIGS. 13 and 14 , similar devices may be employed to increase surface area in contact with the formation, drag, etc., for braking, damping whirl or bounce, controlling weight transfer to limit helical buckling, etc. 
   Further, circumferencial overlays or pads, essentially flush with the pipe outside diameter or upset, which in response to control signals emit energy in a distributed manner (i.e. at the particular locations of interest) into the local pipe, the drilling mud flowing in the annulus, the mud cake, or into formation boundaries. For example, acoustic energy, steady or variable, may be emitted to excite local particles and reduce drag, free sticking pipe, etc. Heat energy may be emitted for the same purposes, for example, deliberately causing local phase changes (e.g. gas bubbles) in the drilling mud or in the formation for these purposes. Given the significant hydrostatic pressure, and the limited and localized heat energy that would be applied, the bubbles would quickly collapse and therefore would not represent a kick. This technique however would preferably be used with care, especially when drilling at or below balance, so as to not invite formation fluid influx which could then evolve to a kick situation. Even more heat energy might be applied to seal the formation in particularly difficult zones, which has the effect of improving borehole quality. 
   Further energy may be emitted from the drill string to affect a property of a component of one of the annulus drilling fluid, the mud cake, the borehole wall, and the near-borehole invaded zone. Further, the energy emission may cause the initiation, acceleration, deceleration, and arresting, of a reaction involving said component. For example, the energy emission may cause a chemical reaction. Alternatively, the emission may cause a physical reaction, such as a change in physical structure, e.g. more or less agglomeration, crystallization, suspension, cementation, etc. The energy emission may, for example, accelerate the reaction of an epoxy component circulated with the drilling fluid. 
   The energy emission may cause the extension of mechanical feet, rollers, or stabilizer blades in order to change a boundary condition of the drill string. For example, the drill string may be in contact with the borehole so that its transmissions of axial, torsional, or bending waves are damped and it is limited in its degrees of freedom. An extension of mechanical feet, rollers, or stabilizer blades has the capability of improving those circumstances. 
   An example heat energy modulator  1500 , shown in  FIGS. 15A and 15B , includes a joint of drill pipe or a sub  1502  with an elongated box end  1504 . A clam-shell heater jacket  1506  is fastened by fasteners  1508  to the outside diameter of the elongated box end  1504 . An optional insulating coating  1510  separates the heater jacket  1506  from the elongated box end  1504 . 
   Further, circumferencial overlays or pads, essentially flush with the pipe outside diameter or upset, respond to control signals by emitting energy in a distributed manner (i.e. at the particular locations of interest) into the local pipe, the drilling mud flowing in the annulus, the mud cake, or into formation boundaries. For example, acoustic energy, steady or variable, may be emitted to excite local particles and reduce drag, free sticking pipe, etc. Heat energy may be emitted for the same purposes, for example, deliberately causing local phase changes (e.g. gas bubbles) in the drilling mud or in the formation for these purposes. Given the significant hydrostatic pressure, and the limited and localized heat energy that would be applied, the bubbles would quickly collapse and therefore would not represent a kick. This technique however would preferably be used with care, especially when drilling at or below balance, so as to not invite formation fluid influx which could then evolve to a kick situation. Even more heat energy might be applied to seal the formation in particularly difficult zones, which has the effect of improving borehole quality. 
   The heater jacket  1506  may include a burner element  1522 , which may be a resistive element that heats up when electric current passes through it. The burner element  1522  is activated by the PCB  1518  via control cables  1524  through connectors  1526 . 
   The burner element  1522  may be encased in a thermally conductive hard material  1528  which can withstand the downhole environment and can conduct heat from the heater element  1522 . The thermally conductive hard material  1528  may be embedded in a thermally insulative substrate, which is a relatively insulative ceramic “dish”  1530  containing a high temperature, highly insulative fiber and epoxy system molded into place to fill all voids in the portion of the heater jacket  1506  where it resides. The optional insulating coating  1510  underlies the insulative dish  1530 . 
   As can be seen, the amount of heat generated by the heat energy modulator  1500  is under the control of its electronics package, which can be controlled by the surface real-time processor  175  in the arrangement shown in  FIG. 2  or as part of a network in the arrangement shown in  FIG. 3 . One or more sensors which preferably include temperature sensors (not shown) may be included within the PCB, and temperature sensors preferably also may be integrated with the burner element  1522 , the thermally conductive hard material  1528 , and/or on the pipe exterior somewhat removed from the heat source. Several of such sensors may preferably be used to monitor the temperature and local temperature rise associated with the heat energy modulator, and for purposes of control. 
   Another embodiment of a heat energy modulator, illustrated in  FIG. 16 , is incorporated in a stabilizer sub  1600 . The stabilizer sub  1600  includes blades  1602  spaced around its outside diameter. In  FIG. 16 , one of the stabilizer blades  1602  is shown in a perspective view and the other is shown in cross-section. The stabilizer sub  1600  may include an electronics package  1604 , sealed by o-rings  1605 , which includes a PCB  1606 . The electronics package  1604  and the PCB  1606  communicate with other elements of the drill string, and in some cases the surface real-time processor  175  via the communications media  170 , through connector  1608 . Typically, while the stabilizer sub  1600  may include more than one electronics package  1604 , it only includes a single connector  1608 , although more than one connector is within the scope of the invention. One or all of the blades  1602  include heating elements  1620  which are protected as described above with respect to  FIG. 15 , by a thermally conductive hard material  1610  and encased by a fiber and epoxy system  1612  molded into place on a insulative ceramic base  1614 , which is optionally separated from the stabilizer blade by a insulative coating  1616 . The thermally conductive hard metal may be covered by an optional CVD diamond overlay. The heating element  1620  is connected to the PCB by cables  1618 . In this way, the PCB, can control the current flowing through, and thus the heat produced by, the heating element  1604 . One or more sensors, preferably temperature sensors (not shown) may be incorporated into this structure in a similar manner as discussed in the previous heat energy modulator embodiment, for similar purposes. 
   As can be seen, the amount of heat generated by the heat energy modulator shown in  FIG. 16  is under the control of its electronics package, which can be controlled by the surface real-time processor  175  in the arrangement shown in  FIG. 2  or as part of a network in the arrangement shown in  FIG. 3 . 
   An embodiment of an sonic energy modulator  1700  that generates sonic energy to affect a change in a local boundary condition, illustrated in  FIG. 17 , includes sonic excitation buttons  1702  mounted in the box end  1704  of a joint of drill pipe  1706 . In  FIG. 17 , three of the sonic excitation buttons  1702  are shown in perspective view and a fourth is shown in cross-section. The sonic energy modulator  1700  includes an electronics package  1708 , sealed by o-rings  1709 , which includes a PCB  1710 . The electronics package  1708  and the PCB  1710  communicate with other elements of the drill string, and in some cases the surface real-time processor  175  via the communications media  170 , through connector  1712 . A set of power and communications cables  1714  connect the electronics package  1708  with the sonic excitation buttons  1702 , providing them with power and excitation signals. Each sonic excitation button excitation button includes a Belleville spring support  1716  inserted into a cavity in the box end  1704  of the joint of drill pipe  1706 . A piezo electric crystal is inserted into the cavity over the spring support  1716  and is connected to the power and communications cables  1714 . A bolt with a spring washer under its head  1718  secures the sonic excitation button  1702  in position. 
   As can be seen, the amount of sonic energy generated by the sonic energy modulator  1700  is under the control of its electronics package, which can be controlled by the surface real-time processor  175  in the arrangement shown in  FIG. 2  or as part of a network in the arrangement shown in  FIG. 3 . Sensors (not shown) may be integrated with the buttons  1702 , or provided independently of but proximate to the buttons, which may be useful in monitoring and control of the sonic energy modulator. 
   An electrical potential, field, or field reversals might be applied to alleviate sticking and balling and other similar issues along the string associated with polar mud particle. 
   Heat energy, electrical potential, and/or particular frequency light energy, might be applied to activate particular mud additives, whether entrained in the mud or already built up in the borehole mud cake, to change the mud or mud cake properties, e.g. reduce friction, increase yield strength and carrying capacity, and/or to change viscosity. 
   The operation of the system, illustrated in  FIG. 18 , is generally similar whether the system is configured as shown in  FIG. 2  or as shown in  FIG. 3 . If the system is configured as shown in  FIG. 2 , the operation of the system may be directed by the surface real-time processor. If the system is configured as shown in  FIG. 3 , the operation of the system may be directed by the autonomous network of controllers  315 , perhaps with some assistance from the surface real-time processor  175 . In one embodiment, data is acquired from one or more sensor modules  210 ,  310  (which may be packaged integrally with, or independent of, particular actuator modules) at the prevailing controlled drilling parameter set (i.e. WOB and rotary speed, and/or the controlled periodic or non-periodic actuation of one or more of the energy modulators  205 ,  305 ) (block  1805 ) and stored in a data store of acquired data sets  1810 . 
   Optionally, but preferably, one (or more, preferably one at a time) of the prevailed controlled drilling parameter set is modified (block  1815 ) and a second data set is acquired from one or more of the sensors reflective of the adjusted parameter set (block  1820 ). That is, the drilling equipment operating parameters are modified by, for example, changing the WOB, modifying the rotary speed or varying any energy that is being added to or removed from the system by an energy modulators. The second data set may be stored in the acquired data sets data store  1810 . 
   Data from the two data sets stored in the acquired data sets data store  1810 , if available, may be processed, optionally in context of an old model of the drill string and drilling process  1825 , to create a new model of the drill string and drilling process  1830  (block  1835 ). Both the old model and the new model may include a transfer function description of the drill string and drilling process. 
   The system may take a desired goal  1840  (e.g. reduced non-constructive drill string behavior, or initiation of a particular drill string behavior believed beneficial to the drilling process) provided by and operator or from another process, and iteratively or analytically determines which energy modulators to activate and the parameters associated with that activation (block  1845 ). The system then initiates or adjusts actuation of one or more of the energy modulators accordingly (block  1850 ). The system then optionally repeat this sequence periodically, and/or when a behavior appears to change outside of thresholds, etc (block  1855 ). 
   The present invention is therefore well-adapted to carry out the objects and attain the ends mentioned, as well as those that are inherent therein. While the invention has been depicted, described and is defined by references to examples of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alteration and equivalents in form and function, as will occur to those ordinarily skilled in the art having the benefit of this disclosure. The depicted and described examples are not exhaustive of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.