Patent Publication Number: US-6981561-B2

Title: Downhole cutting mill

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
   This application is a continuation-in-part of U.S. patent application Ser. No. 10/251,138 filed Sep. 20, 2002, now abandoned, which takes priority from U.S. provisional patent application Ser. No. 60/323,803 filed on Sep. 20, 2001, titled “Active Controlled Bottomhole Pressure System and Method.” 

   FIELD OF THE INVENTION 
   This invention relates generally to oilfield wellbore drilling systems and more particularly to drilling systems that utilize active control of bottomhole pressure or equivalent circulating density during drilling of the wellbores. 
   BACKGROUND OF THE ART 
   Oilfield wellbores are drilled by rotating a drill bit conveyed into the wellbore by a drill string. The drill string includes a drill pipe (tubing) that has at its bottom end a drilling assembly (also referred to as the “bottomhole assembly” or “BHA”) that carries the drill bit for drilling the wellbore. The drill pipe is made of jointed pipes. Alternatively, coiled tubing may be utilized to carry the drilling of assembly. The drilling assembly usually includes a drilling motor or a “mud motor” that rotates the drill bit. The drilling assembly also includes a variety of sensors for taking measurements of a variety of drilling, formation and BHA parameters. A suitable drilling fluid (commonly referred to as the “mud”) is supplied or pumped under pressure from a source at the surface down the tubing. The drilling fluid drives the mud motor and then discharges at the bottom of the drill bit. The drilling fluid returns uphole via the annulus between the drill string and the wellbore inside and carries with it pieces of formation (commonly referred to as the “cuttings”) cut or produced by the drill bit in drilling the wellbore. 
   For drilling wellbores under water (referred to in the industry as “offshore” or “subsea” drilling) tubing is provided at a work station (located on a vessel or platform). One or more tubing injectors or rigs are used to move the tubing into and out of the wellbore. In riser-type drilling, a riser, which is formed by joining sections of casing or pipe, is deployed between the drilling vessel and the wellhead equipment at the sea bottom and is utilized to guide the tubing to the wellhead. The riser also serves as a conduit for fluid returning from the wellhead to the sea surface. 
   During drilling, the drilling operator attempts to carefully control the fluid density at the surface so as to control pressure in the wellbore, including the bottomhole pressure. Typically, the operator maintains the hydrostatic pressure of the drilling fluid in the wellbore above the formation or pore pressure to avoid well blow-out. The density of the drilling fluid and the fluid flow rate largely determine the effectiveness of the drilling fluid to carry the cuttings to the surface. One important downhole parameter controlled during drilling is the bottomhole pressure, which in turn controls the equivalent circulating density (“ECD”) of the fluid at the wellbore bottom. 
   This term, ECD, describes the condition that exists when the drilling mud in the well is circulated. The friction pressure caused by the fluid circulating through the open hole and the casing(s) on its way back to the surface, causes an increase in the pressure profile along this path that is different from the pressure profile when the well is in a static condition (i.e., not circulating). In addition to the increase in pressure while circulating, there is an additional increase in pressure while drilling due to the introduction of drill solids into the fluid. This negative effect of the increase in pressure along the annulus of the well is an increase of the pressure which can fracture the formation at the shoe of the last casing. This can reduce the amount of hole that can be drilled before having to set an additional casing. In addition, the rate of circulation that can be achieved is also limited. Also, due to this circulating pressure increase, the ability to clean the hole is severely restricted. This condition is exacerbated when drilling an offshore well. In offshore wells, the difference between the fracture pressures in the shallow sections of the well and the pore pressures of the deeper sections is considerably smaller compared to on shore wellbores. This is due to the seawater gradient versus the gradient that would exist if there were soil overburden for the same depth. 
   In some drilling applications, it is desired to drill the wellbore at at-balance condition or at under-balanced condition. The term at-balance means that the pressure in the wellbore is maintained at or near the formation pressure. The under-balanced condition means that the wellbore pressure is below the formation pressure. These two conditions are desirable because the drilling fluid under such conditions does not penetrate into the formation, thereby leaving the formation virgin for performing formation evaluation tests and measurements. In order to be able to drill a well to a total wellbore depth at the bottomhole, ECD must be reduced or controlled. In subsea wells, one approach is to use a mud-filled riser to form a subsea fluid circulation system utilizing the tubing, BHA, the annulus between the tubing and the wellbore and the mud filled riser, and then inject gas (or some other low density liquid) in the primary drilling fluid (typically in the annulus adjacent the BHA) to reduce the density of fluid downstream (i.e., in the remainder of the fluid circulation system). This so-called “dual density” approach is often referred to as drilling with compressible fluids. 
   Another method for changing the density gradient in a deepwater return fluid path has been proposed, but not used in practical application. This approach proposes to use a tank, such as an elastic bag, at the sea floor for receiving return fluid from the wellbore annulus and holding it at the hydrostatic pressure of the water at the sea floor. Independent of the flow in the annulus, a separate return line connected to the sea floor storage tank and a subsea lifting pump delivers the return fluid to the surface. Although this technique (which is referred to as “dual gradient” drilling) would use a single fluid, it would also require a discontinuity in the hydraulic gradient line between the sea floor storage tank and the subsea lifting pump. This requires close monitoring and control of the pressure at the subsea storage tank, subsea hydrostatic water pressure, subsea lifting pump operation and the surface pump delivering drilling fluids under pressure into the tubing for flow downhole. The level of complexity of the required subsea instrumentation and controls as well as the difficulty of deployment of the system has delayed (if not altogether prevented) the practical application of the “dual gradient” system. 
   Another approach is described in U.S. patent application Ser. No. 09/353,275, filed on Jul. 14, 1999 and assigned to the assignee of the present application. The U.S. patent application Ser. No. 09/353,275 is incorporated herein by reference in its entirety. One embodiment of this application describes a riser less system wherein a centrifugal pump in a separate return line controls the fluid flow to the surface and thus the equivalent circulating density. 
   The present invention provides a wellbore system wherein the bottomhole pressure and hence the equivalent circulating density is controlled by creating a pressure differential at a selected location in the return fluid path with an active pressure differential device to reduce or control the bottomhole pressure. The present system is relatively easy to incorporate in new and existing systems. 
   SUMMARY OF THE INVENTION 
   The present invention provides wellbore systems for performing downhole wellbore operations for both land and offshore wellbores. Such drilling systems include a rig that moves an umbilical (e.g., drill string) into and out of the wellbore. A bottomhole assembly, carrying the drill bit, is attached to the bottom end of the drill string. A well control assembly or equipment on the well receives the bottomhole assembly and the tubing. A drilling fluid system supplies a drilling fluid into the tubing, which discharges at the drill bit and returns to the well control equipment carrying the drill cuttings via the annulus between the drill string and the wellbore. A riser dispersed between the wellhead equipment and the surface guides the drill string and provides a conduit for moving the returning fluid to the surface. 
   In one embodiment of the present invention, an active pressure differential device moves in the wellbore as the drill string is moved. In an alternative embodiment, the active differential pressure device is attached to the wellbore inside or wall and remains stationary relative to the wellbore during drilling. The device is operated during drilling, i.e., when the drilling fluid is circulating through the wellbore, to create a pressure differential across the device. This pressure differential alters the pressure on the wellbore below or downhole of the device. The device may be controlled to reduce the bottomhole pressure by a certain amount, to maintain the bottomhole pressure at a certain value, or within a certain range. By severing or restricting the flow through the device, the bottomhole pressure may be increased. 
   The system also includes downhole devices for performing a variety of functions. Exemplary downhole devices include devices that control the drilling flow rate and flow paths. For example, the system can include one or more flow-control devices that can stop the flow of the fluid in the drill string and/or the annulus. Such flow-control devices can be configured to direct fluid in drill string into the annulus and/or bypass return fluid around the APD device. Another exemplary downhole device can be configured for processing the cuttings (e.g., reduction of cutting size) and other debris flowing in the annulus. For example, a comminution device can be disposed in the annulus upstream of the APD device. 
   In a preferred embodiment, sensors communicate with a controller via a telemetry system to maintain the wellbore pressure at a zone of interest at a selected pressure or range of pressures. The sensors are strategically positioned throughout the system to provide information or data relating to one or more selected parameters of interest such as drilling parameters, drilling assembly or BHA parameters, and formation or formation evaluation parameters. The controller for suitable for drilling operations preferably includes programs for maintaining the wellbore pressure at zone at under-balance condition, at at-balance condition or at over-balanced condition. The controller may be programmed to activate downhole devices according to programmed instructions or upon the occurrence of a particular condition. 
   Exemplary configurations for the APD Device and associated drive includes a moineau-type pump coupled to positive displacement motor/drive via a shaft assembly. Another exemplary configuration includes a turbine drive coupled to a centrifugal-type pump via a shaft assembly. Preferably, a high-pressure seal separates a supply fluid flowing through the motor from a return fluid flowing through the pump. In a preferred embodiment, the seal is configured to bear either or both of radial and axial (thrust) forces. 
   In still other configurations, a positive displacement motor can drive an intermediate device such as a hydraulic motor, which drives the APD Device. Alternatively, a jet pump can be used, which can eliminate the need for a drive/motor. Moreover, pumps incorporating one or more pistons, such as hammer pumps, may also be suitable for certain applications. In still other configurations, the APD Device can be driven by an electric motor. The electric motor can be positioned external to a drill string or formed integral with a drill string. In a preferred arrangement, varying the speed of the electrical motor directly controls the speed of the rotor in the APD device, and thus the pressure differential across the APD Device. 
   Bypass devices are provided to allow fluid circulation in the wellbore during tripping of the system, to control the operating set points of the APD Device and/or associated drive/motor, and to provide a discharge mechanism to relieve fluid pressure. For examples, the bypass devices can selectively channel fluid around the motor/drive and the APD Device and selectively discharge drilling fluid from the drill string into the annulus. In one arrangement, the bypass device for the pump can also function as a particle bypass line for the APD device. Alternatively, a separate particle bypass can be used in addition to the pump bypass for such a function. Additionally, an annular seal (not shown) in certain embodiments can be disposed around the APD device to enable a pressure differential across the APD Device. 
   Examples of the more important features of the invention have been summarized (albeit rather broadly) in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For detailed understanding of the present invention, reference should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawing: 
       FIG. 1A  is a schematic illustration of one embodiment of a system using an active pressure differential device to manage pressure in a predetermined wellbore location; 
       FIG. 1B  graphically illustrates the effect of an operating active pressure differential device upon the pressure at a predetermined wellbore location; 
       FIG. 2  is a schematic elevation view of  FIG. 1A  after the drill string and the active pressure differential device have moved a certain distance in the earth formation from the location shown in  FIG. 1A ; 
       FIG. 3  is a schematic elevation view of an alternative embodiment of the wellbore system wherein the active pressure differential device is attached to the wellbore inside; 
       FIGS. 4A–D  are schematic illustrations of one embodiment of an arrangement according to the present invention wherein a positive displacement motor is coupled to a positive displacement pump (the APD Device); 
       FIGS. 5A and 5B  are schematic illustrations of one embodiment of an arrangement according to the present invention wherein a turbine drive is coupled to a centrifugal pump (the APD Device); 
       FIG. 6A  is a schematic illustration of an embodiment of an arrangement according to the present invention wherein an electric motor disposed on the outside of a drill string is coupled to an APD Device; 
       FIG. 6B  is a schematic illustration of an embodiment of an arrangement according to the present invention wherein an electric motor disposed within a drill string is coupled to an APD Device; 
       FIG. 7  schematically illustrates one embodiment of a comminution device made in accordance with the teachings of the present invention; 
       FIG. 8  schematically illustrates an exemplary non rotating chamber part for the  FIG. 7  embodiment; 
       FIG. 9  schematically illustrates an exemplary cutting head for the  FIG. 7  embodiment; 
       FIG. 10  schematically illustrates another exemplary cutting head for the  FIG. 7  embodiment; and 
       FIG. 11  schematically illustrated another embodiment of a comminution device made in accordance with the teachings of the present invention. 
   

   DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 
   Referring initially to  FIG. 1A , there is schematically illustrated a system for performing one or more operations related to the construction, logging, completion or work-over of a hydrocarbon producing well. In particular,  FIG. 1A  shows a schematic elevation view of one embodiment of a wellbore drilling system  100  for drilling wellbore  90  using conventional drilling fluid circulation. The drilling system  100  is a rig for land wells and includes a drilling platform  101 , which may be a drill ship or another suitable surface workstation such as a floating platform or a semi-submersible for offshore wells. For offshore operations, additional known equipment such as a riser and subsea wellhead will typically be used. To drill a wellbore  90 , well control equipment  125  (also referred to as the wellhead equipment) is placed above the wellbore  90 . The wellhead equipment  125  includes a blow-out-preventer stack  126  and a lubricator (not shown) with its associated flow control. 
   This system  100  further includes a well tool such as a drilling assembly or a bottomhole assembly (“BHA”)  135  at the bottom of a suitable umbilical such as drill string or tubing  121  (such terms will be used interchangeably). In a preferred embodiment, the BHA  135  includes a drill bit  130  adapted to disintegrate rock and earth. The bit can be rotated by a surface rotary drive or a motor using pressurized fluid (e.g., mud motor) or an electrically driven motor. The tubing  121  can be formed partially or fully of drill pipe, metal or composite coiled tubing, liner, casing or other known members. Additionally, the tubing  121  can include data and power transmission carriers such fluid conduits, fiber optics, and metal conductors. Conventionally, the tubing  121  is placed at the drilling platform  101 . To drill the wellbore  90 , the BHA  135  is conveyed from the drilling platform  101  to the wellhead equipment  125  and then inserted into the wellbore  90 . The tubing  121  is moved into and out of the wellbore  90  by a suitable tubing injection system. 
   During drilling, a drilling fluid from a surface mud system  22  is pumped under pressure down the tubing  121  (a “supply fluid”). The mud system  22  includes a mud pit or supply source  26  and one or more pumps  28 . In one embodiment, the supply fluid operates a mud motor in the BHA  135 , which in turn rotates the drill bit  130 . The drill string  121  rotation can also be used to rotate the drill bit  130 , either in conjunction with or separately from the mud motor. The drill bit  130  disintegrates the formation (rock) into cuttings  147 . The drilling fluid leaving the drill bit travels uphole through the annulus  194  between the drill string  121  and the wellbore wall or inside  196 , carrying the drill cuttings  147  therewith (a “return fluid”). The return fluid discharges into a separator (not shown) that separates the cuttings  147  and other solids from the return fluid and discharges the clean fluid back into the mud pit  26 . As shown in  FIG. 1A , the clean mud is pumped through the tubing  121  while the mud with cuttings  147  returns to the surface via the annulus  194  up to the wellhead equipment  125 . 
   Once the well  90  has been drilled to a certain depth, casing  129  with a casing shoe  151  at the bottom is installed. The drilling is then continued to drill the well to a desired depth that will include one or more production sections, such as section  155 . The section below the casing shoe  151  may not be cased until it is desired to complete the well, which leaves the bottom section of the well as an open hole, as shown by numeral  156 . 
   As noted above, the present invention provides a drilling system for controlling bottomhole pressure at a zone of interest designated by the numeral  155  and thereby the ECD effect on the wellbore. In one embodiment of the present invention, to manage or control the pressure at the zone  155 , an active pressure differential device (“APD Device”)  170  is fluidicly coupled to return fluid downstream of the zone of interest  155 . The active pressure differential device is a device that is capable of creating a pressure differential “ΔP” across the device. This controlled pressure drop reduces the pressure upstream of the APD Device  170  and particularly in zone  155 . 
   The system  100  also includes downhole devices that separately or cooperatively perform one or more functions such as controlling the flow rate of the drilling fluid and controlling the flow paths of the drilling fluid. For example, the system  100  can include one or more flow-control devices that can stop the flow of the fluid in the drill string and/or the annulus  194 .  FIG. 1A  shows an exemplary flow-control device  173  that includes a device  174  that can block the fluid flow within the drill string  121  and a device  175  that blocks can block fluid flow through the annulus  194 . The device  173  can be activated when a particular condition occurs to insulate the well above and below the flow-control device  173 . For example, the flow-control device  173  may be activated to block fluid flow communication when drilling fluid circulation is stopped so as to isolate the sections above and below the device  173 , thereby maintaining the wellbore below the device  173  at or substantially at the pressure condition prior to the stopping of the fluid circulation. 
   The flow-control devices  174 ,  175  can also be configured to selectively control the flow path of the drilling fluid. For example, the flow-control device  174  in the drill pipe  121  can be configured to direct some or all of the fluid in drill string  121  into the annulus  194 . Moreover, one or both of the flow-control devices  174 ,  175  can be configured to bypass some or all of the return fluid around the APD device  170 . Such an arrangement may be useful, for instance, to assist in lifting cuttings to the surface. The flow-control device  173  may include check-valves, packers and any other suitable device. Such devices may automatically activate upon the occurrence of a particular event or condition. 
   The system  100  also includes downhole devices for processing the cuttings (e.g., reduction of cutting size) and other debris flowing in the annulus  194 . For example, a comminution device  176  can be disposed in the annulus  194  upstream of the APD device  170  to reduce the size of entrained cutting and other debris. The comminution device  176  can use known members such as blades, teeth, or rollers to crush, pulverize or otherwise disintegrate cuttings and debris entrained in the fluid flowing in the annulus  194 . The comminution device  176  can be operated by an electric motor, a hydraulic motor, by rotation of drill string or other suitable means. The comminution device  176  can also be integrated into the APD device  170 . For instance, if a multi-stage turbine is used as the APD device  170 , then the stages adjacent the inlet to the turbine can be replaced with blades adapted to cut or shear particles before they pass through the blades of the remaining turbine stages. 
   Sensors S 1-n  are strategically positioned throughout the system  100  to provide information or data relating to one or more selected parameters of interest (pressure, flow rate, temperature). In a preferred embodiment, the downhole devices and sensors S 1-n  communicate with a controller  180  via a telemetry system (not shown). Using data provided by the sensors S 1-n , the controller  180  maintains the wellbore pressure at zone  155  at a selected pressure or range of pressures. The controller  180  maintains the selected pressure by controlling the APD device  170  (e.g., adjusting amount of energy added to the return fluid line) and/or the downhole devices (e.g., adjusting flow rate through a restriction such as a valve). 
   When configured for drilling operations, the sensors S 1-n  provide measurements relating to a variety of drilling parameters, such as fluid pressure, fluid flow rate, rotational speed of pumps and like devices, temperature, weight-on bit, rate of penetration, etc., drilling assembly or BHA parameters, such as vibration, stick slip, RPM, inclination, direction, BHA location, etc. and formation or formation evaluation parameters commonly referred to as measurement-while-drilling parameters such as resistivity, acoustic, nuclear, NMR, etc. One preferred type of sensor is a pressure sensor for measuring pressure at one or more locations. Referring still to  FIG. 1A , pressure sensor P 1  provides pressure data in the BHA, sensor P 2  provides pressure data in the annulus, pressure sensor P 3  in the supply fluid, and pressure sensor P 4  provides pressure data at the surface. Other pressure sensors may be used to provide pressure data at any other desired place in the system  100 . Additionally, the system  100  includes fluid flow sensors such as sensor V that provides measurement of fluid flow at one or more places in the system. 
   Further, the status and condition of equipment as well as parameters relating to ambient conditions (e.g., pressure and other parameters listed above) in the system  100  can be monitored by sensors positioned throughout the system  100 : exemplary locations including at the surface (S 1 ), at the APD device  170  (S 2 ), at the wellhead equipment  125  (S 3 ), in the supply fluid (S 4 ), along the tubing  121  (S 5 ), at the well tool  135  (S 6 ), in the return fluid upstream of the APD device  170  (S 7 ), and in the return fluid downstream of the APD device  170  (S 8 ). It should be understood that other locations may also be used for the sensors S 1-n . 
   The controller  180  for suitable for drilling operations preferably includes programs for maintaining the wellbore pressure at zone  155  at under-balance condition, at at-balance condition or at over-balanced condition. The controller  180  includes one or more processors that process signals from the various sensors in the drilling assembly and also controls their operation. The data provided by these sensors S 1-n  and control signals transmitted by the controller  180  to control downhole devices such as devices  173 – 176  are communicated by a suitable two-way telemetry system (not shown). A separate processor may be used for each sensor or device. Each sensor may also have additional circuitry for its unique operations. The controller  180 , which may be either downhole or at the surface, is used herein in the generic sense for simplicity and ease of understanding and not as a limitation because the use and operation of such controllers is known in the art. The controller  180  preferably contains one or more microprocessors or micro-controllers for processing signals and data and for performing control functions, solid state memory units for storing programmed instructions, models (which may be interactive models) and data, and other necessary control circuits. The microprocessors control the operations of the various sensors, provide communication among the downhole sensors and provide two-way data and signal communication between the drilling assembly  30 , downhole devices such as devices  173 – 175  and the surface equipment via the two-way telemetry. In other embodiments, the controller  180  can be a hydro-mechanical device that incorporates known mechanisms (valves, biased members, linkages cooperating to actuate tools under, for example, preset conditions). 
   For convenience, a single controller  180  is shown. It should be understood, however, that a plurality of controllers  180  can also be used. For example, a downhole controller can be used to collect, process and transmit data to a surface controller, which further processes the data and transmits appropriate control signals downhole. Other variations for dividing data processing tasks and generating control signals can also be used. 
   In general, however, during operation, the controller  180  receives the information regarding a parameter of interest and adjusts one or more downhole devices and/or APD device  170  to provide the desired pressure or range or pressure in the vicinity of the zone of interest  155 . For example, the controller  180  can receive pressure information from one or more of the sensors (S 1 –S n ) in the system  100 . The controller  180  may control the APD Device  170  in response to one or more of: pressure, fluid flow, a formation characteristic, a wellbore characteristic and a fluid characteristic, a surface measured parameter or a parameter measured in the drill string. The controller  180  determines the ECD and adjusts the energy input to the APD device  170  to maintain the ECD at a desired or predetermined value or within a desired or predetermined range. The wellbore system  100  thus provides a closed loop system for controlling the ECD in response to one or more parameters of interest during drilling of a wellbore. This system is relatively simple and efficient and can be incorporated into new or existing drilling systems and readily adapted to support other well construction, completion, and work-over activities. 
   In the embodiment shown in  FIG. 1A , the APD Device  170  is shown as a turbine attached to the drill string  121  that operates within the annulus  194 . Other embodiments, described in further detail below can include centrifugal pumps, positive displacement pump, jet pumps and other like devices. During drilling, the APD Device  170  moves in the wellbore  90  along with the drill string  121 . The return fluid can flow through the APD Device  170  whether or not the turbine is operating. However, the APD Device  170 , when operated creates a differential pressure thereacross. 
   As described above, the system  100  in one embodiment includes a controller  180  that includes a memory and peripherals  184  for controlling the operation of the APD Device  170 , the devices  173 – 176 , and/or the bottomhole assembly  135 . In  FIG. 1A , the controller  180  is shown placed at the surface. It, however, may be located adjacent the APD Device  170 , in the BHA  135  or at any other suitable location. The controller  180  controls the APD Device to create a desired amount of ΔP across the device, which alters the bottomhole pressure accordingly. Alternatively, the controller  180  may be programmed to activate the flow-control device  173  (or other downhole devices) according to programmed instructions or upon the occurrence of a particular condition. Thus, the controller  180  can control the APD Device in response to sensor data regarding a parameter of interest, according to programmed instructions provided to said APD Device, or in response to instructions provided to said APD Device from a remote location. The controller  180  can, thus, operate autonomously or interactively. 
   During drilling, the controller  180  controls the operation of the APD Device to create a certain pressure differential across the device so as to alter the pressure on the formation or the bottomhole pressure. The controller  180  may be programmed to maintain the wellbore pressure at a value or range of values that provide an under-balance condition, an at-balance condition or an over-balanced condition. In one embodiment, the differential pressure may be altered by altering the speed of the APD Device. For instance, the bottomhole pressure may be maintained at a preselected value or within a selected range relative to a parameter of interest such as the formation pressure. The controller  180  may receive signals from one or more sensors in the system  100  and in response thereto control the operation of the APD Device to create the desired pressure differential. The controller  180  may contain pre-programmed instructions and autonomously control the APD Device or respond to signals received from another device that may be remotely located from the APD Device. 
     FIG. 1B  graphically illustrates the ECD control provided by the above-described embodiment of the present invention and references  FIG. 1A  for convenience.  FIG. 1A  shows the APD device  170  at a depth D 1  and a representative location in the wellbore in the vicinity of the well tool  30  at a lower depth D 2 .  FIG. 1B  provides a depth versus pressure graph having a first curve C 1  representative of a pressure gradient before operation of the system  100  and a second curve C 2  representative of a pressure gradients during operation of the system  100 . Curve C 3  represents a theoretical curve wherein the ECD condition is not present; i.e., when the well is static and not circulating and is free of drill cuttings. It will be seen that a target or selected pressure at depth D 2  under curve C 3  cannot be met with curve C 1 . Advantageously, the system  100  reduces the hydrostatic pressure at depth D 1  and thus shifts the pressure gradient as shown by curve C 3 , which can provide the desired predetermined pressure at depth D 2 . In most instances, this shift is roughly the pressure drop provided by the APD device  170 . 
     FIG. 2  shows the drill string after it has moved the distance “d” shown by t 1 –t 2 . Since the APD Device  170  is attached to the drill string  121 , the APD Device  170  also is shown moved by the distance d. 
   As noted earlier and shown in  FIG. 2 , an APD Device  170   a  may be attached to the wellbore in a manner that will allow the drill string  121  to move while the APD Device  170   a  remains at a fixed location.  FIG. 3  shows an embodiment wherein the APD Device is attached to the wellbore inside and is operated by a suitable device  172   a.  Thus, the APD device can be attached to a location stationary relative to said drill string such as a casing, a liner, the wellbore annulus, a riser, or other suitable wellbore equipment. The APD Device  170   a  is preferably installed so that it is in a cased upper section  129 . The device  170   a  is controlled in the manner described with respect to the device  170  ( FIG. 1A ). 
   Referring now to  FIGS. 4A–D , there is schematically illustrated one arrangement wherein a positive displacement motor/drive  200  is coupled to a moineau-type pump  220  via a shaft assembly  240 . The motor  200  is connected to an upper string section  260  through which drilling fluid is pumped from a surface location. The pump  220  is connected to a lower drill string section  262  on which the bottomhole assembly (not shown) is attached at an end thereof. The motor  200  includes a rotor  202  and a stator  204 . Similarly, the pump  220  includes a rotor  222  and a stator  224 . The design of moineau-type pumps and motors are known to one skilled in the art and will not be discussed in further detail. 
   The shaft assembly  240  transmits the power generated by the motor  200  to the pump  220 . One preferred shaft assembly  240  includes a motor flex shaft  242  connected to the motor rotor  202 , a pump flex shaft  244  connected to the pump rotor  224 , and a coupling shaft  246  for joining the first and second shafts  242  and  244 . In one arrangement, a high-pressure seal  248  is disposed about the coupling shaft  246 . As is known, the rotors for moineau-type motors/pump are subject to eccentric motion during rotation. Accordingly, the coupling shaft  246  is preferably articulated or formed sufficiently flexible to absorb this eccentric motion. Alternately or in combination, the shafts  242 ,  244  can be configured to flex to accommodate eccentric motion. Radial and axial forces can be borne by bearings  250  positioned along the shaft assembly  240 . In a preferred embodiment, the seal  248  is configured to bear either or both of radial and axial (thrust) forces. In certain arrangements, a speed or torque converter  252  can be used to convert speed/torque of the motor  200  to a second speed/torque for the pump  220 . By speed/torque converter it is meant known devices such as variable or fixed ratio mechanical gearboxes, hydrostatic torque converters, and a hydrodynamic converters. It should be understood that any number of arrangements and devices can be used to transfer power, speed, or torque from the motor  200  to the pump  220 . For example, the shaft assembly  240  can utilize a single shaft instead of multiple shafts. 
   As described earlier, a comminution device can be used to process entrained cutting in the return fluid before it enters the pump  200 . Such a comminution device ( FIG. 1A ) can be coupled to the drive  200  or pump  220  and operated thereby. For instance, one such comminution device or cutting mill  270  can include a shaft  272  coupled to the pump rotor  224 . The shaft  272  can include a conical head or hammer element  274  mounted thereon. During rotation, the eccentric motion of the pump rotor  224  will cause a corresponding radial motion of the shaft head  274 . This radial motion can be used to resize the cuttings between the rotor and a comminution device housing  276 . 
   The  FIGS. 4A–D  arrangement also includes a supply flow path  290  to carry supply fluid from the device  200  to the lower drill string section  262  and a return flow path  292  to channel return fluid from the casing interior or annulus into and out of the pump  220 . The high pressure seal  248  is interposed between the flow paths  290  and  292  to prevent fluid leaks, particularly from the high pressure fluid in the supply flow path  290  into the return flow path  292 . The seal  248  can be a high-pressure seal, a hydrodynamic seal or other suitable seal and formed of rubber, an elastomer, metal or composite. 
   Additionally, bypass devices are provided to allow fluid circulation during tripping of the downhole devices of the system  100  ( FIG. 1A ), to control the operating set points of the motor  200  and pump  220 , and to provide safety pressure relief along either or both of the supply flow path  290  and the return flow path  292 . Exemplary bypass devices include a circulation bypass  300 , motor bypass  310 , and a pump bypass  320 . 
   The circulation bypass  300  selectively diverts supply fluid into the annulus  194  ( FIG. 1A ) or casing C interior. The circulation bypass  300  is interposed generally between the upper drill string section  260  and the motor  200 . One preferred circulation bypass  300  includes a biased valve member  302  that opens when the flow-rate drops below a predetermined valve. When the valve  302  is open, the supply fluid flows along a channel  304  and exits at ports  306 . More generally, the circulation bypass can be configured to actuate upon receiving an actuating signal and/or detecting a predetermined value or range of values relating to a parameter of interest (e.g., flow rate or pressure of supply fluid or operating parameter of the bottomhole assembly). The circulation bypass  300  can be used to facilitate drilling operations and to selective increase the pressure/flow rate of the return fluid. 
   The motor bypass  310  selectively channels conveys fluid around the motor  200 . The motor bypass  310  includes a valve  312  and a passage  314  formed through the motor rotor  202 . A joint  316  connecting the motor rotor  202  to the first shaft  242  includes suitable passages (not shown) that allow the supply fluid to exit the rotor passage  314  and enter the supply flow path  290 . Likewise, a pump bypass  320  selectively conveys fluid around the pump  220 . The pump bypass includes a valve and a passage formed through the pump rotor  222  or housing. The pump bypass  320  can also be configured to function as a particle bypass line for the APD device. For example, the pump bypass can be adapted with known elements such as screens or filters to selectively convey cuttings or particles entrained in the return fluid that are greater than a predetermined size around the APD device. Alternatively, a separate particle bypass can be used in addition to the pump bypass for such a function. Alternately, a valve (not shown) in a pump housing  225  can divert fluid to a conduit parallel to the pump  220 . Such a valve can be configured to open when the flow rate drops below a predetermined value. Further, the bypass device can be a design internal leakage in the pump. That is, the operating point of the pump  220  can be controlled by providing a preset or variable amount of fluid leakage in the pump  220 . Additionally, pressure valves can be positioned in the pump  220  to discharge fluid in the event an overpressure condition or other predetermined condition is detected. 
   Additionally, an annular seal  299  in certain embodiments can be disposed around the APD device to direct the return fluid to flow into the pump  220  (or more generally, the APD device) and to allow a pressure differential across the pump  220 . The seal  299  can be a solid or pliant ring member, an expandable packer type element that expands/contracts upon receiving a command signal, or other member that substantially prevents the return fluid from flowing between the pump  220  (or more generally, the APD device) and the casing or wellbore wall. In certain applications, the clearance between the APD device and adjacent wall (either casing or wellbore) may be sufficiently small as to not require an annular seal. 
   During operation, the motor  200  and pump  220  are positioned in a well bore location such as in a casing C. Drilling fluid (the supply fluid) flowing through the upper drill string section  260  enters the motor  200  and causes the rotor  202  to rotate. This rotation is transferred to the pump rotor  222  by the shaft assembly  240 . As is known, the respective lobe profiles, size and configuration of the motor  200  and the pump  220  can be varied to provide a selected speed or torque curve at given flow-rates. Upon exiting the motor  200 , the supply fluid flows through the supply flow path  290  to the lower drill string section  262 , and ultimately the bottomhole assembly (not shown). The return fluid flows up through the wellbore annulus (not shown) and casing C and enters the cutting mill  270  via a inlet  293  for the return flow path  292 . The flow goes through the cutting mill  270  and enters the pump  220 . In this embodiment, the controller  180  ( FIG. 1A ) can be programmed to control the speed of the motor  200  and thus the operation of the pump  220  (the APD Device in this instance). 
   It should be understood that the above-described arrangement is merely one exemplary use of positive displacement motors and pumps. For example, while the positive displacement motor and pump are shown in structurally in series in  FIGS. 4A–D , a suitable arrangement can also have a positive displacement motor and pump in parallel. For example, the motor can be concentrically disposed in a pump. 
   Referring now to  FIGS. 5A–B , there is schematically illustrated one arrangement wherein a turbine drive  350  is coupled to a centrifugal-type pump  370  via a shaft assembly  390 . The turbine  350  includes stationary and rotating blades  354  and radial bearings  402 . The centrifugal-type pump  370  includes a housing  372  and multiple impeller stages  374 . The design of turbines and centrifugal pumps are known to one skilled in the art and will not be discussed in further detail. 
   The shaft assembly  390  transmits the power generated by the turbine  350  to the centrifugal pump  370 . One preferred shaft assembly  350  includes a turbine shaft  392  connected to the turbine blade assembly  354 , a pump shaft  394  connected to the pump impeller stages  374 , and a coupling  396  for joining the turbine and pump shafts  392  and  394 . 
   The  FIGS. 5A–B  arrangement also includes a supply flow path  410  for channeling supply fluid shown by arrows designated  416  and a return flow path  418  to channel return fluid shown by arrows designated  424 . The supply flow path  410  includes an inlet  412  directing supply fluid into the turbine  350  and an axial passage  413  that conveys the supply fluid exiting the turbine  350  to an outlet  414 . The return flow path  418  includes an inlet  420  that directs return fluid into the centrifugal pump  370  and an outlet  422  that channels the return fluid into the casing C interior or wellbore annulus. A high pressure seal  400  is interposed between the flow paths  410  and  418  to reduce fluid leaks, particularly from the high pressure fluid in the supply flow path  410  into the return flow path  418 . A small leakage rate is desired to cool and lubricate the axial and radial bearings. Additionally, a bypass  426  can be provided to divert supply fluid from the turbine  350 . Moreover, radial and axial forces can be borne by bearing assemblies  402  positioned along the shaft assembly  390 . Preferably a comminution device  373  is provided to reduce particle size entering the centrifugal pump  370 . In a preferred embodiment, one of the impeller stages is modified with shearing blades or elements that shear entrained particles to reduce their size. In certain arrangements, a speed or torque converter  406  can be used to convert a first speed/torque of the motor  350  to a second speed/torque for the centrifugal pump  370 . It should be understood that any number of arrangements and devices can be used to transfer power, speed, or torque from the turbine  350  to the pump  370 . For example, the shaft assembly  390  can utilize a single shaft instead of multiple shafts. 
   It should be appreciated that a positive displacement pump need not be matched with only a positive displacement motor, or a centrifugal pump with only a turbine. In certain applications, operational speed or space considerations may lend itself to an arrangement wherein a positive displacement drive can effectively energize a centrifugal pump or a turbine drive energize a positive displacement pump. It should also be appreciated that the present invention is not limited to the above-described arrangements. For example, a positive displacement motor can drive an intermediate device such as an electric motor or hydraulic motor provided with an encapsulated clean hydraulic reservoir. In such an arrangement, the hydraulic motor (or produced electric power) drives the pump. These arrangements can eliminate the leak paths between the high-pressure supply fluid and the return fluid and therefore eliminates the need for high-pressure seals. Alternatively, a jet pump can be used. In an exemplary arrangement, the supply fluid is divided into two streams. The first stream is directed to the BHA. The second stream is accelerated by a nozzle and discharged with high velocity into the annulus, thereby effecting a reduction in annular pressure. Pumps incorporating one or more pistons, such as hammer pumps, may also be suitable for certain applications. 
   Referring now to  FIG. 6A , there is schematically illustrated one arrangement wherein an electrically driven pump assembly  500  includes a motor  510  that is at least partially positioned external to a drill string  502 . In a conventional manner, the motor  510  is coupled to a pump  520  via a shaft assembly  530 . A supply flow path  504  conveys supply fluid designated with arrow  505  and a return flow path  506  conveys return fluid designated with arrow  507 . As can be seen, the  FIG. 6A  arrangement does not include leak paths through which the high-pressure supply fluid  505  can invade the return flow path  506 . Thus, there is no need for high pressures seals. 
   In one embodiment, the motor  510  includes a rotor  512 , a stator  514 , and a rotating seal  516  that protects the coils  512  and stator  514  from drilling fluid and cuttings. In one embodiment, the stator  514  is fixed on the outside of the drill string  502 . The coils of the rotor  512  and stator  514  are encapsulated in a material or housing that prevents damage from contact with wellbore fluids. Preferably, the motor  510  interiors are filled with a clean hydraulic fluid. In another embodiment not shown, the rotor is positioned within the flow of the return fluid, thereby eliminating the rotating seal. In such an arrangement, the stator can be protected with a tube filled with clean hydraulic fluid for pressure compensation. 
   Referring now to  FIG. 6B , there is schematically illustrated one arrangement wherein an electrically driven pump  550  includes a motor  570  that is at least partially formed integral with a drill string  552 . In a conventional manner, the motor  570  is coupled to a pump  590  via a shaft assembly  580 . A supply flow path  554  conveys supply fluid designated with arrow  556  and a return flow path  558  conveys return fluid designated with arrow  560 . As can be seen, the  FIG. 6B  arrangement does not include leak paths through which the high-pressure supply fluid  556  can invade the return flow path  558 . Thus, there is no need for high pressures seals. 
   It should be appreciated that an electrical drive provides a relatively simple method for controlling the APD Device. For instance, varying the speed of the electrical motor will directly control the speed of the rotor in the APD device, and thus the pressure differential across the APD Device. Further, in either of the  FIG. 6A  or  6 B arrangements, the pump  520  and  590  can be any suitable pump, and is preferably a multi-stage centrifugal-type pump. Moreover, positive displacement type pumps such a screw or gear type or moineau-type pumps may also be adequate for many applications. For example, the pump configuration may be single stage or multi-stage and utilize radial flow, axial flow, or mixed flow. Additionally, as described earlier, a comminution device positioned downhole of the pumps  520  and  590  can be used to reduce the size of particles entrained in the return fluid. 
   It will be appreciated that many variations to the above-described embodiments are possible. For example, a clutch element can be added to the shaft assembly connecting the drive to the pump to selectively couple and uncouple the drive and pump. Further, in certain applications, it may be advantages to utilize a non-mechanical connection between the drive and the pump. For instance, a magnetic clutch can be used to engage the drive and the pump. In such an arrangement, the supply fluid and drive and the return fluid and pump can remain separated. The speed/torque can be transferred by a magnetic connection that couples the drive and pump elements, which are separated by a tubular element (e.g., drill string). Additionally, while certain elements have been discussed with respect to one or more particular embodiments, it should be understood that the present invention is not limited to any such particular combinations. For example, elements such as shaft assemblies, bypasses, comminution devices and annular seals discussed in the context of positive displacement drives can be readily used with electric drive arrangements. Other embodiments within the scope of the present invention that are not shown include a centrifugal pump that is attached to the drill string. The pump can include a multi-stage impeller and can be driven by a hydraulic power unit, such as a motor. This motor may be operated by the drilling fluid or by any other suitable manner. Still another embodiment not shown includes an APD Device that is fixed to the drill string, which is operated by the drill string rotation. In this embodiment, a number of impellers are attached to the drill string. The rotation of the drill string rotates the impeller that creates a differential pressure across the device. 
   Referring now to  FIG. 7 , there is shown a comminution device  600  for reducing the size of particles entrained in the returning drilling fluid. These particles can include rock and earth cut by the drill bit, debris from the wellbore, pieces of broken wellbore equipment, and other known items. For brevity, the term “crush” or “crushing” is broadly used to encompass any mechanical force, such as compression or shearing, that breaks up or otherwise disintegrates the entrained particles. Preferably, the comminution device  600 , which is positioned upstream of a selected wellbore device (e.g., the APD device  170  of  FIG. 1 ), reduces the entrained particles to a size that will not jam, damage, or otherwise impair the operations of the selected wellbore device (e.g., APD device  170 ). 
   In the  FIG. 7  embodiment, the device  600  includes a first stage  602  for reducing particles to a first selected size and a second stage  604  for reducing particles to a second selected size. The term selected size or predetermined size should be construed to cover ranges of selected or predetermined sizes as well. By way of a non-limiting illustration, the first stage  602  can reduce the diameter size of entrained particles to a range of approximately one hundred mm to forty-five mm and the second stage  604  can reduce the diameter size of entrained particles to a range of approximately fifty mm to ten mm. The ranges of particle reduction for the stages preferably overlap, but, this need not be the case. In one embodiment, each stage  602 , 604  is formed in a housing  606  wherein one or more cutting heads are disposed. Preferably, the comminution device  600  includes a first cutting head  608  and a second cutting head  610 . 
   The first stage  602  has an inlet  611  in fluid communication with the return fluid and a passage  612  that directs flow into the second stage  604 . The first cutting head  608  crushes entrained particles as they flow through a chamber  614  in the first stage  602 . Preferably, the chamber  614  is formed to promote circulation of the drilling fluid and minimize the settling of entrained solids. Referring now to  FIG. 8 , for example, helix-like fins or ribs  616  formed on an inner wall  618  of the housing  606  “spin” or rotate the fluid such that the entrained particles circulate within the chamber  614 . Further, the inner wall  618  can include raised portions  620  or sidewalls that prevent particles from settling along the outer perimeter of the chamber  614 . Preferably, the housing  606  includes a first cutting surface  622  formed on a plane generally perpendicular to the longitudinal axis A of the device  600 . This cutting surface  622  can include a ramped or inclined section to accommodate the flow or return drilling fluid. Preferably, a second cutting surface  624  is formed on the inner wall  618  of the housing  606 . The first and second cutting surfaces  622 , 624  can include hardened surfaces adapted to withstand the forces and wear associated with the crushing or shearing of the entrained particles. 
   Referring now to  FIGS. 7 and 9 , the first cutting head  608  is fixed to a drive shaft  626  and thereby suspended within the housing chamber  614 . The first cutting head  608  includes a first surface or face  628  that is generally perpendicular to the longitudinal axis A of the device  600  and a circumferential outer surface  630 . In one embodiment, the first face  628  and circumferential outer surface  630  are provided with raised cutting members  632  adapted to shear and/or crush entrained particles. The cutting members  632  include inclined planar portions  634 . Preferably, the cutting members  632  are configured such that the inclined planar portions  634  are aligned along multiple planes such that the entrained particles are subjected to different “angles of attack” for enhanced cutting. Thus, as the cutting head rotates, the first face cutting members  632  cooperate with the first cutting head  608  to reduce the size of particles flowing in a gap  635  therebetween. Likewise, the circumferential outer surface cutting members  632  cooperate with the second cutting surface  624  to reduce the size of particles traveling therebetween. 
   Referring now to  FIG. 7 , the second stage  604  has an inlet  636  in fluid communication with the first stage  602  and an exit  638  that directs flow to the selected wellbore device. Referring now to  FIGS. 7 and 10 , preferably, the second cutting head  610  is generally disk-shaped and includes a plurality of longitudinal flow bores  640 . The size and number of the flow bores  640  will depend on the expected flow rate, size of entrained particles, and other factors known to one skilled in the art. The second stage cutting head  610  is fixed to the drive shaft  626  and thereby suspended in a chamber  642  formed in the housing  606 . Preferably, the return fluid can flow through both the flow bores  640  or a gap  644  provided between the second stage cutting head  610  and an inner surface  646  of the housing  606 . In other arrangements, return fluid flow can be directed to either the flow bores  640  or the gap  644 . The second stage  604  has a first cutting surface  648  formed on a plane generally parallel perpendicular to the longitudinal axis A of the device  600 . This cutting surface  648  can be inclined to accommodate the flow or return drilling fluid. A second cutting surface  650  is formed on the inner surface  646  of the housing  606 . The first and second cutting surface  648 , 650  can include hardened surfaces adapted to withstand the forces and wear associated with the crushing or shearing of the entrained particles. 
   The second cutting head  610  includes a first face  652  that is generally perpendicular to the longitudinal axis A of the device  600  and a circumferential outer surface  654 . In one embodiment, first face  652  and circumferential outer surface  654  are provided with raised cutting members  656  adapted to shear and/or crush entrained particles. The cutting members  656  are provided with inclined portions  658  having, preferably, multiple planar angles as described previously. Thus, as the second cutting head  610  rotates, the first face cutting members  656  cooperate with the first cutting surface  648  to reduce the size of particles traveling therebetween. Likewise, the circumferential outer surface cutting members  656  cooperate with the second cutting surface  650  to reduce the size of particles traveling therebetween. The second stage chamber  642  can also be formed to promote circulation of the drilling fluid and minimize the settling of entrained solids; e.g., members for “spinning” and preventing particles from settling along the outer perimeter of the chamber  642 . 
   The drive shaft  626  can be rotated by a suitable connection to the APD device  170  ( FIG. 1 ), to a downhole power source such an electric or hydraulic motor (not shown), or to the drill string  121  ( FIG. 1 ). Also, suitable axial and radial bearings  660  are provided to stabilize the cutting heads  608 , 610  during operation. Also, the comminution device  600  includes crossover flow passages (not shown) for conveying supply fluid from a location uphole of the device  600  to a location downhole of the device  600 . 
   Referring now to  FIGS. 7–10 , during operation, the return fluid RF enters the first stage chamber  614  via the housing inlet  603 . The first cutting head  608  crushes the entrained particles to a selected size or range of sizes against the first cutting surface  622  with the cutting members  632  formed on the face  628 . Cutting members  632  formed on the outer circumferential surface of the first cutting head  608  can also crush the entrained particles flowing through the gap  635 . The drilling fluid and entrained particles flow through the passage  612  to the chamber  642  of the second stage  604 . The second cutting head  610  further crushes the entrained particles to a smaller selected size or range of sizes. The entrained particles exit the chamber  642  after flowing though the second cutting head flow bores  640  and/or the gap  644  between the second cutting head  610  and housing  606 . Thereafter, the return fluid and entrained cutting are directed to the downstream APD device  170  ( FIG. 1 ). 
   Referring now to  FIG. 11 , there is shown another comminution device  700  for reducing the size of particles entrained in the returning drilling fluid. In the  FIG. 11  embodiment, the device  700  includes a first stage  702  for reducing particles to a first selected size and a second stage  704  for reducing particles to a second selected size. Each stage  702 , 704  is formed in a chamber  706  of a housing  708  wherein one or more cutting heads are disposed. In a preferred embodiment, the cutting heads include first and second frustoconical cutting rotors  710 , 712 . In one embodiment, the angles of the rotors  710 ,  712  and the inlet in the housing are chosen such that the entrained solids are continuously resized. For example, the gap between the cutters and the cutting surface is made progressively smaller along the flow path of the entrained particles. 
   The housing  708  has an inlet  714  in fluid communication with the return fluid and an exit  715  that directs return fluid RF to the selected wellbore device. Preferably, the housing  708  includes a first cutting surface  716  formed on an interior circumferential surface  718 . The first cutting surface  716  can include hardened surfaces adapted to withstand the forces and wear associated with the crushing or shearing of the entrained particles. The chamber  706  can also be formed to promote circulation of the drilling fluid and minimize the settling of entrained solids; e.g., members for “spinning” and preventing particles from settling along the outer perimeter of the chamber  706 . 
   In a preferred embodiment, first and second frustoconical cutting rotors  710 , 712  are coupled in series to a shaft  720  and thereby suspended in the housing chamber  706 . The frustoconical cutting rotors  710 , 712  are configured to crush entrained particles as they flow through a chamber  706 . The cutting rotors  710 , 712  include an outer circumferential faces  722 , 724 , respectively, that are provided with cutting members  726  adapted to crush entrained particles. The cutting members  726  include lobes, grooves, teeth and other structures for crushing entrained particles. The cutting members  726  can be of the same configuration on each of the rotors  710 , 712  or of different configurations. Moreover, each rotor  710 ,  712  can include cutting members  726  of different configurations. Preferably, the cutting members  726  are set at multiple different angles or planes such that the multiple angles of attack are available during the crushing action. Preferably, the first and second frustoconical cutting rotors  710 , 712  are arranged such that their smaller diameter ends are joined and their larger diameter ends are on opposing ends. Depending on the particular arrangement, the first and second frustoconical cutting rotors  710 , 712  can be of same or different lengths, inclination (gradient or slope), or diameter. Moreover, a flow gap  734  between the cutting rotors  710 , 712  and the housing  708  is preferably sized to minimize the risk of plugging while allowing sufficient cutting action between the cutting rotors  710 , 712  and the cutting surface  716 . 
   The cutting rotors  710 , 712  are rotated by the drive shaft  720 . The drive shaft  720  can be rotated by a suitable connection to the APD device, to a downhole power source such an electric or hydraulic motor, or to the drill string. Also, suitable axial/thrust bearings  740  and radial bearings  738  are provided to stabilize the cutting rotors  710 , 712  during operation. The comminution device  700  further includes crossover flow passages  736  for conveying supply fluid SF from a location uphole of the device  700  to a location downhole of the device  700 . 
   It should be appreciated that the present invention is not limited to any particular number of rotors. In certain applications, a single cutting rotor may provide sufficient particle reduction. In other applications, three or more cutting rotors may be required to reduce entrained particles to a size that can pass through the APD device. Moreover, the rotors need not be frustoconical in shape. For example, they can be substantially cylindrical or include arcuate surface. Factors to be considered with respect to the number of rotors and configuration of the cutting rotor and housing  708  include the size of the flow passages in the APD device, available torque for rotating the cutting rotors, the expected drilling fluid flow rate, and the rock content (e.g., expected, size, density and nature of the particles). 
   During operation, the return fluid RF and entrained particles enters the chamber  706  via the inlet  714 . The first cutting rotor  710  cuts or crushes the entrained particles to a selected size or range of sizes. The drilling fluid and entrained particles flow through the gap  732  between the first cutting rotor  710  and the housing  708  to the second cutting rotor  712 , which further crushes the entrained particles to a smaller selected size or range of sizes. Thereafter, the return fluid and entrained cutting are directed to the downstream APD device (e.g., positive displacement pump). 
   It should be understood that the present invention is not limited to multi-stage particle reduction. In certain applications, a single stage may provide sufficient particle reduction. In other applications, three or more stages may be required to reduce entrained particles to a size that can pass through the selected wellbore device. Factors to be considered with respect to the number of stages and configuration of the cutting head and housing include the size of the flow passages in the APD device, available torque for rotating the cutting heads, the expected drilling fluid flow rate, and the rock content (e.g., expected, size, density and nature of the particles). Additionally, while the housing has been described as one element, the cutting heads can be housed in structurally separate housings. Moreover, the housing can be integral with the selected wellbore device. Further, it should be appreciated that the teachings of the present invention can be advantageously applied to any number of downhole applications wherein the size of particles in a return fluid are to be reduced in size in situ before returning to the surface. For instance, one or more independently operable comminution devices can be positioned along the drill string to adjust the density of the return fluid or to prevent the settling of larger particles along sections of the wellbore. In such instances, the particle reduction is controlled relative to selected parameter of the return fluid and not relative to the operating condition of a selected wellbore device. 
   Other embodiments, which are not shown, for reducing the size of particles include mills or devices wherein the axis of the rotational cutting action is generally parallel with the flow of the return fluid, which is usually along the longitudinal axis of the wellbore. In one embodiment, a housing can include a frustoconical chamber for receiving a cylindrical cutter. The return fluid enters at the larger diameter of the chamber and exits at the smaller diameter. The cutter can be formed as a worm conveyer that, when rotated, draws entrained cuttings from the larger diameter section of the chamber to the smaller diameter section of the chamber. The entrained particles are crushed as they flow through the gradually decreasing gap between the cutter and an inner wall defining the frustoconical chamber. In a related embodiment, the cylindrical cutter can be formed in a conical or frustoconical shape that generally conforms to the frustoconical shape of the chamber. The gradients or angles of the chamber and cutter are set such that these spacing between the surfaces of the chamber and the cutter gradually reduces from an entry point to an exit point. 
   In another embodiment, cutting members such as teeth may be formed on an inner surface of a cylindrical housing such as a stator. A rotor disposed in the stator crushed particles against the inner surface when rotated. The teeth have a profile and sufficient interstitial space for allowing solids to enter the inside of the stator. The height of the teeth gradually reduces in size so that the particles or solids cannot pass before they have been crushed between the stator and the rotor. Holes provided in the stator can be provided to allow particles of a selected size to exit the stator. 
   In another embodiment, three conical or frustoconical rolls are oriented is such a way so that the enveloped space between the rolls has a conical shape. The diameter of the rolls becomes smaller with travel length of the solids allowing a continuous resizing of particles. One centrally disposed roll drives the other adjacent rolls. In another embodiment, a roller bit rotates on a plate. The roller bit includes wheel-like members that roll on the plate. During operation, roller bit rotation causes the wheel-like members to roll over and crush particles, which exit the roller bit via holes. 
   In still other embodiments, the drive source or rotating action for crushing particles may be perpendicular to the flow of the return fluid. For instance, two rollers may be positioned in a spaced-apart parallel orientation. In one embodiment, the two rollers are rotated in opposite directions such that solids and particles are pulled into the space between the rollers and crushed. In another embodiment, the rollers rotate in the same direction but at different rotational speeds. The particles, while being drawn between the rollers, are rotated, which provides flexible load points and enhances the crushing action. In yet another embodiment, one rotating roll works against a non-rotating plate to crush the particles. The rotating roll can include teeth having specified spacing. The distance between the roll and the plate and the space between the teeth determine the maximum size of the reduced particles. 
   In yet other embodiments, housing includes a rotating disk that has a plurality of radially oriented pistons. During disk rotation, centrifugal force urges the pistons move out of the disk. The rotating disk is disposed in a cavity or chamber such that during one part of the rotation, a wall of the chamber prevents the pistons from emerging from the disk and in another part of rotation, a gap is provided such that the piston can protrude from the disk. During operation, larger particles entering this gap are struck by the piston and crushed. Other particles are crushed between the disk and the wall of the chamber. In still other embodiments, a mortar can be used to crush solids. 
   In another embodiment, a hammer is disposed in a chamber and reciprocates along an axis transverse to the flow of drilling fluid through the chamber. A rod or other connecting member fixed to the hammer drives the hammer in an oscillating fashion against opposing walls defining the chamber. The entrained cuttings are crushed between the hammer and the walls. Biasing members such as springs coupled to the hammer can allow resonance operation. 
   In another embodiment, the drilling fluid is directed between a pair of opposing stamps. One or both of the stamps, which are plate-like members, can include flow holes through which entrained particles of a specified diameter can exit. The stamps move together squeezing entrained particles therebetween. 
   In another embodiment, a screen is positioned upstream of the wellbore device. Only particles of a preselected size can pass through the screen. Once the screen is plugged with larger size particles, a bypass is opened to transport the larger cuttings past the wellbore device. Also, the particles can be collected in a tank or chamber and periodically conveyed to the surface. The particles can also be stored in the formation. 
   In still other embodiments, chemical, electrical, thermal, or wave energy can be used to disintegrate and reduce the size of entrained particles. For instance, an aggressive chemical can be injected into the return fluid. The chemical can either dissolve the particles or sufficiently soften the particles such that the particles disintegrate upon entering the wellbore device or perhaps by rubbing against the wellbore wall. The chemical can be supplied from a downhole reservoir that is periodically replenished by a fluid line to the surface or directly injected from such a fluid line. Embodiments utilizing electrical energy can include spark drilling, which can use electrical energy to evaporate entrained particles. The discharge point for the electrical energy can be integrated into a drill bit or positioned in the return fluid uphole of the drill bit. Other embodiments use a laser positioned proximate or uphole of the drill bit. The laser can produce a continuous or periodic beam that cuts the particles crossing the beam. In still other embodiments, the entrained particles are subjected to ultrasonic waves. The source for the ultrasonic source can be positioned proximate or uphole of the drill bit and reduce the size of particles entering an established wave field. It should be understood that the above-described embodiments can be combined with the described mechanical arrangements and methods for reducing the size of entrained particles. For instance, the larger size particles trapped by the screen can be collected in a chamber, as described previously, and then subjected to chemical, electrical, thermal, or wave energy. Thus, the reduction process is made more efficient by focusing or limiting the discharge of energy to only the larger sized particles. 
   While the foregoing disclosure is directed to the preferred embodiments of the invention, various modifications will be apparent to those skilled in the art. For example, while a stator has been described as a cutting surface, the rotor or other cutting member can crush entrained particles against a wellbore wall, thereby eliminating the direction of return fluid into a chamber. It is intended that all variations within the scope and spirit of the appended claims be embraced by the foregoing disclosure.