Abstract:
An APD Device provides a pressure differential in a wellbore to control dynamic pressure loss while drilling fluid is continuously circulated in the wellbore. A continuous circulation system circulates fluid both during drilling of the wellbore and when the drilling is stopped. Operating the APD Device allows wellbore pressure control during continuous circulation without substantially changing density of the fluid. The APD Device can maintain wellbore pressure below the combined pressure caused by weight of the fluid and pressure losses created due to circulation of the fluid in the wellbore, maintain the wellbore at or near a balanced pressure condition, maintain the wellbore at an underbalanced condition, reduce the swab effect in the wellbore, and/or reduce the surge effect in the wellbore. A flow restriction device that creates a backpressure in the wellbore annulus provides surface control of wellbore pressure.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application takes priority from U.S. Provisional Application Ser. No. 60/691,792 filed on Jun. 17, 2005. This application is a continuation-in-part of U.S. patent application Ser. No. 10/783,471 filed Feb. 20, 2004, now U.S. Pat. No. 7,114,581 which is: (i) a continuation 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” and (ii) a continuation-in-part of U.S. patent application Ser. No. 10/716,106 filed on Nov. 17, 2003, now U.S. Pat. No. 6,854,532 which is a continuation of U.S. patent application Ser. No. 10/094,208, filed Mar. 8, 2002, now U.S. Pat. No. 6,648,081 granted on Nov. 18, 2003, which is a continuation of U.S. application Ser. No. 09/353,275, filed Jul. 14, 1999, now U.S. Pat. No. 6,415,877, which claims benefit of U.S. Provisional Application No. 60/108,601, filed Nov. 16, 1998, U.S. Provisional Application No. 60/101,541, filed Sep. 23, 1998, U.S. Provisional Application No. 60/092,908, filed, Jul. 15, 1998 and U.S. Provisional Application No. 60/095,188, filed Aug. 3, 1998. 
    
    
     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. The umbilical can include wires for transmitting power such as electrical downhole. 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. 
     In one embodiment, sensors communicate with a controller via a communication link to maintain the wellbore pressure at a zone of interest at a selected pressure or range of pressures. The communication link can include conductors, wires, cables in or adjacent the drill string that are adapted to convey data signals and/or electrical power. 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. 
     Embodiments of the present invention can be to manage wellbore pressure even when the formation is not being actively drilled. For example, embodiments of the present invention can be used to control pressure during periods where joints are added to the drill string and when the drill string is tripped into or out of the wellbore. In one embodiment, a system includes a drill string, a drilling fluid unit, a device that allows continuous circulation of drilling fluid into the wellbore, and an APD Device in communication with the drilling fluid to control pressure in the wellbore. The continuous circulation device is adapted to circulate fluid while making up joints to a drill string, while tripping the drill string, and other such activities. In addition to controlling wellbore pressure during drilling of the wellbore, the APD Device also controls wellbore pressure when drilling is stopped for these activities. 
     Using appropriate controls, wellbore pressure can be maintained below the combined pressure caused by weight of the fluid and pressure losses created due to circulation of the fluid in the wellbore, at or near a balanced pressure condition, and at an underbalanced condition. Additionally, the APD Device can be operated to reduce swab effect in the wellbore and/or reduce surge effect in the wellbore. Advantageously, wellbore pressure can be controlled both during the drilling and when the drilling is stopped without substantially changing density of the fluid. In some embodiments, surface control of wellbore pressure is provided by a flow restriction device such as a choke or valve coupled to the fluid flowing out of the annulus of the wellbore. The flow restriction device selectively creates a backpressure in the wellbore that can be used to modulate wellbore pressure. 
     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); 
         FIGS. 6  is a graph depicting exemplary dynamic pressure losses associated with a conventional drilling system and also a system utilizing an active pressure differential device made in accordance embodiments of the present invention; 
         FIG. 7  is a schematic illustration of a continuous circulation system used in conjunction with an APD Device and flow restriction device made in accordance with embodiments of the present invention; and 
         FIG. 8  is a graph depicting exemplary dynamic pressure losses associated with a system utilizing the  FIG. 7  system and also the  FIG. 7  system when utilizing an active pressure differential device made in accordance embodiments 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 fluidly 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 2 ) 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  FIG. 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. 
     In other embodiments, an electrical motor can be used to drive and control the APD Device. 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. 
     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. 
     It should be appreciated that the teachings of the present invention can be advantageously applied to manage wellbore pressure throughout the well construction process. As is known, formations can have a narrow “window” within which wellbore pressure must be maintained to prevent a kick or damage to the formation. As discussed previously, the lower pressure limit is generally the pore pressure of the formation and the upper limit is the fracture pressure of the formation. Wellbore pressure should be maintained within this “window” both when the formation is being drilled and during periods when drilling has been interrupted. Instances where drilling is interrupted include periods where joints are added to the drill string and when the drill string is tripped into or out of the wellbore. Advantageously, embodiments of the present invention can be used to control pressure in such situations. 
     An exemplary situation wherein it is desirable to control wellbore pressure arises while drilling is interrupted in order to add a joint of pipe to the drill string. Conventionally, drilling is halted and fluid circulation is stopped so that the pipe can be added to the drill string at the rig. Referring now to  FIG. 6 , there is shown a graph illustrating changes in wellbore pressure during such a procedure. The x-axis represents time and the y-axis represents dynamic pressure loss. For reference, a zero value for dynamic pressure loss is labeled with numeral 0. A line  700  generally represents wellbore pressure associated with a conventional drilling system. Interval  702  represent a time period when drilling is halted, interval  704  represent a time period when drilling is occurring and interval  706  represents transient conditions. At interval  702 , there is no fluid circulation and, therefore, no dynamic pressure loss. Thus, wellbore pressure at interval  702  is generally the hydrostatic pressure of the mud column. At interval  704 , a dynamic pressure loss occurs due to fluid circulation, which manifests itself as an increase in wellbore pressure. While the interval  706  is shown as smooth transitions between the upper and lower pressure values, it should be understood that the cycling of mud pumps and other factors can cause spikes in pressure. As can be seen, with conventional drilling systems, wellbore pressure periodically varies between an upper and lower pressure value due to dynamic pressure losses. 
     Advantageously, utilization of an APD Device, such as those previously described in connection with  FIGS. 1A-5 , can increase flexibility in selecting operating parameters and improve drilling operations. For instance, a line  710  represents the pressure associated with a drilling system utilizing an APD Device (e.g., the APD Device  170  of  FIG. 1A ). The line  710  is shown offset from the lower pressure values of line  700  merely for clarity. For line  710 , interval  712  represents a time period when drilling is halted and interval  714  represents a time period when drilling is occurring. Intervals of transient conditions can exist but have been omitted for simplicity. At interval  712 , there is no fluid circulation and, therefore, no dynamic pressure loss. While an APD Device could be operating, it assumed that the APD Device is stopped. Thus, wellbore pressure at interval  712  is generally the hydrostatic pressure of the mud column. At interval  714 , a pressure loss normally occurs due to fluid circulation, which manifests itself as an increase in wellbore pressure. However, the APD Device reduces the dynamic pressure loss at interval  704  of line  700 . For simplicity, the pressure differential generated by the APD Device is shown as generally equaling the dynamic pressure loss. The pressure differential, however, can be selected to be a fraction or a multiple of the dynamic pressure loss. As can be seen, the APD Device can reduce the magnitude of the pressure changes, which can lead to a more benign pressure condition in the wellbore when fluid circulation is periodically halted. 
     As discussed below, the utility of the present invention extends also to applications where circulation continues even though drilling is halted. 
     Referring now to  FIG. 7 , there is schematically shown a conventional drilling rig  730  utilizing a continuous circulation system  732 . The rig  730  includes known equipment such as a top drive  734 , a blowout preventer (BOP) stack  736 , and a fluid circulation system  738 , which includes known equipment such as a pump, mud pit and suitable conduits. A drill string  740  suspended from the rig  730  drills a wellbore  742  in a formation  737 . The continuous circulation system  732  includes a coupler  733  that is connected to the top drive  734  and drill string  740 . During operation, the top drive  734  rotates the drill string  740  while the fluid circulation system  738  pumps drilling fluid into the wellbore  742  via the top drive  734  and drill string  740 . 
     The coupler  733  maintains fluid circulation through the drill string  740  and to the wellbore  742  even when the top drive  734  is uncoupled from the drill string  740 . The coupler  733  can include suitable rams and isolation chambers that direct drilling fluid into the drill string while one or more tubular joints are made up to the drill string. One suitable coupler is discussed in “Continuous Circulation Drilling”, OTC 14269, J. W. Jenner, et al., which is hereby incorporated by reference for all purposes. Thus, the continuous circulation system  732  reduces or eliminates the instances where drilling fluid ceases to flow in the wellbore  742 . Thus, wellbore pressure does not normally drop to hydrostatic pressure when the continuous circulation system  732  is in operation. 
     It should be understood that the coupler  733  is merely representative of devices and equipment that convey fluid into the wellbore while making a connection to the drill string or while tripping the drill string. The teachings of the present invention can be advantageously utilized with any device or system that can convey fluid into the wellbore during activities such as tripping and connections interrupt drilling. Moreover, the term “continuous circulation system” should be understood generically to refer to one or more devices that can be operated to convey fluid and not any particular device or system. 
     Referring now to  FIG. 8 , there is shown a graph illustrating the wellbore pressure changes associated with the  FIG. 7  system. The x-axis represents time and the y-axis represents dynamic pressure loss. A line  750  represents pressure for the  FIG. 7  drilling system. Interval  752  represent a time period when drilling is halted and interval  754  represent a time period when drilling is occurring. For both intervals  752  and  754 , a dynamic pressure loss occurs due to fluid circulation, which manifests itself as an increase in wellbore pressure relative to hydrostatic pressure. Thus, the wellbore pressure is generally the hydrostatic pressure plus ECD for the  FIG. 7  system. 
     As noted earlier, wellbore pressure should be maintained between the pore pressure and the fracture pressure. Thus, to prevent a kick, the wellbore pressure associated with operation of the continuous circulation system  732  should remain above pore pressure even if fluid circulation is interrupted. That is, the value of the hydrostatic pressure alone, without dynamic pressure loss, should be greater than pore pressure to ensure formation fluids do not flow into the wellbore since dynamic pressure loss disappears when circulation stops. A conventional circulation system could utilize a drilling fluid having a high enough mud weight to provide a hydrostatic pressure above pore pressure. However, dynamic pressure loss is additive to hydrostatic pressure. Thus, during circulation, dynamic pressure losses could cause wellbore pressure to approach or exceed the fracture pressure of the formation. It should be appreciated that, while the continuous circulation system can provide enhanced drilling operations, constraints relating to drilling operating parameters and formation parameters could limit its applicability in certain situations. Advantageously, use of an APD Device in conjunction with the continuous circulation system can mitigate such constraints. 
     Referring to  FIG. 7 , there is shown an APD Device  760  positioned in the wellbore in conjunction with the continuous circulation system  732 . The APD Device  760  creates a pressure differential in the wellbore in a manner previously discussed. Referring now to  FIG. 8 , this pressure differential reduces dynamic pressure losses and thereby shifts the line  750  to dashed line  770 . It should be appreciated that this shift can assist in keeping wellbore pressure below the fracture pressure of the formation. Moreover, wellbore pressure can be so maintained even when using a drilling fluid having a mud weight that provides a hydrostatic pressure greater than pore pressure. Thus, if operation of the continuous circulation system is interrupted, then wellbore pressure drops to hydrostatic pressure, which is higher than pore pressure. If operation of the APD Device is interrupted, then wellbore pressure increases to hydrostatic pressure plus ECD. In neither case does wellbore pressure fall below pore pressure. Because the circulating wellbore pressure can be maintained below fracture pressure while still allowing a hydrostatic pressure above pore pressure in the event that circulation is stopped, the risk of a kick is minimized. 
     Furthermore, referring to  FIG. 7 , a surface flow modulation or restriction device  780  can be used to control wellbore pressure by controlling the flow of fluid out of the wellbore  742 . The flow restriction device  780 , which can be a choke or valve, can be actuated to modulate flow of drilling fluid out of the annulus of the wellbore  742  and thereby alter wellbore pressure. For example, a restriction of flow can cause a backpressure in the annulus of the wellbore  742  that can increase wellbore pressure. This backpressure can in effect reduce the magnitude of the pressure differential caused by the APD Device  760 . Thus, for example, the APD Device  760  can be operated to provide a generally fixed pressure differential. From the surface, the flow restriction device  780  can be modulated as desired to increase backpressure and thereby set the wellbore pressure. It should be thus appreciated that any device that can control flow out of the wellbore can be suitable for such a purpose. 
     It should be appreciated that although the above discussion related to drilling interruptions for adding joints to a drill string, the utility of the APD Device in conjunction with a continuous circulation system can also be applied to instances such as tripping of a drill string into or out of a wellbore. As noted earlier with reference to  FIG. 6 , the transient interval  706  can include pressure spikes that temporarily and significantly vary wellbore pressure; e.g., surge effects can increase wellbore pressure whereas swab effect can decrease wellbore pressure. Operation of the APD Device during such transient conditions can mitigate such effects by appropriately controlling wellbore pressure. 
     Furthermore, while utilization of the APD Device was discussed in the context of the  FIG. 7  system, it should be understood that the present teachings can be applied to any drilling system; including offshore systems, land-based systems, coiled tubing systems, rotary table driven systems, tractor based systems, and other systems previously described. 
     While the foregoing disclosure is directed to the preferred embodiments of the invention, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope and spirit of the appended claims be embraced by the foregoing disclosure.