Patent Publication Number: US-6986282-B2

Title: Method and apparatus for determining downhole pressures during a drilling operation

Description:
BACKGROUND OF INVENTION 
     1. Field of the Invention 
     This invention relates generally to the determination of various downhole parameters in a subsurface formation penetrated by a wellbore. More particularly, this invention relates to the determination downhole parameters, such as annular, formation and/or pore pressure, during a drilling operation. 
     2. Description of the Related Art 
     Present day oil well operation and production involves continuous monitoring of various subsurface formation parameters. One aspect of standard formation evaluation is concerned with the parameters of reservoir pressure and the permeability of the reservoir rock formation. Continuous monitoring of parameters such as reservoir pressure and permeability indicate the formation pressure change over a period of time, and is essential to predict the production capacity and lifetime of a subsurface formation. 
     Present day operations typically obtain these parameters through wireline logging via a “formation tester” tool. This type of measurement requires a supplemental “trip” downhole. In other words, the drill string must be removed from the wellbore so that a formation tester may be run into the wellbore to acquire the formation data and, after retrieving the formation tester, running the drill string back into the wellbore for further drilling. Thus, it is typical for formation parameters, including pressure, to be monitored with wireline formation testing tools, such as those tools described in U.S. Pat. Nos.: 3,934,468; 4,860,581; 4,893,505; 4,936,139; and 5,622,223. Each of these patents is limited in that the formation testing tools described therein are only capable of acquiring formation data as long as the wireline tools are disposed in the wellbore and in physical contact with the formation zone of interest. Since “tripping the well” to use such formation testers consumes significant amounts of expensive rig time, it is typically done under circumstances where the formation data is absolutely needed, when tripping of the drill string is done for a drill bit change or for other reasons. 
     The availability of reservoir formation data on a “real time” basis during well drilling activities is a valuable asset. Real time formation pressure obtained while drilling will allow a drilling engineer or driller to make decisions concerning changes in drilling mud weight and composition, as well as penetration parameters, at a much earlier time to thus promote the safety aspects of drilling. The availability of real time reservoir formation data is also desirable to enable precision control of drill bit weight in relation to formation pressure changes and changes in permeability so that the drilling operation can be carried out at its maximum efficiency. 
     Techniques have been developed to acquire formation data from a subsurface zone of interest while the downhole drilling tool is present within the wellbore, and without having to trip the well to run formation testers downhole to identify these parameters. Examples of techniques involving measurement of various downhole parameters during drilling are set forth in U.K. Patent Application GB 2,333,308 assigned to Baker Hughes Incorporated, U.S. Pat. No. 6,026,915 assigned to Halliburton Energy Services, Inc. and U.S. Pat. Nos. 6,230,557 and 6,164,126 assigned to the assignee of the present invention. 
     Despite the advances in obtaining downhole formation parameters, there remains a need to further develop reliable techniques which permit data collection during the drilling process. Benefits may also be achieved by utilizing the wellbore environment and the existing operation of the drilling tool to facilitate measurements. It is desirable that such techniques be provided that are automatic and/or without the need of signals from the surface to activate operation. It is further desirable that such techniques provide one or more of the following, among others, simplified operation, minimal impact on the drilling operation, fast operation, minimal test volume, external testing of a variety of downhole parameters, elimination of test flow line, multiple test devices about the tool for multiple opportunities for test results, reduction or elimination the use of motors, pumps and/or valves, low power consumption, reduction in moving parts, compact design, durability for even high impact operations, rapid response. Added benefit would be achieved where such a device could be used in combination with a pre-test piston to provide pressure readings, pretest functions as well as other downhole data. 
     SUMMARY OF INVENTION 
     The invention relates generally to an apparatus for collecting downhole data during a drilling operation via a downhole drilling tool positioned in a wellbore. The wellbore has an annular pressure therein. The wellbore penetrates a subterranean formation having a pore pressure therein. The downhole tool is adapted to pass a drilling mud flowing therethrough such that an internal pressure is created therein. The internal pressure and annular pressure generate a differential pressure therebetween. 
     In at least one aspect, the apparatus includes a drill collar, a piston and a sensor. The drill collar is operatively connectable to a drill string of the drilling tool, and has a passage therein for passing the drilling mud therethrough. The drill collar has an opening therein extending into a pressure chamber. The pressure chamber is in fluid communication with the passage and/or the wellbore. The piston is slidably positioned in the pressure chamber and has a rod extending therefrom into the opening. The piston is movable to a closed position in response to an increase in differential pressure and to an open position in response to a decrease in differential pressure such that in the closed position the rod fills the opening and in the open position at least a portion of the rod is drawn into the chamber such that a cavity is formed in the opening for receiving downhole fluid. The sensor is positioned in the rod for collecting data from the downhole fluid in the cavity. 
     In another aspect, the apparatus includes a drill collar, a probe, a piston and a sensor. The drill collar is operatively connectable to a drill string of the drilling tool. The drill collar has a passage therein for passing the drilling mud therethrough. The drill collar has a collar opening therein extending into a pressure chamber. The pressure chamber is in fluid communication with the passage and/or the wellbore. The probe is slidably positioned in the pressure chamber. The probe movable between a retracted position in the pressure chamber and an extended position extending from the drill collar into the collar opening. The probe is positionable adjacent the sidewall of the wellbore for sealing engagement therewith. The probe has a probe opening therethrough extending into a probe chamber therein. The piston is slidably positioned in a probe chamber in the probe and has a rod extending therefrom into the probe opening. The piston is movable to a closed position in response to an increase in differential pressure and to an open position in response to a decrease in differential pressure such that in the closed position the rod fills the opening and in the open position at least a portion of the rod is drawn into the chamber such that a cavity is formed in the probe opening for receiving downhole fluid. The sensor is positioned in the rod for collecting data from the downhole fluid in the cavity. 
     The apparatus may be provided with a hydraulic control circuit to manipulate the internal and/or annular pressure for activation of the piston and/or probe. The hydraulics may also be used to affect the timing of tests performed by the piston and/or probe. 
     The sensor may be provided with circuitry arranged to facilitate collection and/or communication of data. The circuitry may be of an overlapping communication coil, back-to-back-coil and/or other arrangements. 
     Finally, in another aspect, the invention relates to a method of collecting downhole data during a drilling operation via a downhole drilling tool positioned in a wellbore. The wellbore has an annular pressure therein. The wellbore penetrating a subterranean formation having a pore pressure therein. A differential pressure being generated between the internal pressure and the annular pressure. The method comprises providing a downhole drilling tool with a drill collar having a passage therethrough, positioning the downhole drilling tool into a wellbore, selectively changing the differential pressure such that the piston is moved between the open and closed position, and sensing data from the downhole fluid in the cavity. The drill collar having an opening therein extending into a chamber and a piston slidably positioned in the chamber and having a rod extending therefrom into the opening. The piston is movable between a closed and an open position. Measurements may be taken continuously or at desired intervals. 
     Other aspects of the invention will be clear from the description provided herein. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG. 1  is an elevational view, partially in section and partially in block diagram, of a conventional drilling rig and drill string employing the present invention; 
         FIG. 2  is an elevational view, partially in section and partially in block diagram, of a stabilizer collar having pressure assemblies therein; 
         FIG. 3A  is a cross-sectional view of a first embodiment of a pressure assembly of  FIG. 2  in the closed position; 
         FIG. 3B  is a cross-sectional view of another embodiment of a pressure assembly of  FIG. 2  in the open position; 
         FIG. 4A  is a cross-sectional view of a first embodiment of a pressure assembly of  FIG. 3  in the extended position, and a corresponding hydraulic control diagram; 
         FIG. 4B  is a cross-sectional view of another embodiment of a pressure assembly of  FIG. 3  in the retracted position, and a corresponding hydraulic control diagram; 
         FIG. 5A  is a schematic view detailing a first embodiment of electronics for the pressure assembly of  FIG. 2 ; 
         FIG. 5B  is a schematic view detailing another embodiment of electronics for the pressure assembly of  FIG. 2 ; 
         FIG. 6  is a block diagram depicting the electronics of the pressure assemblies of FIG.  2 . 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  shows a typical drilling system and related environment. Land-based platform and derrick assembly  10  are positioned over wellbore  11  penetrating subsurface formation F. Wellbore  11  is formed by rotary drilling in a manner that is well known. Those of ordinary skill in the art given the benefit of this disclosure will appreciate, however, that the present invention also finds application in directional drilling applications as well as rotary drilling, and is not limited to land-based rigs. 
     Drill string  12  is suspended within wellbore  11  and includes drill bit  15  at its lower end. Drill string  12  is rotated by rotary table  16 , energized by means not shown, which engages kelly  17  at the upper end of the drill string. Drill string  12  is suspended from hook  18 , attached to a traveling block (also not shown), through kelly  17  and rotary swivel  19  which permits rotation of the drill string relative to the hook. 
     Drilling fluid or mud  26  is stored in pit  27  formed at the well site. Pump  29  delivers drilling fluid  26  to the interior of drill string  12  via a port in swivel  19 , inducing the drilling fluid to flow downwardly through drill string  12  as indicated by directional arrow  9 . The drilling fluid exits drill string  12  via, ports in drill bit  15 , and then circulates upwardly through the region between the outside of the drillstring and the wall of the wellbore, called the annulus, as indicated by direction arrows  32 . In this manner, the drilling fluid lubricates drill bit  15  and carries formation cuttings up to the surface as it is returned to pit  27  for recirculation. 
     The drilling mud performs various functions to facilitate the drilling process, such as lubricating the drill bit  15  and transporting cuttings generated by the drill bit during drilling. The cuttings and/or other solids mix within the drilling fluid to create a “mudcake”  160  that also performs various functions, such as coating the borehole wall. 
     The dense drilling fluid  26  conveyed by a pump  29  is used to maintain the drilling mud in the wellbore at a pressure (annular pressure P A ) higher than the pressure of fluid in the surrounding formation F (pore pressure P P ) to prevent formation fluid from passing from surrounding formations into the borehole. In other words, the annular pressure (P A ) is maintained at a higher pressure than the pore pressure (P P ) so that the wellbore is “overbalanced”(P A &gt;P P ) and does not cause a blowout. The annular pressure (P A ) usually is also maintained below a given level to prevent the formation surrounding the wellbore from cracking, and to prevent drilling fluid from entering the surrounding formation. Thus, downhole pressures are typically maintained within a given range. 
     Drillstring  12  further includes a bottom hole assembly, generally referred to as  100 , near the drill bit  15  (in other words, within several drill collar lengths from the drill bit). The bottom hole assembly includes capabilities for measuring, processing, and storing information, as well as communicating with the surface. Bottom hole assembly  100  thus includes, among other things, measuring and local communications apparatus  200  for determining and communicating the resistivity of formation F surrounding wellbore  11 . Communications apparatus  200 , including transmitting antenna  205  and receiving antenna  207 , is described in detail in U.S. Pat. No. 5,339,037, commonly assigned to the assignee of the present application, the entire contents of which are incorporated herein by reference. 
     Assembly  100  further includes drill collar  130  for performing various other measurement functions, and surface/local communications subassembly  150 . Subassembly  150  includes antenna  250  used for local communication with apparatus  200 , and a known type of acoustic communication system that communicates with a similar system (not shown) at the earth&#39;s surface via signals carried in the drilling fluid or mud. Thus, the surface communication system in subassembly  150  includes an acoustic transmitter which generates an acoustic signal in the drilling fluid that is representative of measured downhole parameters. 
     One suitable type of acoustic transmitter employs a device known as a “mud siren” which includes a slotted stator and a slotted rotor that rotates and repeatedly interrupts the flow of drilling fluid to establish a desired acoustical wave signal in the drilling fluid. The driving electronics in subassembly  150  may include a suitable modulator, such as a phase shift keying (PSK) modulator, which conventionally produces driving signals for application to the mud transmitter. These driving signals can be used to apply appropriate modulation to the mud siren. 
     The generated acoustical wave is received at the surface by transducers represented by reference numeral  31 . The transducers, for example, piezoelectric transducers, convert the received acoustical signals to electronic signals. The output of transducers  31  is coupled to uphole receiving subsystem  90 , which demodulates the transmitted signals. The output of receiving subsystem  90  is then couple to processor  85  and recorder  45 . 
     Uphole transmitting system  95  is also provided, and is operative to control interruption of the operation of pump  29  in a manner that is detectable by transducers  99  in subassembly  150 . In this manner, there is two-way communication between subassembly  150  and the uphole equipment as described in greater detail in U.S. Pat. No. 5,235,285. 
     Drill string  12  is further equipped in the embodiment of  FIG. 1  with stabilizer collar  300 . Such stabilizing collars are utilized to address the tendency of the drill string to “wobble” and become decentralized as it rotates within the wellbore, resulting in deviations in the direction of the wellbore from the intended path (for example, a straight vertical line). Such deviation can cause excessive lateral forces on the drill string sections as well as the drill bit, producing accelerated wear. This action can be overcome by providing a means for centralizing the drill bit and, to some extent, the drill string, within the wellbore, such as stabilizer blades  314 . 
       FIG. 2  illustrates a stabilizer collar  300   a , partially in cross-section, usable in connection with a drilling tool, such as the drilling tool  100  of FIG.  1 . The collar  300   a  is connected to a drill string  12  and positioned in a borehole  11  lined with mudcake  105 . The stabilizer collar  300   a  includes a plurality of stabilizer blades  314   a  with pressure assemblies  210  therein. The collar  300   a  has a passage  215  extending therethrough for passage of drilling fluid through the downhole tool as indicated by the arrow. The flow of fluid through the tool creates an internal pressure P I . The exterior of the drill collar is exposed to the annular pressure P A  of the surrounding wellbore. The differential pressure δ P between the internal pressure P I  and the annular pressure P A  may be used to activate the pressure assemblies  210  as will be described further herein. If the desired differential pressure does not result from the bottom hole assembly arrangement, an additional choke (not shown) may be placed in the drill string to restrict flow and create back pressure. 
     The stabilizer collar  300   a  has a tubular mandrel  302  adapted for axial connection in a downhole tool, such as the drill string  12  of FIG.  1 . Thus, mandrel  302  may be equipped with pin and box ends  304 ,  306  for conventional make-up within the drill string. As shown in  FIG. 2 , ends  304 ,  306  may be customized collars that are connected to the central elongated portion of mandrel  302  in a conventional manner, such as threaded engagement and/or welding. 
     Stabilizer collar  300  further includes stabilizer element or sleeve  308  positioned about tubular mandrel  302  between ends  304  and  306 . Thrust bearings  312  are provided to reduce the frictional forces and bear the axial loads developed at the axial interface between sleeve  308  and mandrel ends  304 ,  306 . Rotary seals  348  and radial bearings  346  are also provided at the radial interface between mandrel  302  and sleeve  308 . 
     The stabilizer collar  300   a  of  FIG. 2  has three spiral stabilizer blades  314   a  positioned about the circumference of the drill collar. The stabilizer blades  314   a  are connected, such as by welding or bolting, to the exterior surface of stabilizer sleeve  308 . The blades are preferably spaced apart, and oriented in a spiral configuration, as indicated in  FIG. 2 , or axially ( FIG. 1 ) along the stabilizer sleeve. It is presently preferred that the sleeve  308  include three such blades  314  distributed evenly about the circumference of the sleeve. However, the present invention is not limited to this three-blade embodiment, and may be utilized to advantage with other arrangements of the blades. 
     For illustration purposes a cross-sectional view of two embodiments of a pressure assembly  210   a  and  210   b  are depicted. Pressure assembly  210   a  is positioned within stabilizer blade  314   a  for performing various measurements. Pressure assembly  210   a  may be used to monitor annular pressure in the borehole and/or pressures of the surrounding formation when positioned in engagement with the wellbore wall. As shown in  FIG. 2 , pressure assembly  210   a  is in non-engagement with the borehole wall  110  and, therefore, may measure annular pressure, if desired. When moved into engagement with the borehole wall  110 , the pressure assembly  210   a  may be used to measure pore pressure of the surrounding formation. 
     As best seen in  FIG. 2 , pressure assembly  210   b  is extendable from the stabilizer blade  314   a  for sealing engagement with the mudcake  105  and/or the wall  110  of the borehole  11  for taking measurements of the surrounding formation. The pressure assembly  210   b  may be activated, as described further herein, to extend from the stabilizer to reach the surrounding borehole to take the desired measurement. Optionally, the pressure assembly  210   b  may also be used to take annular pressures when in non-engagement with the borehole wall. One or more pressure assemblies of various configurations may be used in one or more stabilizer blades for performing the desired measurements. 
       FIGS. 3A and 3B  depict pressure assembly  210   a  in greater detail.  FIG. 3A  shows the pressure assembly  210   a  in a closed position.  FIG. 3B  shows the pressure assembly in a testing, or open, position. The pressure assembly  210   a  is positioned in a chamber  355  in the stabilizer blade  314   a . The pressure assembly  210   a  includes a piston  350  and a spring  365 . The piston has a first portion  375  slidably movable within a chamber  355  in the stabilizer blade  314   a , and a second portion, or rod,  370  extending therefrom. The second portion  370  extends from the chamber  355  into a passage  380  and is slidably movable therein. The piston may be provided with seals to facilitate movement within the chamber and/or the passage. The passage  380  extends from an opening  385  in the drill collar, through the stabilizer blade  314   a  and into the chamber  355 . 
     The piston is preferably provided with a sensor  360 , such as a pressure gauge, capable of taking downhole measurements. The sensor is preferably exposed to fluids adjacent the first portion  370  of piston  350 . The sensor may be enabled to monitor and/or selectively take readings, such as pressure measurements during the downhole operations. 
     Spring  365  is positioned about the first portion  370  in a pocket  381  formed in chamber  355  between the second portion  375  of the piston and the walls of the chamber. As shown in  FIG. 3A , the spring is compressed in the pocket  381  between piston  350  and the chamber  355 . Pocket  381  is in fluid communication with the wellbore via conduit  390 . The chamber  355  is in fluid communication with the passage  215  ( FIG. 2 ) of the downhole tool. Optionally, an oil filled piston may be provided in conduit  397  to isolate the drilling mud from the pressure assembly  210   a  while still allowing the pressure therein to apply. 
     During drilling operation, mud flowing through the downhole tool creates an internal pressure P I  The internal pressure and borehole pressure P A  create a differential pressure. When fluid is flowing in passage  215 , the differential pressure increases and pressure is applied to the chamber  355 . A choke  240  ( FIG. 2 ) or similar device may be used to restrict or delay the passage of fluid through conduit  220  ( FIG. 2 ) thereby delaying the movement of the piston. Once sufficient pressure is created in chamber  355 , the internal pressure P I  applies a force against piston  350  as shown by the arrow. This internal pressure is greater than the annual pressure P A  and the force of spring  365  thereby causing the piston to move toward opening  385  in the stabilizer blade  314   a.    
     Fluid in pocket  381  may freely pass between the borehole and the pocket via conduit  390 . The first portion  375  of the piston compresses the spring  365 . Second portion  370  moves towards opening  385  and fills the passage  380 . Thus, while drilling fluid passes through the passage  215 , internal pressure generated therefrom applies a force to the piston  350  and moves it to the closed position. When the pressure assembly is in non-engagement with the borehole wall and mudcake, the sensor may take downhole readings of the wellbore, such as the annular pressure P A  of the wellbore. 
     As shown in  FIG. 3B , when the tool comes to a rest and fluid stops flowing through the tool, the internal pressure drops and the pressure differential between the internal pressure and the borehole pressure in this case falls to about zero. The internal pressure is no longer available to apply force to piston  350  and compress spring  365 , and the spring expands to its relaxed position. Expansion of the spring causes the piston to retract away from opening  385  and into the stabilizer blade. Fluid in cavity  355  may be expelled into passage  215  and/or borehole fluid may be drawn into chamber  381 . 
     Retraction of the piston into the stabilizer blade creates a small cavity  395  (typically of about 1 cc to about 3 cc) extending from the opening  385  and into the passage  380 . Pressure sensor  360  measures the pressure of the fluid in the cavity as the piston retracts into the tool. When in non-engagement with the wellbore wall, fluid from the borehole is permitted to fill the cavity  395 . In this position, the sensor may take or continue to take borehole measurements. However, when the pressure assembly is in engagement with the borehole wall  110 , retraction of the piston into the stabilizer blade will draw formation fluid into cavity  395  and provide formation data, such as pore or formation pressure. The flow of fluid into the cavity and the corresponding measurement may also be used to perform a pretest. Techniques for performing pretests are known by those of skill in the art and are described, for instance, in U.S. Pat. Nos. 4,860,581 and 4,936,139 issued to Zimmerman et al, both of which are assigned to the assignee of the present invention. 
     Once circulation of drilling fluid through the tool is re-initiated and sufficient differential pressure is present, the piston returns to the position of FIG.  3 A. In this manner, the pressure assembly may be used to take multiple downhole measurements. When fluid is flowing through the downhole tool, the piston moves to the closed position of  FIG. 3A  in preparation for the next test. When fluid flow ceases, the piston is released to the open position of FIG.  3 B and the draw-down cycle begins. The operation may be repeated as desired. Movement of the piston may be delayed by incorporating a choke into conduit  397  to restrict the flow out of chamber  355 . 
       FIGS. 4A and 4B  depict the pressure assembly  210   b  in greater detail.  FIG. 4A  depicts the pressure assembly  210   b  in the extended position.  FIG. 4B  depicts the pressure assembly  210   b  in the retracted position. A corresponding hydraulic control circuit  400  is depicted in schematic for each of these figures to further describe the operation of the pressure assembly in each position. 
     The pressure assembly  210   b  includes an internal pressure assembly  405  mounted within a probe assembly  410 . The probe assembly  410  includes a carriage  412 , a packer  414 , a spring  416  and a collar  417 . The carriage  412  is positioned in a chamber  418  in stabilizer blade  314   a  and is slidably movable therein. Seals  420  may be provided to seal the probe in the chamber and facilitate movement therein. Packer  414 , typically of an elastomer or rubber, is provided at an exterior end of the carriage  412  to facilitate sealing engagement with the borehole wall. Collar  417  is preferably threadably mounted within chamber  418  about an opening  415  in the stabilizer blade. The collar  417  encircles the carriage, and the carriage is slidably movable therein. Spring  416  encircles the carriage and is compressed in a pocket  419  between the collar  417  and a shoulder  422  of carriage  412 . A pocket  421  is formed between shoulder  422 , carriage  412  and the stabilizer blade  314   a.    
     The carriage  412  has an internal chamber  355   b  therein. The internal pressure assembly  405  is positioned in the internal chamber  355   b . Like pressure assembly  210   a  of  FIGS. 3A and 3B , the internal pressure assembly  405  includes a piston  350  and a spring  365 . The piston has a first portion  375  slidably movable within chamber  355   b , and a second portion  370  extending therefrom. The second portion  370  extends from the chamber  355   b  into a passage  380  and is slidably movable therein. The piston may be provided with seals to isolate various portions of the chamber from each other and/or from external mud contamination. The piston is preferably provided with a sensor  360  capable of taking downhole measurements. A spring  365  is positioned in chamber  355   b  about the first portion  370 . As shown in  FIG. 3A , the spring is compressed in a pocket  381  in the chamber  355   b  between the second portion  375  of the piston and the walls of the chamber. Pocket  381  is in fluid communication with chamber  418  via conduit  465 . The chamber  355   b  is in fluid communication with oil under pressure from the passage  215  of the downhole too via conduit  460 , pocket  419 , and conduits  448 ,  440 , and  442 . 
     The hydraulic control circuit  400  used to operate the pressure assembly  210   b  includes a low pressure compensator  424 , a high pressure compensator  426 , and an accumulator  428 . Hydraulic control circuit is preferably provided to allow selective activation or de-activation of the probe and/or pressure sensor assemblies. This additional control may be necessary in drilling, tripping or other situations where activation or de-activation of the pressure control assemblies is desired. The sensor(s) may be used to provide data to determine whether such a situation has occurred. 
     The compensators are preferably capable of accommodating volume changes caused by the pressure differences, temperature difference and/or movement of the downhole tool. The low pressure compensator  424  is operatively connected to chamber  418  in the stabilizer blade  314   a  via conduit  429 . The low pressure compensator has a slidable piston  433  forming a first variable volume chamber  430  and a second variable volume chamber  432 . The first chamber  430  is in fluid communication with the conduit  429 , and a second chamber  432  in fluid communication with the borehole (and/or the annual pressure P A  therein). 
     Accumulator  428  is operatively connected to conduit  429  via conduit  434 . The accumulator stores oil at high pressure, and may be used to increase pressure in chamber  421 . The accumulator has a spring-loaded piston  435  defining a first chamber  436  and a second chamber  438 . The first chamber  436  is in fluid communication with conduit  434  and conduit  429 . The second chamber  438  of the accumulator is connected via conduits  456 ,  440  and  442  to the high pressure compensator  426 ; via conduits  444  and  446  to the chamber  421 ; and via conduits  444 ,  460 ,  440  and  442  to pocket  419 . 
     The high pressure compensator  426  has a slidable piston  453  defining a first variable volume chamber  450  and a second variable volume chamber  452 . The first chamber  450  is in fluid communication with chamber  421  via conduits  442 ,  440  and  446 ; with the accumulator  428  via conduits  442 ,  440  and  456 ; and with pocket  419  via conduits  442 ,  440 , and  448 . A check valve  454  is positioned in conduit  456  to prevent fluid from flowing from second chamber  438  of accumulator  428  to conduit  440 . The second chamber  452  of high pressure compensator  426  is in fluid communication with passage  215  of stabilizer collar  300   a  ( FIG. 2 ) and the internal pressure P I  therein. 
     Various devices may be provided in the control circuit to monitor, manipulate and/or control the flow of fluid and/or the operation of the probe and/or pressure assemblies. Internal pressure sensor  490  may be provided to monitor the internal pressure in passage  425 . Annular pressure sensor  495  may be provided to monitor the annular pressure of the wellbore. Both pressure may also be monitored simultaneously via a differential pressure sensor (not shown). A choke  458  (or leak orifice, electrical controller or other restrictor) is preferably provided in conduit  460  to slow the flow of fluid through conduit  460  (ie. between the second chamber  438  of accumulator  428  and the high pressure compensator  426 ). A choke  462  is preferably positioned in conduit  460  to restrict and/or delay the flow of fluid out of chamber  355   b.    
     An electrical on-off switch (not shown) may also be provided to activate the hydraulic control circuit  400 . Once activated, no further signals are required to activate the system to perform tests. The system is capable of operating without activation. However, it is possible to add electronic controls and/or signals for communication with the system. One way to affect such activation is by incorporating an on/off switch into the hydraulic control system. An electrical on/off switch may be connected to the first chamber  430  of the low pressure compensator and/or the first chamber  450  of the high pressure compensator to send a signal to isolate the high pressure compensator from the system. In this case, the accumulator would not be charged and the differential pressure changes would no longer have an effect on the system. 
     In the position depicted in  FIG. 4A , the pressure assembly  210   b  is in the extended position. Fluid is no longer flowing through the downhole tool to create a differential pressure. The pressure of the fluid in second chamber  452  of high pressure compensator  426  is reduced and piston  453  can travel to reduce the size of chamber  452 . Corresponding chamber  450  increases and draws fluid out of pocket  419  and permits the spring  416  to retract thereby shifting carriage  412  out of blade  314   a . The loss of internal pressure in chamber  452  also causes fluid in accumulator chamber  438  to be expelled into conduit  444 . Most of the fluid in conduit  444  flows via conduit  446  into pocket  421  thereby placing force against shoulder  422  to move the carriage outward from the stabilizer blade. Some fluid is permitted to flow through conduit  460  and into conduit  440 . However, choke  458  restricts the flow of fluid therethrough and only allows a limited bleed off of this fluid. 
     As fluid in accumulator chamber  438  is expelled, the piston  435  moves and expands chamber  436 . Fluid is drawn from chamber  430  of low pressure compensator  433  into chamber  436  via conduits  434  and  429 . Fluid in chamber  430  is also permitted to flow via flowline  429  into chamber  418 . 
     The internal pressure assembly  405  is also movable within the probe assembly  410  between an open, or testing, position as depicted in  FIG. 4A , and a closed position as depicted in FIG.  4 B. As shown in  FIG. 4A , when the tool comes to a rest and fluid stops flowing through the tool, the pressure in chamber  355   b  drops with the reduction in pressure differential between the internal pressure and the borehole pressure. The pressure in chamber  355   b  releases through conduit  460  into pocket  419 . As the pressure in chamber  355   b  decreases, the force of the spring  365  pushes the piston into chamber  355   b . A choke may be provided to restrict the flow through conduit  465  to provide a delay, if desired. The fluid in pocket  381  is in fluid communication with chamber  418  via conduit  465 . Flow into pocket  418  is preferably slow and delayed such that the probe assembly is fully extended from blade  314   a  before piston  350  travels. 
     Retraction of the piston into the collar creates a cavity  395  (typically of about 1 cc to about 3 cc) extending from an opening  385  and into the passage  380 . Fluid from the formation is permitted to fill the cavity  395  when a seal is formed between the packer  414  and the formation. Pressure sensor  360  is preferably positioned adjacent the cavity to measure the pressure of the fluid in the cavity as the piston retracts into the tool. A pretest and/or other measurements may then be taken to determine various downhole properties of the surrounding formation. 
     The movement of the internal pressure assembly  405  and the probe assembly  410  may be manipulated such that movement occurs at the desired time. For example, the choke may be used to delay the flow of fluid and the corresponding retraction of the internal pressure assembly to allow sufficient time for a seal to form between the probe assembly and the borehole wall. Other variations to the circuitry may be envisioned to provide selective flow of fluid through the circuit and manipulate the operation of the pressure assembly. 
     Once the spring accumulator  428  has fully expanded, oil/pressure from chamber  438  bleeds off through conduits  444 ,  460 ,  440 , and  442  into chamber  450 . The pressure in conduit  446  continues to drop until it reaches the ambient hydrostatic pressure. The spring  416  retracts the probe assembly back into blade  314   a  and completes the cycle. Piston  350  is in its open, or testing position, and the process may be repeated. 
       FIG. 4B  depicts pressure assembly  210   b  during a charge cycle operation of the downhole tool. When fluid is pumped through internal passage  215 , it creates a higher internal pressure P I  with respect to the annular pressure thereby creating a differential pressure. This differential pressure forces piston  453  to expand chamber  452  and reduce chamber  450 . Fluid is expelled from chamber  450  into chamber  428  via conduits  442 ,  440  and  456 . Fluid is also expelled from chamber  436  and into chamber  430  via conduits  434  and  429 . The flow of fluid into chamber  430  causes fluid in chamber  432  to be expelled into the borehole. 
     Fluid also flows from chamber  450  into chamber  355   b  via conduits  442  and  448 , pocket  419 , and conduit  460 . The flow of fluid into chamber  355   b  overcomes the force of the spring  365  and causes the piston to move toward opening  385 . The spring  365  is compressed in pocket  381  between the second portion  375  and the walls of the chamber. Fluid is released from pocket  381  via conduit  465  to chamber  418  and back to chamber  430  via conduit  429 . The first portion  375  of the piston is pressed against the spring  365 , and the second portion, or rod,  370  fills the passage  380 . The internal pressure assembly  405  is now charged to perform the next pressure measurement. 
     Referring now to  FIGS. 5A and 5B , the electronic details for the pressure assembly is shown in greater detail.  FIG. 5A  depicts an overlapping communication coil embodiment, and  FIG. 5B  depicts a back-to-back coil embodiment. The sensor  360  is preferably a small sensor, such as a MEMS sensor, positioned on an outer end of the piston  350  adjacent opening  385  in the passage  380 . The sensor is preferably capable of measuring various downhole parameters, such as pressure, temperature, viscosity, permeability chemical composition, H2S, and/or other downhole parameters. Hermetical seals may be provided to seal the sensor in the end of the piston. The seals may be provided to reduce the required test volume in cavity  395  to achieve the desired measurements. Contacts are provided between the sensor and the tool via hermetically sealed feed-through to the tool electronics. 
     The tool electronics preferably provide power for and/or communication with the sensors. In  FIG. 5A , the overlapping communication coil embodiment includes a sensor coil  500  and a transmission coil  505 . The sensor coil  500  is preferably positioned in the first portion  375  of piston  350 . The transmission coil  505  is preferably positioned in about chamber  355 . At least a portion of the sensor and/or transmission coils are preferably made of a non-conductive material, such as a ceramic. 
     A magnetic field is B created between sensor coil  500  and transmission coil  505 . The field enables a wireless coupling between the sensor coil and transmission coil. Power and data transfer is provided to the sensor through the wireless coupling. However, a wired coupling is used to create a link between the pressure assembly electronics and the electronics in the remainder of the tool as depicted by the curled arrow. The transmission coil preferably overlaps with the sensor coil, but is independent of the sensor position within chamber  355 . 
     The back-to-back coil embodiment of  FIG. 5B  includes a sensor coil  550   a , a transmission coil  555   a  and a ceramic window  560 . The sensor coil  500   a  is preferably positioned in the first portion  375  of piston  350 . The ceramic window  560  is preferably positioned on an internal wall of chamber  355 . The transmission coil  505   a  is preferably positioned in the drill collar adjacent the ceramic window. 
     A magnetic field Ba is created between sensor coil  500   a  and transmission coil  505   a  through ceramic window  560 . A field provides a wireless connection between the sensor coil and transmission coil. Power and data transfer is provided to the sensor through the wireless coupling. In this embodiment, a wireless coupling may also be used to create a link between the pressure assembly electronics and the electronics in the remainder of the tool. 
     This embodiment eliminates the need for wires for the sensor and the surrounding threaded cup. One or more non-metallic ceramic windows may be positioned between the sensor coil and the transmission coil to allow coupling therethrough. The mechanical assembly eliminates the need for feed-throughs for the coil wire. Instead the-metallic window(s) between the sensor and the host transmission coil are provided. The windows allow coupling between the two coils. While the depicted embodiments eliminate wired connections and/or feed-throughs, some embodiments may incorporate such items. 
       FIG. 6  depicts an electronic block diagram for operation of the pressure assemblies. One or more pressure assemblies having pressure sensors  360  therein are used to collect downhole data. The sensors are linked to the downhole electronics either through a wireless link as depicted in  FIG. 5A , or wirelessly as depicted in FIG.  5 B. Power and/or communication signals are distributed and protected using distribution device  700 . The signals pass through preamplifiers  705  and demodulators  710  and are sent to a controller  715  for processing. Signals may also be collected from one or more sensors, such as internal pressure sensor  490  and/or an annular pressure sensor  495 , and processed in the controller. The controller may be used to analyze, collect, sort, manipulate and/or otherwise process the data. The data may be sent to the surface via a mud telemetry interface  720 . Signals may also be sent downhole via the mud telemetry interface to the controller. 
     A battery  725  may be included to provide power to the controller and/or to the sensors. The battery delivers power to a power amplifier  730 . The power signal is passed through the signal distribution and protection device to the pressure sensor(s)  360 . The power signal can be used to provide power to the sensor(s). 
     While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. For example, embodiments of the invention may be easily adapted and used to perform specific formation sampling or testing operations without departing from the spirit of the invention. Accordingly, the scope of the invention should be limited only by the attached claims.