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CROSS-REFERENCE TO RELATED APPLICATIONS 
   The present application claims the benefit of U.S. Provisional Application Ser. No. 60/381,258, filed May 17, 2002, entitled Method and Apparatus for MWD Formation Testing, which is hereby incorporated herein by reference. 

   STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
   Not applicable. 
   BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   This invention relates generally to a method and apparatus utilized in hydrocarbon exploration. More specifically, the invention relates to formation testing tools. Even more particularly, the present invention is directed to methods and apparatus for performing formation testing while drilling. 
   2. Background and Related Art 
   Geologists and geophysicists are interested in the characteristics of the formations encountered by a drill bit as it is drilling a well for the ultimate production of hydrocarbons from the earth. Such information is useful in determining the correctness of the geophysical data used to choose the drilling location and in choosing subsequent drilling locations. In horizontal drilling, such information can be useful in determining the location of the drill bit and the direction that drilling should follow. 
   Such information can be derived in a number of ways. For example, cuttings from the mud returned from the drill bit location can be analyzed, or a core can be bored along the entire length of the borehole. Alternatively, the drill bit can be withdrawn from the borehole and a “wireline logging tool” can be lowered into the borehole to collect data or otherwise determine formation characteristics. In still another approach, called “measurement while drilling” (“MWD”) or “logging while drilling” (“LWD”), tools are included in the drill string that collect formation data while the drill bit remains in the borehole. 
   One type of formation testing tool measures formation pressure, which can be used for a variety of purposes, including computing the permeability and porosity of the formation. A conventional such formation testing tool operates in the wireline environment. It is lowered into the well to a depth where formation testing is desired. Before the wire line tool can be lowered, however, the entire drill string must be removed from the borehole. This process, known as “tripping” is a laborious and time consuming process by which the drill string, which may be miles long, is removed from the hole, pipe section by pipe section. After the formation tester has been lowered to the appropriate depth by means of a wireline, the borehole interval adjacent to the tester must be packed off and isolated from the drilling fluid that remains in and fills the borehole so that accurate reading of the formation pressure can be obtained. With the pressure recorded, the tool is retrieved to the surface for analysis and the drill string is then reassembled and replaced in the borehole, section by section. As well be understood, conducting formation tests via a wireline tool is time consuming and costly, given that costs of drilling a well may be thousands of dollars per hour. 
   As mentioned above, testing the formation using a tester incorporated into the drill string is desirable in that the drill string does not need to be removed to conduct the test. However, there are various complications associated with conventional such apparatus. For example, in certain such testers, the flow of drilling fluid must be stopped in order to measure the formation pressure or take a sample of the formation fluid. When this occurs, without the flow of constantly moving drilling fluid, the bottom hole assembly can become stuck in the hole, necessitating a costly and time consuming procedure to free the stock tool. Furthermore, mud turbine generators are sometimes employed in the bottom hole assembly as the means of supplying electrical power needed to actuate the formation tester. In such tools, stopping the flow of drilling fluid therefore prevents the tool from generating the needed electrical power, and power to operate the formation tester must be supplied by other means, such as batteries which, in certain instances, may be less reliable or otherwise less desirable. Other problems and shortcomings are associated with present day formation testers. 
   For example, certain conventional formation testers employ a extendible probe that extends from the tool to engage the borehole wall in order to conduct the fluid test or sampling. In certain instances, however, particularly when drilling a horizontal well, the orientation of the tool may be such that the probe extends out of the tool on the low side of the hole. When this occurs, the extending probe may be subjected to detrimental loading as the piston extends and contacts the borehole. Further, there are many instances during which the extending probe will engage the borehole wall at an angle, rather than being normal to the wall. When this occurs, the seal necessary for properly extracting and measuring formation fluid pressure is difficult, if not impossible, to achieve. 
   Accordingly, there remains a need in the art for a formation testing apparatus that may be employed in a drill string to conduct reliable formation testing. Ideally, such apparatus would not require that the flow of drilling fluid be cut off so as to prevent the bottom hole assembly from sticking to the borehole and permit the formation tester to be powered by the flow of drilling fluid. Further, it would be preferable if the sensed data and other measurements could be communicated to the surface via mud pulse telemetry, which relies on the flow of drilling fluid. A formation tester that insures that an extending probe contacts the borehole wall substantially normal to the wall, rather than at an angle, and which protects the probe from excessive bending moments and other excessive forces would be particularly welcomed by the industry. 
   BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS OF THE INVENTION 
   In accordance with the spirit of the present invention, a novel formation testing tool is described herein. One property of the present formation testing tool is that an extending probe or sample device contacts the borehole wall substantially normal to the wall, protecting the probe from excessive bending moments and other excessive forces. 
   Several embodiments are disclosed as being illustrative of the spirit of the invention. For example, in one embodiment, the formation testing tool includes a longitudinal body with a flowbore; a plurality of extendable centralizing pistons coupled to the body; an extendable sample device coupled to the body; and a centralizing hydraulic circuit configured to cause each of the plurality of centralizing pistons to extend at substantially the same rate. The centralizing pistons are extended at substantially the same rate to assist in positioning the extending sample probe such that it is substantially normal to the borehole wall. The centralizing hydraulic circuit includes a series of flow control and pressure-determining valves configured to extend the centralizing pistons at substantially the same rate, and to help maintain stability in the hydraulic circuit in response to external pressures. The circuit also includes a controller for operating and managing the valves and pistons. The extendable sample device is preferably configured to be recessed beneath the surface of the body in a first position and to extend beyond the surface in a second position. 
   Methods of use for the formation testing tool are also described herein. For example, a method for formation testing comprising includes extending at substantially the same rate a plurality of centering pistons from a formation testing tool; centering the formation testing tool in a borehole; and testing the formation. These and other embodiments of the present invention, as well as their features and advantages, will become apparent with reference to the following detailed description. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which: 
       FIG. 1  is a schematic view, partially in cross-section showing a well being drilled including a bottom hole assembly that includes a formation testing tool of the preferred embodiment; 
       FIG. 2  is an elevation view, partially in cross-section of the formation testing tool of  FIG. 1 ; 
       FIG. 3  is an elevation view of the formation testing tool of  FIG. 2 ; 
       FIGS. 4 ,  5 ,  6 ,  7  and  8  are cross sectional views along lines A—A shown in  FIG. 3  of the formation testing tool of  FIG. 3 ; 
       FIG. 9A  is a schematic of a hydraulic circuit of the centralizer pistons of the formation testing tool of  FIG. 3 ; 
       FIG. 9B  is a flow chart showing the preferred sequence of operation of the formation testing tool of  FIG. 3 ; 
       FIGS. 10 and 11  are cross sectional views along lines B—B shown in  FIG. 3  of the formation testing tool of  FIG. 3 ; 
       FIG. 12  is a schematic of a hydraulic circuit of the seal piston and drawdown piston of the formation tester of  FIG. 3 ; and 
       FIG. 13  is a flow chart showing the preferred sampling sequence for the formation tester of  FIG. 3 . 
   

   NOTATION AND NOMENCLATURE 
   In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus are to be interpreted to mean “including, but not limited to . . . ”. Reference to up or down will be made for purposes of description with “up,” “upward,” or “upper” meaning toward the surface of a well and “down,” “downward,” or “lower” meaning toward the bottom of a well. In addition, the term “couple,” “couples,” or “coupled” is intended to mean either an indirect or a direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect electrical or fluid connection via other devices and connections. 
   This exemplary disclosure is provided with the understanding that it is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. In particular, various embodiments of the present invention provide a number of different constructions and methods of operation. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. 
   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
   Referring to  FIG. 1 , a drilling rig  10  (simplified to exclude items not important to this application) comprises a derrick  12 , derrick floor  14 , draw works  16 , hook  18 , swivel  20 , kelly joint  22  and rotary table  24 , such components being arranged in a conventional manner so as to support and impart rotation to drillstring  26 . Drill string  26  includes at its lower end a bottom hole assembly  29  which comprises drill collar  28 , MWD tool  30  (which may be any kind of MWD tool, such as an acoustic logging tool), MWD formation testing tool  32  (which may be a separate tool as shown or may be incorporated into another tool) and drill bit  34 . A description of exemplary MWD tools and MWD formation testing tools may be found in the provisional Patent Application No. 60/381,243 filed May 17, 2002, entitled Formation Tester, and in the patent application filed concurrently herewith via Express Mail No. EV324573681US and entitled MWD Formation Tester, which claims priority to the previously referenced provisional application, both applications hereby incorporated by reference herein for all purposes. Drilling fluid (which may also be referred to as “drilling mud”) is injected into the swivel by a mud supply line  36 . The mud travels through the kelly joint  22 , drillstring  26 , drill collars  28 , MWD tool  30  and MWD formation testing tool  32  and exits through ports in the drill bit  34 . The mud then flows up the borehole  38 . A mud return line  40  returns mud from the borehole  38  and circulates it to a mud pit (not shown) and ultimately back to the mud supply line  36 . 
   The data collected by the MWD tool  30  and formation testing tool  32  is returned to the surface for analysis by telemetry transmitted in any conventional manner, including but not limited to mud pulse telemetry, or EM or acoustic telemetry. For purposes of the present application, the embodiment described herein will be explained with respect to use of mud pulse telemetry. A telemetry transmitter  42  located in a drill collar  28  or in one of the MWD tools collects data from the MWD tools and transmits it through the mud via pressure pulses generated in the drilling mud. A telemetry sensor  44  on the surface detects the telemetry and returns it to a demodulator  46 . The demodulator  46  demodulates the data and provides it to computing equipment  48  where the data is analyzed to extract useful geological information. 
   Further, commands may be passed downhole to the MWD tool and formation testing tool  32  in a variety of ways. In addition to the methods described in the previous paragraph, information may be transmitted by performing predefined sequences of drill pipe rotations that can be sensed in the MWD tools and translated into commands. Similarly, the mud pumps may be cycled on and off in predefined sequences to transmit information in a similar fashion. 
   The formation testing tool  32  includes a plurality of centralizing pistons  60  and one or more sampling pistons  62 , as shown in  FIG. 2 . For present purposes, the formation testing tool will be described with reference to tool  32  having one sampling piston  62 , it being understood that the tool could likewise be configured to include additional such pistons  62 . The plurality of centralizing pistons  60  centralize the formation testing tool  32  in the borehole  38 . Once the formation testing tool  32  is centralized, the sampling piston  62  extends from the formation testing tool  32  to the borehole wall  66 , where it seals against the wall and allows formation testing to be performed. 
   In one embodiment of the formation testing tool  32 , the centralizing pistons  60  are all in the same cross section and the sampling piston  62  is in a different cross section. In another embodiment, one or more of the centralizing pistons  68  are in a different cross-section from the remaining centralizing pistons  60 . In still another embodiment, the centralizing pistons are in three or more cross sections. 
   During drilling operations, the centralizing pistons  60  and the sampling piston  62  are retained in a retracted position inside the formation testing tool  32 , as shown in  FIG. 3 . In this position, the sampling piston  62  is recessed below the surface of the formation testing tool  32 , as is discussed further below. When it is time to perform the formation testing function, the rotation of the drill string  26  is ceased and the centralizing pistons  60  are extended at the same rate so that the formation testing tool  32  is relatively centralized within the borehole, as shown in  FIG. 2 . The sampling piston  62  is then extended and the formation testing tool  32  performs its testing function. 
   The formation testing tool  32  is centralized before the sampling piston  62  is extended for several reasons. Centering the formation testing tool  32  in the borehole improves the likelihood that the sampling piston  62  will only have to be partially extended to reach the borehole wall  66 . The sampling piston  62  is less vulnerable to bending when it is partially extended than when it is fully extended. This is especially important in MWD applications in which torque or axial loads may be inadvertently applied to tool  32 . Further, centering the formation testing tool  32  increases the likelihood that the sampling piston will be normal to the borehole wall rather than at an angle, which improves the conditions for sealing the piston against the borehole wall. Still further, centralizing the tool  32  in the borehole maximizes the size of the borehole that can be sampled with a given centralizing piston length. The short distance that the centralizing pistons  60  need to be extended allows more room in the drill collar for fluid flow through the flowbore of the tool. Preferably, the tool  32  will operate while drilling fluids remain circulating in borehole  38  which will minimize the possibility of the tool assembly sticking, allow data to be transmitted to the surface for real-time examination and decision making, and allow the centralizing and sampling pistons to be powered by a mud turbine generator which require the continuous flow of drilling fluid to operate. 
   The formation testing tool&#39;s  32  centering apparatus is illustrated in  FIG. 4 . In the embodiment illustrated in  FIG. 4 , the formation testing tool  32  includes three centralizing pistons  72 ,  74  and  76 . It will be understood that tool  32  can include any number of centralizing pistons that accomplish the functions described below. A flowbore  78  through the center of the formation testing tool  32  allows drilling mud to flow through the tool to the-drill bit  34  at the end of the drill string  26  ( FIG. 1 ). Flowbore  78  is preferably centralized in formation testing tool  32  but may be offset from the axis of the tool  32 . Hardfacing  80  is coupled to portions of the tool  32  to prevent damage to the tool during drilling operations. 
     FIG. 5  shows the formation testing tool  32  in the borehole  38  after the drill string has stopped rotating. An annulus  92  is formed between tool  32  and the borehole wall  66 . As can be seen in  FIG. 5 , the formation testing tool  32  has stopped in a position in which it is not aligned with the center of the borehole. Centralizing piston  72  is close to the borehole wall  66 , while the other pistons  74  and  76  are some distance away from the wall. 
   The centralizing process begins as shown in  FIG. 6 . The three centralizing pistons  72 ,  74  and  76  begin to extend from the formation testing tool  32 . The centralizing pistons  72 ,  74  and  76  extend at the same rate. The rate of extension may vary from moment to moment but the rate of extension for one piston at a given moment in time is substantially, i.e., within that allowed by tolerances, the same as the rate of extension of the other two pistons. Consequently, the three pistons  72 ,  74  and  76  will extend the same amount from the formation testing tool  32  at any given moment in time. Given its position relative to borehole wall  66 , piston  72  pushes the formation testing tool  32  away from the borehole wall  66 . The other pistons  74  and  76  have not yet contacted the borehole wall and, therefore, have no effect. 
   The centralizing process continues, as shown in  FIG. 7 , with the centralizing pistons  72 ,  74  and  76  continuing to extend, all at the same rate. As shown in  FIG. 7 , piston  72  has pushed the formation testing tool  32  far enough that piston  74  has come into contact with the borehole wall. Piston  76  has not yet contacted the borehole wall. 
   The final position is illustrated in  FIG. 8 . All of the centralizing pistons  72 ,  74  and  76  are in contact with the borehole wall and, because they extended at the same rate, they extend the same distance from the formation testing tool  32 . Consequently, the formation testing tool  32  is centered in the borehole. 
   The hydraulic circuit that accomplishes the centering function is schematically illustrated in  FIG. 9A . A controller  82  is connected to all of the controllable elements in the hydraulic circuit illustrated in  FIG. 9A  and in hydraulic circuits described below. The connections to the controllable elements are conventional and are not illustrated. Controller  82  is located in MWD tool  30 , or in formation testing tool  32 , or elsewhere in bottom hole assembly  29  ( FIG. 1 ). The sequence of operations coordinated by the controller  82  is illustrated in  FIG. 9B . 
   The controller  82  detects control signals, transmitted from the surface in one of the formats described above, ordering the formation testing tool  32  to conduct a formation test (block  138  in  FIG. 9B ). When it receives the command, the centralizing pistons  60  and the sampling piston  62  are in their withdrawn positions, as shown in  FIG. 3 . The drillstring has stopped rotating. 
   The controller  82  orders the motor  84  to begin to rotate (block  140  in  FIG. 9B ). The motor  84  can be an electric motor or a mud turbine or any other source of energy. The motor  84  is coupled to a pump  86  and causes pump  86  to draw hydraulic fluid out of a hydraulic reservoir  88  through a serviceable filter  90 . The pressure of hydraulic reservoir  88  is approximately equal to the pressure in the annulus  92  between the tool  32  and the wall of the borehole through the use of a pressure balance piston  250  (shown in  FIGS. 9A and 12 ). 
   The pump  86  directs the hydraulic fluid into hydraulic circuit  100  that includes extend solenoid actuated valve  94 , retract solenoid actuated valve  96 , relief valve  98  and differential pressure transducer  99 . The relief valve  98  prevents damage to the hydraulic circuit  100  and provides other functions as described below. The electrical output of pressure transducer  99  is coupled to the controller  82  and allows the controller  82  to monitor pressure in hydraulic circuit  100  and control the progress of the formation testing operation, as described below. 
   The controller  82  actuates (or “opens”) the extend solenoid actuated valve  94  (block  142  in  FIG. 9B ). Prior to being actuated, in its “normal” position, valve  94  has its control port (C) connected to its tank port (T), the position shown in  FIG. 9A . Upon actuation by controller  82 , its control port (C) connects to its pump port (P). In this position, hydraulic fluid flows from the pump  86  to three pressure compensated flow control valves (FCVs)  102 ,  104  and  106 . Each FCV has the characteristic that, when the pressure on its output side is between a minimum value and a maximum value (e.g., between 200 and 3000 p.s.i.), fluid flows from its output side at a constant rate. Thus, for the range of operation between 200 and 3000 p.s.i., then the flow rate from the FCVs will be the same when the pressure on their output sides is, for example, 250 p.s.i. as it will when the pressure is, for example, 2550 p.s.i. 
   The hydraulic fluid flows through the FCVs  102 ,  104  and  106  to pilot control valves (PCVs)  108 ,  110  and  112 , respectively. The PCVs  108 ,  110  and  112  act as check valves to prevent the reverse flow of hydraulic fluid until the pressure applied to their pilot ports (shown on  FIG. 9A  as dotted lines  114 ,  116  and  118 ) exceeds a predetermined amount, at which time they allow fluid flow in either direction. 
   The hydraulic fluid flows through the PCVs  108 ,  110  and  112  to relief valves  120 ,  122  and  124  and to the extend sides of centralizer pistons  72 ,  74  and  76 , respectively. Centralizer pistons  72 ,  74  and  76  are identified to pistons  60  previously described. The relief valves open at a predetermined pressure (for example 5000 p.s.i., as shown in  FIG. 9A ), providing a safety function. The centralizer pistons  72 ,  74  and  76  attempt to move under the pressure exerted by the hydraulic fluid on their extend sides shown as  72   e ,  74   e ,  76   e , respectively. 
   The retract side of the centralizer pistons  72 ,  74  and  76  ( 72   r ,  74   r  and  76   r ) are connected together, as shown at point  130  in  FIG. 9A , and are connected through a parallel-connected relief valve  132  and check valve  134  to the retract solenoid actuated valve  96 , which has been left in its normally-closed position with the common (C) connected to the tank (T). The check valve  134  prevents the hydraulic fluid from flowing from the retract sides of the centralizer pistons  72 ,  74  and  76  through its branch of the parallel hydraulic circuit. The relief valve  132  is sized to prevent hydraulic fluid from flowing from the retract side of the centralizer pistons  72 ,  74  and  76  until the pressure impinging on the relief valve  132  is within the operating range of the FCVs  102 ,  104  and  106 . For the example shown in  FIG. 9A , the relief valve  132  is sized to open at 200 p.s.i., which is within the operating zone of the FCVs  102 ,  104  and  106 . 
   Since the relief valve  132  opens at a pressure within the operating range of the FCVs  102 ,  104  and  106 , fluid from each of the FCVs will flow at the same rate to the extend side of the centralizer pistons  72 ,  74  and  76 , respectively. Consequently, the three centralizer pistons will begin to extend at the same rate. Even when one or two of the pistons encounter resistance, such as when one or two of the pistons press against the borehole wall as shown in  FIGS. 6 and 7 , all three pistons will continue to extend at the same rate. 
   When all three centralizer pistons  72 ,  74  and  76  meet resistance, or when all three are fully extended, the pressure in the hydraulic circuit  100  will begin to climb. When it reaches a predetermined value, for example, 3000 p.s.i. as shown in  FIG. 9A , relief valve  98  will open and the pressure in the hydraulic circuit  100  will stabilize. 
   The controller  82 , which has been monitoring the pressure in the hydraulic circuit through transducer  99  (block  144  in  FIG. 9B ), detects the pressure stabilization caused by the opening of the relief valve  98 . The extend solenoid actuated valve  94  remains energized so that if the tool  32  shifts, hydraulic pressure will be available to adjust the positions of the centralizer pistons  72 ,  74  and  76  to account for the shift and to “recentralize” the tool. 
   Now that the centralizer pistons  72 ,  74  and  76  are extended, the formation testing tool  32  is ready to begin its sampling operations. The sampling piston  62 , illustrated in  FIG. 10 , includes a seal piston  166  and a draw down chamber  168  inside and axially aligned with the seal piston  166 . When the seal piston  166  and draw down chamber  168  are retracted into the tool  32 , as shown in  FIG. 10 , they are recessed below the surface of the tool  32 . In particular, the top of the seal piston  166  is beneath a straight line  170  connecting the low points  172  and  174  in the opening in the collar  176  provided for the sampling piston. 
   To perform the formation testing operation, the seal piston  166  is first extended to seal against the borehole wall  66 , as shown in  FIG. 11 . The centralizer pistons  72 ,  74  and  76  keep the formation testing tool  32  stable during this step which reduces the possibility of damage to the seal piston  166  as it is being extended. The draw down chamber  168  extends slightly into the mudcake formed on the borehole wall  66 , thereby improving the seal between the tool and the wall of the  66  borehole  38 . The purpose of the seal piston  166  is to seal against the borehole wall  66  so that the draw down chamber  168  can determine the pressure in the formation without being influenced by the pressure in the annulus  92  (such as drilling mud). The seal piston  166  and draw down chamber  168  are preferably separate from the centralizing pistons  72 ,  74  and  76  because the centralizing pistons  72 ,  74  and  76  may slip along the borehole wall  66  during centralizing. Such slipping might damage the seal piston  166  and prevent it from operating as required. 
   Once the seal piston  166  has extended, as shown in  FIG. 11 , the draw down chamber  168  is activated to withdraw fluids from the formation. In one embodiment, the withdrawn fluids are stored within the tool  32 . After the fluid sample has been withdrawn from the formation and the formation fluid pressure has been measured, the seal piston  166  and draw down chamber  168  are then withdrawn back into the tool  32 . 
   The hydraulic circuit  101  used to control the seal piston  166  and the draw down chamber  168  is illustrated in  FIG. 12 . The motor  84 , pump  86 , reservoir  88 , filter  90 , relief valve  98  and transducer  99  perform the same functions as the items bearing the same reference numbers in  FIG. 9A . Preferably, the two hydraulic circuits  100 ,  101  are independent and employ separate motors, pumps, hydraulic reservoirs, filter, relief valve and pressure transducer. Alternatively, they may be combined to share the same such components. 
   The controller  82  actuates seal piston extend solenoid actuated valve  180  causing its control port (C) to be connected to its pump port (P) (block  146  in  FIG. 9B ). Hydraulic fluid flows through the seal piston extend solenoid actuated valve  180  and through check valve  182  to the extend side  166   e  of the seal piston  166  causing it to extend. When the seal piston  166  has extended to the point where it is sealed against the formation wall  66  (or it is fully extended) and it is no longer moving, the pressure within the hydraulic circuit  101  begins to increase. When the pressure reaches, for example, 3000 p.s.i., the relief valve  98  opens and releases hydraulic fluid from the hydraulic circuit into the reservoir  88 . The check valve  182  prevents hydraulic fluid from draining from the seal piston  166  and keeps it sealed against the borehole wall. When the controller  82 , through pressure transducer  99 , detects the pressure in the hydraulic circuit stabilizing because of the opening of the relief valve  98  (block  148  in  FIG. 9B ), controller  82  activates the draw down chamber  168 . The controller  82 , which has been monitoring the pressure in the hydraulic circuit, does not deactivate the seal piston extend solenoid actuated valve  180  because if, for example, the tool  32  shifts so that the seal piston requires more hydraulic fluid to remain sealed against the borehole wall, the hydraulic fluid is available through seal piston extend solenoid actuated valve  180 . 
   To activate the draw down chamber  168 , the controller  82  activates a draw down chamber retract solenoid controlled valve  184 , causing its control port (C) to be connected to its pump port (P) (block  150  in  FIG. 9B ). Hydraulic fluid flows through the draw down chamber retract solenoid controlled valve  184  and into the retract side  168   r  of the draw down chamber  168 , causing the draw down chamber to retract. As a draw down chamber piston  188  within the draw down chamber  168  retracts, a pressure transducer  190  measures the pressure in the formation fluid. The pressure transducer  190  sends the pressure data to the controller  82  which sends it to the surface for analysis and/or records it. The controller  82  may also analyze the data collected and record the results and/or send the results to the surface. 
   The draw down chamber piston  188  stops moving when it has fully withdrawn and pressure within the hydraulic circuit  101  begins to increase. When the pressure reaches 3000 p.s.i., relief valve  98  opens and releases hydraulic fluid from the hydraulic circuit  101  into the reservoir  88 . When the controller  82 , which has been monitoring the pressure in the hydraulic circuit through transducer  99  (block  152  in  FIG. 9B ), detects a stabilization of the pressure in the hydraulic circuit  101 , it deactivates the draw down chamber retract solenoid controlled valve  184  (block  154  in  FIG. 9B ). 
   At the same time, the controller  82  activates a draw down chamber extend solenoid controlled valve  186 , causing its control port (C) to be connected to its pump port (P) (block  154  in  FIG. 9B ). Hydraulic fluid flows through the draw down chamber extend solenoid controlled valve  186  and into the extend side  168   e  of the draw down chamber  168 , causing the piston  188  in the draw down chamber to extend. As the draw down chamber piston  188  within the draw down chamber  168  extends, it drives the formation fluid from the draw down chamber  168  through the central passageway of the seal piston  166  and into the annulus. Alternatively, the fluid may be driven into storage receptacles (not shown) for later analysis on the surface. The additional valves required to implement such a storage system are conventional and are not illustrated in  FIG. 12 . 
   The draw down chamber piston  188  stops moving when it has fully extended and pressure within the hydraulic circuit  101  begins to increase. When the pressure reaches, for example, 3000 p.s.i., relief valve  98  opens and releases hydraulic fluid from the hydraulic circuit  101  into the reservoir  88 . When the controller  82 , which has been monitoring pressure through transducer  99  (block  156  in  FIG. 9B ), detects a stabilization of pressure in the hydraulic circuit  101 , it activates the seal piston retract solenoid controlled valve  187  and closes the seal piston extend solenoid controlled valve  180  (block  158  in  FIG. 9B ). Hydraulic fluid flows through the seal piston retract solenoid controlled valve  187  and into the retract side  166   r  of the seal piston  166 . The seal piston  166  is prevented from moving by the presence of the check valve  182 , which prevents hydraulic fluid from flowing out of the extend side  166   e  of the seal piston  166 . When the pressure on the retract side  166   r  of the seal piston reaches a predetermined level, the pilot port of the check valve  182  causes it to open which allows the seal piston  166  to move. When the seal piston has fully retracted, the pressure in the hydraulic circuit  101  increases until the relief valve  98  actuates. The pressure in the hydraulic circuit  101  then stabilizes. 
   Referring again to  FIG. 9A , the controller  82 , which has been monitoring the pressure in the hydraulic circuit (block  159  in  FIG. 9B ), actuates the retract solenoid actuated valve  96 , which causes its control port (C) to be connected to its pump port (P) (block  160  in  FIG. 9B ). At the same time, the controller deactivates the extend solenoid actuated valve  94  (block  160  in  FIG. 9B ). Hydraulic fluid flows through the retract solenoid actuated valve  96 , through check valve  134  and to the retract side of the centralizer pistons  72 ,  74  and  76 . At first, the centralizer pistons  72 ,  74  and  76  cannot move because the PCVs  108 ,  110  and  112  prevent hydraulic fluid from flowing out of the extend side of the centralizer pistons  72 ,  74  and  76 . Consequently, the pressure on the retract side of the centralizer pistons  72 ,  74  and  76  increases. At a predetermined pressure, the pilot ports  114 ,  116  and  118  of the PCVs  108 ,  110  and  112 , respectively, cause the PCVs to open and allow hydraulic fluid to flow out of the extend side of the centralizer pistons  72 ,  74  and  76 , through the FCVs  102 ,  104  and  106 , respectively, through the extend solenoid actuated valve  94  and into the hydraulic reservoir  88 . Consequently, the centralizer pistons  72 ,  74  and  76  will begin to retract. 
   When the centralizer pistons  72 ,  74  and  76  have fully retracted, the pressure in the hydraulic circuit  100  will begin to increase, and when it reaches, for example, 3000 p.s.i., the relief valve  98  will open causing the pressure to stabilize. The controller  82 , which has been monitoring pressure in the hydraulic circuit through the transducer  99  (block  162  in  FIG. 9B ), will detect that the pressure has stabilized and will turn the motor  84  off and return all valves to their original conditions (block  164  in  FIG. 9B ). The tool  32  is now back in its original condition. 
   The hydraulic circuit  100  illustrated in  FIG. 9A  also includes a fail-safe feature. The control port of a fail-safe solenoid actuated valve  136  is connected to the extend side of the centralizer pistons  72 ,  74  and  76 . In its normal, unactuated position, the control port (C) is connected to its tank port (T). When it is time to extend the centralizer pistons  72 ,  74  and  76 , the controller  82  actuates the fail-safe solenoid actuated valve  136 , which causes its control port (C) to become connected to its pump port (P). The pump port (P) is capped off, which prevents fluid from flowing through the fail-safe solenoid actuated valve  136 . Should power fail, however, the fail-safe solenoid actuated valve  136  will deactivate and revert to the position shown in  FIG. 9A , which allows hydraulic fluid to flow from the centralizer pistons  72 ,  74  and  76  to the hydraulic reservoir  88  and allows the centralizer pistons  72 ,  74  and  76  to be pushed back into their retracted positions by forces outside the tool  32 . Thus, if power to the tool  32  fails, the centralizer pistons  72 ,  74  and  76  will not be locked in their extended positions, where they would be susceptible to being damaged or destroyed if the drill string begins moving. 
   Operation of the MWD formation testing tool  32  after it is centralized in the borehole is illustrated in  FIG. 13 . The process begins (block  192 ) by drawing a 10 cc sample from the formation (block  194 ) via seal piston  166 . It will be understood that the size of the sample can vary. The controller  82  stores a draw down pressure profile as the sample is being taken. The sample pressure is compared to the annulus pressure (block  196 ). If the sample pressure is the same as the annulus pressure, then the test is considered to have failed. After the first failure, the sample is ejected into the annulus (block  198 ) and the process begins again (block  194 ). On the second and third failures, the sample is ejected to the annulus (block  200 ) and the seal piston is reset with an increased load (block  202 ), in the hope that increased pressure on the seal piston will seal it against the borehole wall. If the test fails a fourth time, the tool  32  transmits a “failed seal response” message to the surface (block  204 ). The process then ends (block  206 ). 
   If any of the comparisons of sample pressure to annulus pressure pass, the resistance of the sample is checked (block  208 ). A resistance test is a conventional test performed on formation fluids. If the formation fluid is conductive, it may be water, salt water, drilling mud, formation fluid contaminated with drilling mud, or some other conductive fluid. If the formation is resistive, it may be a hydrocarbon. 
   Alternatively, any other fluid test can be performed such as an NMR, salinity test, or infrared analysis. Regardless of the particular test performed, if the sample fails the test based upon a predetermined test criteria, the fluid is ejected to the annulus  198  and the process is repeated (beginning at block  194 ). If the sample passes the resistance test (or other test that may be employed instead of or in addition to the resistance test), the controller  82  transmits the stored draw down pressure profile to the surface (block  210 ). The sample is then ejected into the annulus. Alternatively, the sample is transferred to storage (block  212 ) for analysis at a time after tool  32  has been retrieved to the surface. Alternatively, the tool  32  may incorporate equipment to analyze the sample and transmit the results to the surface. The process then ends (block  214 ). 
   The above discussion is meant to be illustrative of the principles and various embodiments of the present invention. While the preferred embodiment of the invention and its method of use have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not limiting. Many variations and modifications of the invention and apparatus and methods disclosed herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited by the description set out above, but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims.

Summary:
A method and apparatus for formation testing is disclosed. In a preferred embodiment, a formation testing tool includes a longitudinal body with a flowbore; a plurality of extendable centralizing pistons coupled to the body; an extendable sample device coupled to the body; and a centralizing hydraulic circuit configured to cause each of the plurality of centralizing pistons to extend at substantially the same rate. The centralizing hydraulic circuit includes a series of flow control and pressure-determining valves configured to extend the centralizing pistons at substantially the same rate, and to help maintain stability in the hydraulic circuit in response to external pressures. In some embodiments, the extendable sample device is preferably configured to be recessed beneath a surface of the body in a first position and to extend beyond the surface in a second position. The extendable sample device is preferably extended to contact the borehole wall substantially normal to the wall, protecting the sample device from excessive bending moments and other excessive forces.