Patent Publication Number: US-7216533-B2

Title: Methods for using a formation tester

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
   This application claims the benefit of 35 U.S.C. 119(e) from U.S. Provisional Application Ser. No. 60/573,423, filed May 21, 2004 and entitled “Methods and Apparatus for Controlling a Formation Tester Tool Assembly”, hereby incorporated herein by reference for all purposes. 

   STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
   Not Applicable. 
   BACKGROUND 
   During the drilling and completion of oil and gas wells, it may be necessary to engage in ancillary operations, such as monitoring the operability of equipment used during the drilling process or evaluating the production capabilities of formations intersected by the wellbore. For example, after a well or well interval has been drilled, zones of interest are often tested to determine various formation properties such as permeability, fluid type, fluid quality, formation temperature, formation pressure, bubble point, formation pressure gradient, mobility, filtrate viscosity, spherical mobility, coupled compressibility porosity, skin damage (which is an indication of how the mud filtrate has changed the permeability near the wellbore), and anisotropy (which is the ratio of the vertical and horizontal permeabilities). These tests are performed in order to determine whether commercial exploitation of the intersected formations is viable and how to optimize production. 
   Wireline formation testers (WFT) and drill stem testers (DST) have been commonly used to perform these tests. The basic DST tool consists of a packer or packers, valves, or ports that may be opened and closed from the surface, and two or more pressure-recording devices. The tool is lowered on a work string to the zone to be tested. The packer or packers are set, and drilling fluid is evacuated to isolate the zone from the drilling fluid column. The valves or ports are then opened to allow flow from the formation to the tool for testing while the recorders chart static pressures. A sampling chamber traps formation fluid at the end of the test. WFTs generally employ the same testing techniques but use a wireline to lower the formation tester into the borehole after the drill string has been retrieved from the borehole. The WFT typically uses packers also, although the packers are typically placed closer together, compared to DSTs, for more efficient formation testing. In some cases, packers are not even used. In those instances, the testing tool is brought into contact with the intersected formation and testing is done without zonal isolation. 
   WFTs may also include a probe assembly for engaging the borehole wall and acquiring formation fluid samples. The probe assembly may include an isolation pad to engage the borehole wall. The isolation pad seals against the formation and around a hollow probe, which places an internal cavity in fluid communication with the formation. This creates a fluid pathway that allows formation fluid to flow between the formation and the formation tester while isolated from the borehole fluid. 
   In order to acquire a useful sample, the probe must stay isolated from the relative high pressure of the borehole fluid. Therefore, the integrity of the seal that is formed by the isolation pad is critical to the performance of the tool. If the borehole fluid is allowed to leak into the collected formation fluid, a non-representative sample will be obtained and the test will have to be repeated. 
   Examples of isolation pads and probes used in WFTs can be found in Halliburton&#39;s DT, SFTT, SFT4, and RDT tools. Isolation pads that are used with WFTs are typically rubber pads affixed to the end of the extending sample probe. The rubber is normally affixed to a metallic plate that provides support to the rubber as well as a connection to the probe. These rubber pads are often molded to fit within the specific diameter hole in which they will be operating. 
   With the use of WFTs and DSTs, the drill string with the drill bit must first be retracted from the borehole. Then, a separate work string containing the testing equipment, or, with WFTs, the wireline tool string, must be lowered into the well to conduct secondary operations. Interrupting the drilling process to perform formation testing can add significant amounts of time to a drilling program. 
   DSTs and WFTs may also cause tool sticking or formation damage. There may also be difficulties of running WFTs in highly deviated and extended reach wells. WFTs also do not have flowbores for the flow of drilling mud, nor are they designed to withstand drilling loads such as torque and weight on bit. 
   Further, the formation pressure measurement accuracy of drill stem tests and, especially, of wireline formation tests may be affected by mud filtrate invasion and mudcake buildup because significant amounts of time may have passed before a DST or WFT engages the formation after the borehole has been drilled. Mud filtrate invasion occurs when the drilling mud fluids displace formation fluid. Because the mud filtrate ingress into the formation begins at the borehole surface, it is most prevalent there and generally decreases further into the formation. When filtrate invasion occurs, it may become impossible to obtain a representative sample of formation fluid or, at a minimum, the duration of the sampling period must be increased to first remove the drilling fluid and then obtain a representative sample of formation fluid. Mudcake buildup occurs when any solid particles in the drilling fluid are plastered to the side of the wellbore by the circulating drilling mud during drilling. The prevalence of the mudcake at the borehole surface creates a “skin”. Thus there may be a “skin effect” because formation testers can only extend relatively short distances into the formation, thereby distorting the representative sample of formation fluid due to the filtrate. The mudcake also acts as a region of reduced permeability adjacent to the borehole. Thus, once the mudcake forms, the accuracy of reservoir pressure measurements decreases, affecting the calculations for permeability and producibility of the formation. 
   Another testing apparatus is the formation tester while drilling (FTWD) tool. Typical FTWD formation testing equipment is suitable for integration with a drill string during drilling operations. Various devices or systems are used for isolating a formation from the remainder of the borehole, drawing fluid from the formation, and measuring physical properties of the fluid and the formation. Fluid properties, among other items, may include fluid compressibility, flowline fluid compressibility, density, resistivity, composition, and bubble point. For example, the FTWD may use a probe similar to a WFT that extends to the formation and a small sample chamber to draw in formation fluid through the probe to test the formation pressure. To perform a test, the drill string is stopped from rotating and moving axially and the test procedure, similar to a WFT described above, is performed. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a more detailed description of the embodiments, reference will now be made to the following accompanying drawings: 
       FIG. 1  is a schematic elevation view, partly in cross-section, of an embodiment of the formation tester disposed in a subterranean well; 
       FIGS. 2A–2E  are elevation views, partly in cross-section, of portions of the bottomhole assembly and shown in  FIG. 1 ; 
       FIG. 3  is an enlarged elevation view, partly in cross-section, of the formation tester shown in  FIG. 2D ; 
       FIG. 3A  is an enlarged cross-section view of the drawdown piston and chamber shown in  FIG. 3 ; 
       FIG. 3B  is an enlarged cross-section view along line  3 B— 3 B of  FIG. 3 ; 
       FIG. 4  is an elevation view of the formation tester shown in  FIG. 3 ; 
       FIG. 5  is a cross-sectional view of the formation probe assembly taken along line  5 — 5  shown in  FIG. 4 ; 
       FIGS. 6A–6C  are cross-sectional views of a portion of the formation probe assembly taken along the same line as seen in  FIG. 5 , the probe assembly being shown in a different position in each of  FIGS. 6A–6C ; 
       FIG. 7  is an elevation view of the probe pad mounted on the skirt in one embodiment employed in the formation probe assembly shown in  FIGS. 4 and 5 ; 
       FIG. 8  is a top view of the probe pad shown in  FIG. 7 ; 
       FIG. 9  is a cross-sectional view of the probe pad and skirt taken along line A—A in  FIG. 7 ; 
       FIG. 10  is a schematic view of a hydraulic circuit employed in actuating the formation tester; 
       FIG. 11  is a graph of the fluid pressure as compared to time measured during operation of the formation tester; 
       FIG. 12  is another graph of the fluid pressure as compared to time measured during operation of the formation tester and showing pressures measured by different pressure transducers employed in the formation tester; 
       FIG. 13  is another graph of the fluid pressure as compared to time measured during operation of the formation tester that illustrates the bubble point of the fluid in the formation tester being exceeded; 
       FIG. 14  is a graph that shows an example of compressibility and bubble point determination; 
       FIG. 15  is a schematic view of a hydraulic circuit employed in operating the formation tester using a hydraulic threshold; 
       FIG. 16  is a schematic view of a hydraulic circuit employed in operating the formation tester using a pressure compensated variable restrictor; and 
       FIG. 17  is a schematic view of a hydraulic circuit employed in operating the formation tester that allows the formation tester to perform a burst test. 
   

   DETAILED DESCRIPTION OF THE EMBODIMENTS 
   Certain terms are used throughout the following description and claims to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function. 
   In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Also, the terms “couple,” “couples”, and “coupled” used to describe any electrical connections are each intended to mean and refer to either an indirect or a direct electrical connection. Thus, for example, if a first device “couples” or is “coupled” to a second device, that interconnection may be through an electrical conductor directly interconnecting the two devices, or through an indirect electrical connection via other devices, conductors and connections. Further, reference to “up” or “down” are made for purposes of ease of description with “up” meaning towards the surface of the borehole and “down” meaning towards the bottom of the borehole. In addition, in the discussion and claims that follow, it may be sometimes stated that certain components or elements are in fluid communication. By this it is meant that the components are constructed and interrelated such that a fluid could be communicated between them, as via a passageway, tube, or conduit. Also, the designation “MWD” or “LWD” are used to mean all generic measurement while drilling or logging while drilling apparatus and systems. 
   In the drawings and description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure 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. 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. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings. 
   Referring to  FIG. 1 , an MWD formation tester  10  is illustrated as a part of bottom hole assembly  6  (BHA) that comprises an MWD sub  13  and a drill bit  7  at its lower most end. The BHA  6  is lowered from a drilling platform  2 , such as a ship or other conventional platform, via a drill string  5 . The drill string  5  is disposed through a riser  3  and a well head  4 . Conventional drilling equipment (not shown) is supported within the derrick  1  and rotates the drill string  5  and the drill bit  7 , causing the bit  7  to form a borehole  8  through the formation material  9 . The borehole  8  penetrates subterranean zones or reservoirs, such as a reservoir  11 . It should be understood that the formation tester  10  may be employed in other bottom hole assemblies and with other drilling apparatus in land-based drilling, as well as offshore drilling as shown in  FIG. 1 . In all instances, in addition to formation tester  10 , the bottom hole assembly  6  may contain various conventional apparatus and systems, such as a down hole drill motor, mud pulse telemetry system, measurement-while-drilling sensors and systems, and others well known in the art. 
   It should also be understood that, even though the MWD formation tester  10  is shown as part of a drill string  5 , the embodiments of the invention described below may be conveyed down the borehole  8  via wireline technology, as is partially described above. It should also be understood that the exact physical configuration of the formation tester and the probe assembly is not a requirement of the present invention. The embodiment described below serves to provide an example only. Additional examples of a probe assembly and methods of use are described in U.S. patent application Ser. No. 10/440,593, filed May 19, 2003 and entitled “Method and Apparatus for MWD Formation Testing”; Ser. No. 10/440,835, filed May 19, 2003 and entitled “MWD Formation Tester”; and Ser. No. 10/440/637, filed May 19, 2003 and entitled “Equalizer Valve”; each hereby incorporated herein by reference for all purposes. 
   The formation tester  10  is best understood with reference to  FIGS. 2A–2E . The formation tester  10  generally comprises a heavy walled housing  12  made of multiple sections of drill collar  12   a , 12   b , 12   c , 12   d  that engage one another so as to form the complete housing  12 . Bottom hole assembly  6  includes flow bore  14  formed through its entire length to allow passage of drilling fluids from the surface through the drill string  5  and through the bit  7 . The drilling fluid passes through nozzles in the drill bit face and flows upwards through borehole  8  along the annulus  150  formed between housing  12  and borehole wall  151 . 
   Referring to  FIGS. 2A and 2B , upper section  12   a  of housing  12  includes upper end  16  and lower end  17 . Upper end  16  may include a threaded box for connecting formation tester  10  to drill string  5 . Lower end  17  may include a threaded box for receiving a correspondingly threaded pin end of housing section  12   b . Disposed between ends  16  and  17  in housing section  12   a  are three aligned and connected sleeves or tubular inserts  24   a,b,c  that create an annulus  25  between sleeves  24   a,b,c  and the inner surface of housing section  12   a . Annulus  25  is sealed from flowbore  14  and provided for housing a plurality of electrical components, including battery packs  20 , 22 . Battery packs  20 , 22  are mechanically interconnected at connector  26 . Electrical connectors  28  are provided to interconnect battery packs  20 , 22  to a common power bus (not shown). Beneath battery packs  20 , 22  and also disposed about sleeve insert  24   c  in annulus  25  is electronics module  30 . Electronics module  30  may also include various circuit boards, capacitors banks, and other electrical components, including the capacitors shown at  32 . A connector  33  is provided adjacent upper end  16  in housing section  12   a  to electrically couple the electrical components in formation tester  10  with other components of bottom hole assembly  6  that are above housing  12 . 
   Beneath electronics module  30  in housing section  12   a  is an adapter insert  34 . Adapter  34  connects to sleeve insert  24   c  at connection  35  and retains a plurality of spacer rings  36  in a central bore  37  that forms a portion of flowbore  14 . Lower end  17  of housing section  12   a  connects to housing section  12   b  at threaded connection  40 . Spacers  38  are disposed between the lower end of adapter  34  and the pin end of housing section  12   b . Because threaded connections such as connection  40 , at various times, need to be cut and repaired, the length of sections  12   a ,  12   b  may vary in length. Employing spacers  36 ,  38  allow for adjustments to be made in the length of threaded connection  40 . 
   Housing section  12   b  includes an inner sleeve  44  disposed therethrough. Sleeve  44  extends into housing section  12   a  above, and into housing section  12   c  below. The upper end of sleeve  44  abuts spacers  36  disposed in adapter  34  in housing section  12   a . An annular area  42  is formed between sleeve  44  and the wall of housing  12   b  and forms a wire way for electrical conductors that extend above and below housing section  12   b , including conductors controlling the operation of formation tester  10  as described below. 
   Referring now to  FIGS. 2B and 2C , housing section  12   c  includes upper box end  47  and lower box end  48 , which may threadingly engage housing section  12   b  and housing section  12   c , respectively. For the reasons previously explained, adjusting spacers  46  are provided in housing section  12   c  adjacent to end  47 . As previously described, insert sleeve  44  extends into housing section  12   c  where it stabs into inner mandrel  52 . The lower end of inner mandrel  52  stabs into the upper end of formation tester mandrel  54 , which is comprised of three axially aligned and connected sections  54   a, b , and  c . Extending through mandrel  54  is a deviated flowbore portion  14   a . Deviating flowbore  14  into flowbore path  14   a  provides sufficient space within housing section  12   c  for the formation tool components described in more detail below. As best shown in  FIG. 2E , deviated flowbore  14   a  eventually centralizes near the lower end  48  of housing section  12   c , shown generally at location  56 . Referring momentarily to  FIG. 5 , the cross-sectional profile of deviated flowbore  14   a  may be a non-circular in segment  14   b , so as to provide as much room as possible for the formation probe assembly  50 . 
   As best shown in  FIGS. 2D and 2E , disposed about formation tester mandrel  54  and within housing section  12   c  are electric motor  64 , hydraulic pump  66 , hydraulic manifold  62 , equalizer valve  60 , formation probe assembly  50 , pressure transducers  160 , and drawdown piston  170 . Hydraulic accumulators provided as part of the hydraulic system  200  for the operating formation probe assembly  50  are also disposed about mandrel  54  in various locations, one such accumulator  68  being shown in  FIG. 2D . 
   Electric motor  64  may be a permanent magnet motor powered by battery packs  20 , 22  and capacitor banks  32 . Motor  64  is interconnected to and drives hydraulic pump  66 . Pump  66  provides fluid pressure for actuating formation probe assembly  50 . Hydraulic manifold  62  includes various solenoid valves, check valves, filters, pressure relief valves, thermal relief valves, pressure transducer  160   b  and hydraulic circuitry employed in actuating and controlling formation probe assembly  50  as explained in more detail below. 
   Referring again to  FIG. 2C , mandrel  52  includes a central segment  71 . Disposed about segment  71  of mandrel  52  are pressure balance piston  70  and spring  76 . Mandrel  52  includes a spring stop extension  77  at the upper end of segment  71 . Stop ring  88  is threaded to mandrel  52  and includes a piston stop shoulder  80  for engaging corresponding annular shoulder  73  formed on pressure balance piston  70 . Pressure balance piston  70  further includes a sliding annular seal or barrier  69 . Barrier  69  consists of a plurality of inner and outer o-ring and lip seals axially disposed along the length of piston  70 . 
   Beneath piston  70  and extending below inner mandrel  52  is a lower oil chamber or reservoir  78 , described more fully below. An upper chamber  72  is formed in the annulus between central portion  71  of mandrel  52  and the wall of housing section  12   c , and between spring stop portion  77  and pressure balance piston  70 . Spring  76  is retained within chamber  72 , which is open through port  74  to annulus  150 . As such, drilling fluids may fill chamber  72  in operation. An annular seal  67  is disposed about spring stop portion  77  to prevent drilling fluid from migrating above chamber  72 . 
   Barrier  69  maintains a seal between the drilling fluid in chamber  72  and the hydraulic oil that fills and is contained in oil reservoir  78  beneath piston  70 . Lower chamber  78  extends from barrier  69  to seal  65  located at a point generally noted as  83  and just above transducers  160  in  FIG. 2E . The oil in reservoir  78  completely fills all space between housing section  12   c  and formation tester mandrel  54 . The hydraulic oil in chamber  78  may be maintained at slightly greater pressure than the pressure of the drilling fluid in annulus  150 . The annulus pressure is applied to piston  70  via drilling fluid entering chamber  72  through port  74 . Because lower oil chamber  78  is a closed system, the annulus pressure that is applied via piston  70  is applied to the entire chamber  78 . Additionally, spring  76  provides a slightly greater pressure to the closed oil system  78  such that the pressure in oil chamber  78  is substantially equal to the annulus fluid pressure plus the pressure added by the spring force. This slightly greater oil pressure is desirable so as to maintain positive pressure on all the seals in oil chamber  78 . Between barrier  69  in piston  70  and point  83 , the hydraulic oil fills all the space between the outside diameter of mandrels  52 ,  54  and the inside diameter of housing section  12   c , this region being marked as distance  82  between points  81  and  83 . The oil in reservoir  78  is employed in the hydraulic circuit  200  ( FIG. 10 ) used to operate and control formation probe assembly  50  as described in more detailed below. 
   Equalizer valve  60 , best shown in  FIG. 3 , is disposed in formation tester mandrel  54   b  between hydraulic manifold  62  and formation probe assembly  50 . Equalizer valve  60  is in fluid communication with hydraulic passageway  85  and with longitudinal fluid passageway  93  formed in mandrel  54   b . Prior to actuating formation probe assembly  50  so as to test the formation, drilling fluid fills passageways  85  and  93  as valve  60  is normally open and communicates with annulus  150  through port  84  in the wall of housing section  12   c . When the formation fluid is being sampled by formation probe assembly  50 , valve  60  closes the passageway  85  to prevent drilling fluids from annulus  150  entering passageway  85  or passageway  93 . A valve particularly well suited for use in this application is the valve described in U.S. patent application Ser. No. 10/440/637, filed May 19, 2003 and entitled “Equalizer Valve”, hereby incorporated herein by reference for all purposes. 
   As shown in  FIGS. 3 and 4 , housing section  12   c  includes a recessed portion  135  adjacent to formation probe assembly  50  and equalizer valve  60 . The recessed portion  135  includes a planar surface or “flat”  136 . The ports through which fluids may pass into equalizing valve  60  and probe assembly  50  extend through flat  136 . In this manner, as drill string  5  and formation tester  10  are rotated in the borehole, formation probe assembly  50  and equalizer valve  60  are better protected from impact, abrasion, and other forces. Flat  136  may be recessed at least ¼ inch and may be at least ½ inch from the outer diameter of housing section  12   c . Similar flats  137 , 138  are also formed about housing section  12   c  at generally the same axial position as flat  136  to increase flow area for drilling fluid in the annulus  150  of borehole  8 . 
   Disposed about housing section  12   c  adjacent to formation probe assembly  50  is stabilizer  154 . Stabilizer  154  may have an outer diameter close to that of nominal borehole size. As explained below, formation probe assembly  50  includes a seal pad  140  that is extendable to a position outside of housing  12   c  to engage the borehole wall  151 . As explained, probe assembly  50  and seal pad  140  of formation probe assembly  50  are recessed from the outer diameter of housing section  12   c , but they are otherwise exposed to the environment of annulus  150  where they could be impacted by the borehole wall  151  during drilling or during insertion or retrieval of bottom hole assembly  6 . Accordingly, being positioned adjacent to formation probe assembly  50 , stabilizer  154  provides additional protection to the seal pad  140  during insertion, retrieval, and operation of bottom hole assembly  6 . It also provides protection to pad  140  during operation of formation tester  10 . In operation, a piston extends seal pad  140  to a position where it engages the borehole wall  151 . The force of the pad  140  against the borehole wall  151  would tend to move the formation tester  10  in the borehole, and such movement could cause pad  140  to become damaged. However, as formation tester  10  moves sideways within the borehole as the piston is extended into engagement with the borehole wall  151 , stabilizer  154  engages the borehole wall and provides a reactive force to counter the force applied to the piston by the formation. In this manner, further movement of the formation tester  10  is resisted. 
   Referring to  FIG. 2E , mandrel  54   c  contains chamber  63  for housing pressure transducers  160   a,c,d  as well as electronics for driving and reading these pressure transducers. In addition, the electronics in chamber  63  contain memory, a microprocessor, and power conversion circuitry for properly utilizing power from power bus  700 . 
   Referring still to  FIG. 2E , housing section  12   d  includes pins ends  86 , 87 . Lower end  48  of housing section  12   c  threadingly engages upper end  86  of housing section  12   d . Beneath housing section  12   d , and between formation tester  10  and drill bit  7  are other sections of the bottom hole assembly  6  that constitute conventional MWD tools, generally shown in  FIG. 1  as MWD sub  13 . In a general sense, housing section  12   d  is an adapter used to transition from the lower end of formation tester  10  to the remainder of the bottom hole assembly  6 . The lower end  87  of housing section  12   d  threadingly engages other sub assemblies included in bottom hole assembly  6  beneath formation tester  10 . As shown, flowbore  14  extends through housing section  12   d  to such lower subassemblies and ultimately to drill bit  7 . 
   Referring again to  FIG. 3  and to  FIG. 3A , drawdown piston  170  is retained in drawdown manifold  89  that is mounted on formation tester mandrel  54   b  within housing  12   c . Drawdown piston  170  includes annular seal  171  and is slidingly received in cylinder  172 . Spring  173  biases drawdown piston  170  to its uppermost or shouldered position as shown in  FIG. 3A . Separate hydraulic lines (not shown) interconnect with cylinder  172  above and below drawdown piston  170  in portions  172   a ,  172   b  to move drawdown piston  170  either up or down within cylinder  172  as described more fully below. A plunger  174  is integral with and extends from drawdown piston  170 . Plunger  174  is slidingly disposed in cylinder  177  coaxial with  172 . Cylinder  175  is the upper portion of cylinder  177  that is in fluid communication with the longitudinal passageway  93  as shown in  FIG. 3A . A flowline valve  179  controls flow of fluid through the passageway  93  between the drawdown piston  170  and the probe assembly  50 . Cylinder  175  is flooded with drilling fluid via its interconnection with passageway  93 . Cylinder  177  is filled with hydraulic fluid beneath seal  166  via its interconnection with hydraulic circuit  200 . Plunger  174  also contains scraper  167  that protects seal  166  from debris in the drilling fluid. Scraper  167  may be an o-ring energized lip seal. 
   As best shown in  FIG. 5 , formation probe assembly  50  generally includes stem  92 , a generally cylindrical adapter sleeve  94 , piston  96  adapted to reciprocate within adapter sleeve  94 , and a snorkel assembly  98  adapted for reciprocal movement within piston  96 . Housing section  12   c  and formation tester mandrel  54   b  include aligned apertures  90   a ,  90   b , respectively, that together form aperture  90  for receiving formation probe assembly  50 . 
   Stem  92  includes a circular base portion  105  with an outer flange  106 . Extending from base  105  is a tubular extension  107  having central passageway  108 . The end of extension  107  includes internal threads at  109 . Central passageway  108  is in fluid connection with fluid passageway  91  that, in turn, is in fluid communication with longitudinal fluid chamber or passageway  93 , best shown in  FIG. 3 . 
   Adapter sleeve  94  includes inner end  111  that engages flange  106  of stem number  92 . Adapter sleeve  94  is secured within aperture  90  by threaded engagement with mandrel  54   b  at segment  110 . The outer end  112  of adapter sleeve  94  extends to be substantially flushed with flat  136  formed in housing member  12   c . Circumferentially spaced about the outermost surface of adapter sleeve  94  is a plurality of tool engaging recesses  158 . These recesses are employed to thread adapter  94  into and out of engagement with mandrel  54   b . Adapter sleeve  94  includes cylindrical inner surface  113  having reduced diameter portions  114 , 115 . A seal  116  is disposed in surface  114 . Piston  96  is slidingly retained within adapter sleeve  94  and generally includes base section  118  and an extending portion  119  that includes inner cylindrical surface  120 . Piston  96  further includes central bore  121 . 
   The snorkel  98  includes a base portion  125 , a snorkel extension  126 , and a central passageway  127  extending through base  125  and extension  126 . 
   The probe assembly  50  is assembled such that piston base  118  is permitted to reciprocate along surface  113  of adapter sleeve  94 . Similarly, the snorkel base  125  is disposed within piston  96  and the snorkel extension  126  is adapted for reciprocal movement along the piston surface  120 . Central passageway  127  of the snorkel  98  is axially aligned with tubular extension  107  of the stem  92  and with the screen  100 . 
   Referring to  FIGS. 5 and 6C , screen  100  is a generally tubular member having a central bore  132  extending between a fluid inlet end  131  and outlet end  122 . Outlet end  122  includes a central aperture  123  that is disposed about stem extension  107 . Screen  100  further includes a flange  130  adjacent to fluid inlet end  131  and an internally slotted segment  133  having slots  134 . Apertures  129  are formed in screen  100  adjacent end  122 . Between slotted segment  133  and apertures  129 , screen  100  includes threaded segment  124  for threadingly engaging snorkel extension  126 . 
   The scraper  102  includes a central bore  103 , threaded extension  104 , and apertures  101  that are in fluid communication with central bore  103 . Section  104  threadingly engages internally threaded section  109  of stem extension  107 , and is disposed within central bore  132  of screen  100 . 
   Referring now to FIGS.  5  and  7 – 9 , seal pad  140  may be generally donut-shaped having base surface  141 , an opposite sealing surface  142  for sealing against the borehole wall, a circumferential edge surface  143  and a central aperture  144 . In the embodiment shown, base surface  141  is generally flat and is bonded to a metal skirt  145 . Seal pad  140  seals and prevents drilling fluid from entering the probe assembly  50  during formation testing so as to enable pressure transducers  160  to measure the pressure of the formation fluid. Changes in formation fluid pressure over time provide an indication of the permeability of the formation  9 . More specifically, seal pad  140  seals against the mudcake  49  that forms on the borehole wall. Typically, the pressure of the formation fluid is less than the pressure of the drilling fluids that are injected into the borehole. A layer of residue from the drilling fluid forms a mudcake  49  on the borehole wall and separates the two pressure areas. Pad  140 , when extended, conforms its shape to the borehole wall and, together with the mudcake  49 , forms a seal through which formation fluid can be collected. 
   As best shown in  FIGS. 3 ,  5 , and  6 , pad  140  is sized so that it can be retracted completely within aperture  90 . In this position, pad  140  is protected both by flat  136  that surrounds aperture  90  and by recess  135  that positions face  136  in a setback position with respect to the outside surface of housing  12 . 
   Pad  140  may be made of an elastomeric material having a high elongation characteristic. At the same time, the material may possess relatively hard and wear resistant characteristics. More particularly, the material may have an elongation % equal to at least 200% and even more than 300%. One such material useful in this application is Hydrogenated Nitrile Butadiene Rubber (HNBR). A material found particularly useful for pad  140  is HNBR compound number 372 supplied by Eutsler Technical Products of Houston, Tex., U.S.A. having a durometer hardness of 85 Shore A and a percent elongation of 370% at room temperature. 
   One possible profile for pad  140  is shown in  FIGS. 7–9 . Sealing surface  142  of pad  140  generally includes a spherical surface  162  and radius surface  164 . Spherical surface  162  begins at edge  143  and extends to point  163  where spherical surface  162  merges into and thus becomes a part of radius surface  164 . Radius surface  164  curves into central aperture  144  which passes through the center of the pad  140 . In the embodiment shown in  FIGS. 7–9 , pad  140  includes an overall diameter of 2.25 inches with the diameter of central aperture  144  being equal to 0.75 inches. Radius surface  164  has a radius of 0.25 inches, and spherical surface  162  has a spherical radius equal to 4.25 inches. The height of the profile of pad  140  is 0.53 inches at its thickest point. 
   Referring again to  FIGS. 7-9 , when pad  140  is compressed, it may extrude into the recesses  152  in skirt  145 . The corners  2008  of the recesses  152  can damage the pad, resulting in premature failure. An undercut feature  1000  shown in  FIGS. 7 and 9  is cut into the pad to give space between the elastomeric pad  140  and the recesses  152 . 
   As best shown in  FIG. 7 , skirt  145  includes an extension  146  for threadingly engaging extending portion  119  of piston  96  ( FIG. 5 ) at threaded segment  147  ( FIGS. 7 and 9 ). Skirt  145  may also include dovetail groove  149   a  as shown in  FIG. 9 . When molded, the elastomer fills the dovetail groove. The groove acts to retain the elastomer in the event of de-bonding between the metal skirt  145  and the pad  140 . As shown in  FIG. 5 , snorkel extension  126  supports the central aperture  144  of pad  140  ( FIG. 7 ) to reduce the extrusion of the elastomer when it is pressed against the borehole wall during a formation test. Reducing extrusion of the elastomer helps to ensure a good pad seal, especially against the high differential pressure seen across the pad during a formation test. 
   To help with a good pad seal, tool  10  may include, among other things, centralizers for centralizing the formation probe assembly  50  and thereby normalizing pad  140  relative to the borehole wall. For example, the formation tester  10  may include centralizing pistons coupled to a hydraulic fluid circuit configured to extend the pistons in such a way as to protect the probe assembly and pad, and also to provide a good pad seal. A formation tester including such devices is described in U.S. patent application Ser. No. 10/440,593, filed May 19, 2003 and entitled “Method and Apparatus for MWD Formation Testing”, hereby incorporated herein by reference for all purposes. 
   The hydraulic circuit  200  used to operate probe assembly  50 , equalizer valve  60 , and drawdown piston  170  is illustrated in  FIG. 10 . A microprocessor-based controller  190  is electrically coupled to all of the controlled elements in the hydraulic circuit  200  illustrated in  FIG. 10 , although the electrical connections to such elements are conventional and are not illustrated other than schematically. Controller  190  is located in electronics module  30  in housing section  12   a , although it could be housed elsewhere in bottom hole assembly  6 . Controller  190  detects the control signals transmitted from a master controller (not shown) housed in the MWD sub  13  of the bottom hole assembly  6  which, in turn, receives instructions transmitted from the surface via mud pulse telemetry, or any of various other conventional means for transmitting signals to downhole tools. 
   Controller  190  receives a command to initiate formation testing. This command may be received when the drill string is rotating or sliding or otherwise moving; however the drill string must be stationary during a formation test. As shown in  FIG. 10 , motor  64  is coupled to pump  66  that draws hydraulic fluid out of hydraulic reservoir  78  through a serviceable filter  79 . As will be understood, the pump  66  directs hydraulic fluid into hydraulic circuit  200  that includes formation probe assembly  50 , equalizer valve  60 , drawdown piston  170  and solenoid valves  176 , 178 , 180 . 
   The operation of the formation tester  10  is best understood in reference to  FIG. 10  in conjunction with  FIGS. 3A ,  5 , and  6 A–C. In response to an electrical control signal, the controller  190  energizes solenoid valve  180  and starts motor  64 . Pump  66  then begins to pressurize hydraulic circuit  200  and, more particularly, charges probe retract accumulator  182 . The act of charging accumulator  182  also ensures that the probe assembly  50  is retracted and that drawdown piston  170  is in its initial shouldered position as shown in  FIG. 3A . When the pressure in system  200  reaches a predetermined value, such as 1800 psi as sensed by pressure transducer  160   b , the controller  190 , which continuously monitors pressure in the hydraulic circuit  200 , energizes solenoid valve  176  and de-energizes solenoid valve  180 , which causes the probe piston  96  and the snorkel  98  to begin to extend toward the borehole wall  151 . Concurrently, check valve  194  and relief valve  193  seal the probe retract accumulator  182  at a pressure charge of between approximately 500 to 1250 psi. 
   The piston  96  and the snorkel  98  extend from the position shown in  FIG. 6A  to that shown in  FIG. 6B  where the pad  140  engages the mudcake  49  on the borehole wall  151 . With hydraulic pressure continued to be supplied to the extend side of the piston  96  and snorkel  98 , the snorkel then penetrates the mudcake as shown in  FIG. 6C . There are two expanded positions of snorkel  98 , generally shown in  FIGS. 6B and 6C . The piston  96  and snorkel  98  move outwardly together until the pad  140  engages the borehole wall  151 . This combined motion continues until the force of the borehole wall against pad  140  reaches a pre-determined magnitude, for example 5,500 lb, causing pad  140  to be squeezed. At this point, a second stage of expansion takes place with snorkel  98  then moving within the cylinder  120  in piston  96  to penetrate the mudcake  49  on the borehole wall  151  and to receive formation fluid. 
   In one method, as seal pad  140  is pressed against the borehole wall, the pressure in circuit  200  rises and when it reaches a predetermined pressure, the valve  192  opens so as to close the equalizer valve  60 , thereby isolating the fluid passageway  93  from the annulus. In this manner, the valve  192  ensures that the valve  60  closes only after the seal pad  140  has entered contact with the mudcake  49  that lines the borehole wall  151 . In another method, as the seal pad  140  is pressed against the borehole wall  151 , the pressure in circuit  200  rises and closes the equalizer valve  60 , thereby isolating the fluid passageway  93  from the annulus. In this manner, the valve  60  may close before the seal pad  140  has entered contact with the mudcake  49  that lines the borehole wall  151 . The passageway  93 , now closed to the annulus  150 , is in fluid communication with the cylinder  175  at the upper end of the cylinder  177  in drawdown manifold  89 , best shown in  FIG. 3A . 
   With the solenoid valve  176  still energized, the probe seal accumulator  184  is charged until the system reaches a predetermined pressure, for example 1800 psi, as sensed by the pressure transducer  160   b . When that pressure is reached, a delay may occur before the controller  190  energizes the solenoid valve  178  to begin drawdown. This delay, which is controllable, can be used to measure properties of the mudcake  49  that lines the borehole wall  151 . Energizing the solenoid valve  178  permits pressurized fluid to enter the portion  172   a  of the cylinder  172  causing the drawdown piston  170  to retract. When that occurs, the plunger  174  moves within the cylinder  177  such that the volume of the fluid passageway  93  increases by the volume of the area of the plunger  174  times the length of its stroke along the cylinder  177 . This movement increases the volume of cylinder  175 , thereby increasing the volume of the fluid passageway  93 . For example, the volume of the fluid passageway  93  may be increased by 10 cc as a result of the drawdown piston  170  being retracted. 
   As the drawdown piston  170  is actuated, formation fluid may thus be drawn through the central passageway  127  of the snorkel  98  and through the screen  100 . The movement of the drawdown piston  170  within its cylinder  172  lowers the pressure in the closed passageway  93  to a pressure below the formation pressure, such that formation fluid is drawn through the screen  100  and the snorkel  98  into the aperture  101 , then through the stem passageway  108  to the passageway  91  that is in fluid communication with the passageway  93  and part of the same closed fluid system. In total, the fluid chambers  93 , which include the volume of various interconnected fluid passageways, including passageways in the probe assembly  50 , the passageways  85 , 93  [ FIG. 3 ], the passageways interconnecting  93  with drawdown piston  170  and the pressure transducers  160   a,c  may have a volume of approximately 40 cc. Drilling mud in the annulus  150  is not drawn into snorkel  98  because pad  140  seals against the mudcake. Snorkel  98  serves as a conduit through which the formation fluid may pass and the pressure of the formation fluid may be measured in passageway  93  while pad  140  serves as a seal to prevent annular fluids from entering the snorkel  98  and invalidating the formation pressure measurement. 
   Referring momentarily to  FIGS. 5 and 6C , formation fluid is drawn first into the central bore  132  of screen  100 . It then passes through slots  134  in screen slotted segment  133  such that particles in the fluid are filtered from the flow and are not drawn into passageway  93 . The formation fluid then passes between the outer surface of screen  100  and the inner surface of snorkel extension  126  where it next passes through apertures  123  in screen  100  and into the central passageway  108  of stem  92  by passing through apertures  101  and central passage bore  103  of scraper  102 . 
   Referring again to  FIG. 10 , with seal pad  140  sealed against the borehole wall, check valve  195  maintains the desired pressure acting against piston  96  and snorkel  98  to maintain the proper seal of pad  140 . Additionally, because the probe seal accumulator  184  is fully charged, should the tool  10  move during drawdown, additional hydraulic fluid volume may be supplied to the piston  96  and the snorkel  98  to ensure that pad  140  remains tightly sealed against the borehole wall. In addition, should the borehole wall  151  move in the vicinity of pad  140 , the probe seal accumulator  184  will supply additional hydraulic fluid volume to piston  96  and snorkel  98  to ensure that pad  140  remains tightly sealed against the borehole wall  151 . Without accumulator  184  in circuit  200 , movement of the tool  10  or borehole wall  151 , and thus of formation probe assembly  50 , could result in a loss of seal at pad  140  and a failure of the formation test. 
   With the drawdown piston  170  in its fully retracted position and formation fluid drawn into closed system  93 , the pressure will stabilize and enable pressure transducers  160   a,c  to sense and measure formation fluid pressure. The measured pressure is transmitted to the controller  190  in the electronic section where the information is stored in memory and, alternatively or additionally, is communicated to the master controller in the MWD tool  13  below the formation tester  10  where it can be transmitted to the surface via mud pulse telemetry or by any other conventional telemetry means. 
   When drawdown is completed, drawdown piston  170  actuates a contact switch  320  mounted in endcap  400  and drawdown piston  170 , as shown in  FIG. 3A . The drawdown switch assembly consists of contact  300 , wire  308  coupled to contact  300 , plunger  302 , spring  304 , ground spring  306 , and retainer ring  310 . The drawdown piston  170  actuates switch  320  by causing plunger  302  to engage contact  300  that causes wire  308  to couple to system ground via contact  300  to plunger  302  to ground spring  306  to drawdown piston  170  to endcap  400  that is in communication with system ground (not shown). 
   When the contact switch  320  is actuated controller  190  responds by shutting down motor  64  and pump  66  for energy conservation. Check valve  196  traps the hydraulic pressure and maintains drawdown piston  170  in its retracted position. In the event of any leakage of hydraulic fluid that might allow drawdown piston  170  to begin to move toward its original shouldered position, drawdown accumulator  186  will provide the necessary fluid volume to compensate for any such leakage and thereby maintain sufficient force to retain drawdown piston  170  in its retracted position. 
   During this interval, controller  190  continuously monitors the pressure in fluid passageway  93  via pressure transducers  160   a,c  until the pressure stabilizes, or after a predetermined time interval. 
   When the measured pressure stabilizes, or after a predetermined time interval, controller  190  de-energizes solenoid valve  176 . De-energizing solenoid valve  176  removes pressure from the close side of equalizer valve  60  and from the extend side of probe piston  96 . Spring  58  then returns the equalizer valve  60  to its normally open state and probe retract accumulator  182  will cause piston  96  and snorkel  98  to retract, such that seal pad  140  becomes disengaged with the borehole wall. Thereafter, controller  190  again powers motor  64  to drive pump  66  and again energizes solenoid valve  180 . This step ensures that piston  96  and snorkel  98  have fully retracted and that the equalizer valve  60  is opened. Given this arrangement, the formation tool  10  has a redundant probe retract mechanism. Active retract force is provided by the pump  66 . A passive retract force is supplied by probe retract accumulator  182  that is capable of retracting the probe even in the event that power is lost. Accumulator  182  may be charged at the surface before being employed downhole to provide pressure to retain the piston and snorkel in housing  12   c.    
   Referring again briefly to  FIGS. 5 and 6 , as piston  96  and snorkel  98  are retracted from their position shown in  FIG. 6C  to that of  FIG. 6B , screen  100  is drawn back into snorkel  98 . As this occurs, the flange on the outer edge of scraper  102  drags and thereby scrapes the inner surface of screen member  100 . In this manner, material screened from the formation fluid upon its entering of screen  100  and snorkel  98  is removed from screen  100  and deposited into the annulus  150 . Similarly, scraper  102  scrapes the inner surface of screen member  100  when snorkel  98  and screen  100  are extended toward the borehole wall. 
   After a predetermined pressure, for example 1800 psi, is sensed by pressure transducer  160   b  and communicated to controller  190  (indicating that the equalizer valve is open and that the piston and snorkel are fully retracted), controller  190  de-energizes solenoid valve  178  to remove pressure from side  172   a  of drawdown piston  170 . With solenoid valve  180  remaining energized, positive pressure is applied to side  172   b  of drawdown piston  170  to ensure that drawdown piston  170  is returned to its original position (as shown in  FIG. 3 ). Controller  190  monitors the pressure via pressure transducer  160   b  and when a predetermined pressure is reached, controller  190  determines that drawdown piston  170  is fully returned and it shuts off motor  64  and pump  66  and de-energizes solenoid valve  180 . With all solenoid valves  176 ,  178 ,  180  returned to their original position and with motor  64  off, tool  10  is back in its original condition and drilling can again be commenced. 
   Relief valve  197  protects the hydraulic system  200  from overpressure and pressure transients. Various additional relief valves may be provided. Thermal relief valve  198  protects trapped pressure sections from overpressure. Check valve  199  prevents back flow through the pump  66 . 
     FIG. 11  illustrates a pressure versus time graph illustrating in a general way the pressure sensed by pressure transducer  160   a,c  during the operation of the formation tester  10 . As the formation fluid is drawn within the formation tester  10 , pressure readings are taken continuously by the transducers  160   a,c . The pressure sensed by the transducers  160   a,c  will initially be equal to the annulus, or borehole, pressure shown at point  201 . As pad  140  is extended and equalizer valve  60  is closed, there will be a slight increase in pressure as shown at  202 . This occurs when the pad  140  seals against the borehole wall  151  and squeezes the drilling fluid trapped in the now-isolated passageway  93 . As the drawdown piston  170  is actuated, the volume of the closed passageway  93  increases, causing the pressure to decrease as shown in region  203 . When the drawdown piston  170  bottoms out within the cylinder  172 , a differential pressure with the formation fluid exists causing the fluid in the formation to move towards the low pressure area and, therefore, causing the pressure to build over time as shown in region  204 . The pressure begins to stabilize, and at point  205 , achieves the pressure of the formation fluid in the zone being tested. After a fixed time, such as three minutes after the end of region  203 , the equalizer valve  60  is again opened, and the pressure within the passageway  93  equalizes back to the annulus pressure as shown at  206 . 
   Referring again to  FIG. 10 , the formation tester  10  may include four pressure transducers  160 : two quartz crystal gauges  160   a,d , a strain gauge  160   c , and a differential strain gage  160   b . One of the quartz crystal gauges  160   a  is in communication with the annulus, or borehole, fluid and also senses formation pressures during the formation test. The other quartz crystal gauge  160   d  is in communication with the flowbore  14  at all times. In addition, both quartz crystal gauges  160   a  and  160   d  may have temperature sensors associated with the crystals. The temperature sensors may be used to compensate the pressure measurement for thermal effects. The temperature sensors may also be used to measure the temperature of the fluids near the pressure transducers. For example, the temperature sensor associated with quartz crystal gauge  160   a  is used to measure the temperature of the fluid near the gage in the passageway  93 . The third transducer is a strain gauge  160   c  and is in communication with the annulus fluid and also senses formation pressures during the formation test. The quartz transducers  160   a,d  provide accurate, steady-state pressure information, whereas the strain gauge  160   c  provides faster transient response. In performing the sequencing during the formation test, the passageway  93  is closed off and both the annulus quartz gauge  160   a  and the strain gauge  160   c  measure pressure within the closed passageway  93 . The strain gauge transducer  160   c  essentially is used to supplement the quartz gauge  160   a  measurements. When the formation tester  10  is not in use, the quartz transducers  160   a,d  may operatively measure pressure while drilling to serve as a pressure while drilling tool. 
     FIG. 12  illustrates representative formation test pressure curves. The solid curve  220  represents pressure readings P sg  detected and transmitted by the strain gauge  160   c . Similarly, the pressure P q , indicated by the quartz gauge  160   a , is shown as a dashed line  222 . As noted above, strain gauge transducers generally do not offer the accuracy exhibited by quartz transducers and quartz transducers do not provide the transient response offered by strain gauge transducers. Hence, the instantaneous formation test pressures indicated by the strain gauge  160   c  and quartz  160   a  transducers are likely to be different. For example, at the beginning of a formation test, the pressure readings P hydl  indicated by the quartz transducer Pq and the strain gauge P sg  transducer are different and the difference between these values is indicated as E offs1  in  FIG. 12 . 
   With the assumption that the quartz gauge reading P q  is the more accurate of the two readings, the actual formation test pressures may be calculated by adding or subtracting the appropriate offset error E offs1  to the pressures indicated by the strain gauge P sg  for the duration of the formation test. In this manner, the accuracy of the quartz transducer and the transient response of the strain gauge may both be used to generate a corrected formation test pressure that, where desired, is used for real-time calculation of formation characteristics. 
   As the formation test proceeds, it is possible that the strain gauge readings may become more accurate or for the quartz gauge reading to approach actual pressures in the pressure chamber even though that pressure is changing. In either case, it is probable that the difference between the pressures indicated by the strain gauge transducer and the quartz transducer at a given point in time may change over the duration of the formation test. Hence, it may be desirable to consider a second offset error that is determined at the end of the test where steady state conditions have been resumed. Thus, as pressures P hyd2  level off at the end of the formation test, it may be desirable to calculate a second offset error E offs2 . This second offset error E offs2  might then be used to provide an after-the-fact adjustment to the formation test pressures. 
   The offset values E offs1  and E offs2  may be used to adjust specific data points in the test. For example, all critical points up to P fu  might be adjusted using errors E offs1 , whereas all remaining points might be adjusted offset using error E offs2 . Another solution may be to calculate a weighted average between the two offset values and apply this single weighted average offset to all strain gauge pressure readings taken during the formation test. The amplitude of recorded strain gauge data can also be corrected by multiplying by amplitude correction k, where k=(P q1 −P q2 )/(P sg1 −P sg2 ). Other methods of applying the offset error values to accurately determine actual formation test pressures may also be used accordingly and will be understood by those skilled in the art. 
   The formation tester  10  may operate in two general modes: pump-on operation and pump-off operation. During pump on operation, mud pumps on the surface pump drilling fluid through the drill string  6  and back up the annulus  150 . Using this column of drilling fluid, the tool  10  can transmit data to the surface using mud pulse telemetry during the formation test. The tool  10  may also receive mud pulse telemetry downlink commands from the surface. During a formation test, the drill string  6  and the formation tester  10  are not rotated. However, it may be the case that an immediate movement or rotation of the drill string  6  will be necessary. As a failsafe feature, at any time during the formation test, an abort command can be transmitted from surface to the formation tester  10 . In response to this abort command, the formation tester  10  will immediately discontinue the formation test and retract the probe piston to its normal, retracted position for drilling. The drill string  6  can then be moved or rotated without causing damage to the formation tester  10 . 
   During pump-off operation, a similar failsafe feature may also be active. The formation tester  10  and/or MWD tool  13  may be adapted to sense when the mud flow pumps are turned on. Consequently, the act of turning on the pumps and reestablishing flow through the tool may be sensed by pressure transducer  160   d  or by other pressure sensors in bottom hole assembly  6 . This signal will be interpreted by a controller in the MWD tool  13  or other control and communicated to controller  190  that is programmed to automatically trigger an abort command in the formation tester  10 . At this point, the formation tester  10  will immediately discontinue the formation test and retract the probe piston  96  to its normal position for drilling. The drill string  6  can then be moved or rotated without causing damage to the formation tester  10 . 
   The uplink and downlink commands are not limited to mud pulse telemetry. By way of example and not by way of limitation, other telemetry systems may include manual methods, including pump cycles, flow/pressure bands, pipe rotation, or combinations thereof. Other possibilities include electromagnetic (EM), acoustic, and wireline telemetry methods. An advantage to using alternative telemetry methods lies in the fact that mud pulse telemetry (both uplink and downlink) requires pump-on operation but other telemetry systems do not. The failsafe abort command may therefore be sent from the surface to the formation tester  10  using an alternative telemetry system regardless of whether the mud flow pumps are on or off. 
   The down hole receiver for downlink commands or data from the surface may reside within the formation tester  10  or within an MWD tool  13  with which it communicates. Likewise, the down hole transmitter for uplink commands or data from down hole may reside within the formation tester  10  or within an MWD tool  13  with which it communicates. The receivers and transmitters may each be positioned in MWD tool  13  and the receiver signals may be processed, analyzed, and sent to a master controller in the MWD tool  13  before being relayed to local controller  190  in formation testing tool  10 . 
   Commands or data sent from surface to the formation tester  10  can be used for more than transmitting a failsafe abort command. The formation tester  10  can also have many other operating modes that may be selected using a command from the surface. For example, one of a plurality of operating modes may be selected by transmitting a header sequence indicating a change in operating mode followed by a number of pulses that correspond to that operating mode. Other means of selecting an operating mode will certainly be known to those skilled in the art. 
   In addition to the selection of the operating modes, other information may be transmitted from the surface to the formation tester  10 . This information may include critical operational data such as depth or surface drilling mud density. The formation tester  10  may use this information to help refine measurements or calculations made downhole or to select an operating mode. Commands from the surface might also be used to program the formation tester  10  to perform in a mode that is not preprogrammed. 
   An example of an operating mode of the formation tester  10  is the ability of the formation tester  10  to adapt the pressure test procedure to the bubble point of the formation fluid at different test depths. At discovery, formation fluid can contain some natural gas in solution. The bubble point is the pressure at which the gas comes out of solution in the formation fluid at a given temperature. If any gas comes out of solution during a drawdown test procedure, the test data may not accurately represent the formation pressure. 
     FIG. 13  illustrates a drawdown test procedure where the bubble point of the fluid in the formation tester  10  is exceeded. When the drawdown exceeds the bubble point, the pressure declines rapidly during the drawdown and in low permeability zones the slope is typically directly proportional to the flow rate. This slope is due primarily to the compressibility of the fluid in the flow line of the tool  10 . As the drawdown continues, the slope changes when the bubble point is encountered as shown in  FIG. 13  at the line marked “Bubble Point”. This change in slope can be caused by formation fluids entering the tool  10 , but when the pressure does not start to build up after the end of the drawdown (t end     —     dd ), then the bubble point has been exceeded. When the bubble point is exceeded, the effective compressibility of the flowline fluid is increased substantially showing the buildup. After a sufficient buildup time some fluid enters the tool  10  from the formation and at some point the gas is absorbed into solution. When this occurs, the compressibility of the flowline fluids is reduced and the buildup rate increases rapidly. Both the inflection point during the drawdown and buildup can be used to estimate the bubble point of the fluid in the tool  10 . This can be accomplished by monitoring the slope of the buildup using standard regression techniques. For example, the drawdown stage can be analyzed. Initially the slope is very sharp but changes to nearly 0 when the bubble point is encountered. In this case the initial drawdown curve can be compared to the remaining data and the intersection of these two curves is the bubble point. Starting at the beginning of the drawdown the pressure and time points are monitored. Assuming n points have been collected then the slope is calculated using n−n o  as follows. 
           b   =         n   ⁢     ∑           ⁢   xy       -       (     ∑           ⁢   x     )     ⁢     (     ∑           ⁢   y     )             n   ⁢     ∑           ⁢     x   2         -       (     ∑           ⁢   x     )     2               
buildup slope in psi/sec
 
   a=(Σy−bΣx)/n line intercept using n−n o  points 
   Where: x i —time 
   y i —pressure 
   n—start of drawdown points collected (usually 8–20 data points). 
   Using the last 10–20 data points a second slope is monitored to look for a change in slope. 
             b   o     =           n   o     ⁢     ∑           ⁢   xy       -       (     ∑           ⁢   x     )     ⁢     (     ∑           ⁢   y     )               n   o     ⁢     ∑           ⁢     x   2         -       (     ∑           ⁢   x     )     2               
end of drawdown and beginning of buildup slope
 
   a o =(Σy−b o Σx)/n o  line intercept using n o  points 
   Where: n o —set number of points (usually 30 to 120 points). 
   The beginning slope b is much larger than the ending slope b o  and the bubble point is determined by the intersection of the two lines. 
   
     
       
         
           
             P 
             bp 
           
           = 
           
             
               y 
               bp 
             
             = 
             
               
                 
                   
                     a 
                     o 
                   
                   ⁢ 
                   b 
                 
                 - 
                 
                   ab 
                   o 
                 
               
               
                 b 
                 - 
                 
                   b 
                   o 
                 
               
             
           
         
       
     
   
   If the buildup is allowed to continue another estimate of bubble point can be made from the buildup data. Using this technique, all of the buildup data can be used to determine b and then only a portion of the buildup data is monitored to determine the current slope b o . While monitoring these slopes during the buildup, the ending slope b o  becomes much greater than the predominate slope b. The bubble point is then estimated by the intersection of the two lines. The time at which the intersection occurs can also be used to estimate formation permeability. 
   
     
       
         
           
             t 
             bp 
           
           = 
           
             
               x 
               bp 
             
             = 
             
               
                 
                   a 
                   o 
                 
                 - 
                 a 
               
               
                 b 
                 - 
                 
                   b 
                   o 
                 
               
             
           
         
       
     
   
   The linear regression techniques shown are one of several methods that can be used to determine curve inflection points and the subsequent bubble points. Derivative and second derivatives and non linear regression methods may also be used. 
   The bubble point determined from the buildup is typically higher than that determined from the drawdown (see  FIG. 13 ). This is due to the thermodynamic changes that occur during the rapid drawdown and then the slow buildup. Typically the fluid is cooled due to adiabatic expansion during the drawdown. This cooling effect tends cause the bubble point to be underestimated. During the buildup the temperature equalizes and the apparent bubble point also increases. 
   In the case where the bubble point and time is determined from the buildup curve, the formation mobility can be estimated by making a few assumptions. The first is that the actual formation flow rate is much lower than the pretest piston rate measured by the formation tester  10 . This is because the gas formation in the tool is now regulating the rate. If it is assumed that the flow rate is nearly constant during the time where the pretest starts and where the phase change occurs during the buildup, then the formation spherical mobility can be estimated as follows. 
           Ms   =       (       14   ,   696       2   ⁢   π       )     ⁢     (       q   o       Δ   ⁢           ⁢     P   dd         )     ⁢     (       C   dd       r   s       )             
Where: q o =V 0 /(t bp −t dd     —     start ) estimated drawdown flow rate (cc/sec)
         V o =drawdown volume (cc)   t bp =bubble point buildup time (sec)   t dd     —     start =start of drawdown (sec)   r s =snorkel radius(cm)   C dd =flow correction factor (dimensionless)   ΔP dd =P stop −P bp          
   The second assumption is that the formation pressure is near the last build pressure P stop . If there is insufficient time for the buildup to stabilize, P Stop  may not yield an optimistic estimate of Ms. If this is the case the hydrostatic mud pressure can be used to obtain a conservative estimate of Ms. This technique of determining the mobility is called the drawdown method and assumes steady state flow. This is one of several that can be used to estimate the mobility. Other methods could include spherical homer and derivative plots. 
   The operating mode of the formation tester  10  may be adjusted to account for the bubble point of the formation fluid. For example, if the bubble point is breached, the drawdown piston  170  may be moved back to the starting position and the pressure test performed over again. 
   The first method of modifying the pretest is to lower the flow rate of the fluid into the tool  10 . This is accomplished by estimating a flow rate that would keep the drawdown pressure above the bubble point. This can be done from the estimate of the spherical mobility Ms as follows: 
   
     
       
         
           
             q 
             pt 
           
           = 
           
             Ms 
             ⁢ 
             
                 
             
             ⁢ 
             Δ 
             ⁢ 
             
                 
             
             ⁢ 
             
               
                 P 
                 dd 
               
               ⁡ 
               
                 ( 
                 
                   
                     r 
                     s 
                   
                   
                     C 
                     dd 
                   
                 
                 ) 
               
             
             ⁢ 
             
               ( 
               
                 
                   2 
                   ⁢ 
                   π 
                 
                 
                   14 
                   , 
                   696 
                 
               
               ) 
             
           
         
       
     
   
   After the pressure has been equalized back to nearly hydrostatic the second pretest is performed at the new rate. 
   Still another method of performing the second drawdown is to set a cutoff pressure. The pretest would stop as soon as this pressure is reached. The cutoff pressure would be higher than the estimated bubble point pressure, usually by several hundred psi. Again the second pretest would be performed after the flowline pressure has been equalized back to nearly hydrostatic mud pressure. This second pretest would start at the same rate as the first but then the pretest piston displacement is stopped when the pressure reaches the cutoff pressure. 
   Still another method is to both adjust the flow rate and set a cutoff pressure. It may not be possible for the formation tester  10  to reduce its rate to that required to maintain the pressure above the bubble point. The slower rate reduces the change in pressure over time and makes stopping the pretest piston at the prescribe cutoff pressure more accurate. 
   As another example, if the test is allowed sufficient time to build up as illustrated in  FIG. 13 . The pressure is allowed to build up and the gas allowed to recombine with the fluids from the formation. The amount of time for the gas to recombine may depend on the bubble point pressure and the characteristics of the test fluid. From this information, the formation permeability can be estimated and the drawdown rate can be adjusted so that the drawdown pressure would not fall below the bubble point. 
   Alternatively, the drawdown of the drawdown piston  170  may be done incrementally until a proper drawdown and buildup are achieved. Using this method, the drawdown piston  170  is drawn down, but not to the full extent under a normal pressure test. The pressure is then monitored in the cylinder  175  using the transducers  160 . If the drawdown piston  170  was not drawn down enough to produce a proper buildup, the drawdown piston  170  is drawn down again to create more of a pressure drop within the cylinder  175 . The drawdown may be adjusted by drawing the drawdown piston  170  more or at a faster rate, or a combination of magnitude and rate. This method may be performed until a proper drawdown and build up are achieved. Although the bubble point pressure is not measured, parameters for the pressure test may be set based on the incremental drawdown steps to ensure that the bubble point is not reached with further pressure tests. 
   Other operating modes involve the formation tester  10  determining the bubble point of the formation fluid by performing a pressure test to purposefully bubble point the formation fluid. During the pressure test, the flowline valve  179  may be closed and the drawdown piston  170  drawn down to lower the pressure in the cylinder  175  and create a known volume within the cylinder  175 . Once the drawdown piston  170  is retracted, the flowline valve  179  may be opened. With enough pressure drop, the formation fluid will breach its bubble point and any gas in the formation fluid will come out of solution. If the bubble point is not breached, then the test is repeated until enough of an initial pressure drop is created to breach the bubble point. Normally the pretest is moved at it slowest rate while monitoring pressure of the sealed flowline. Then the method of determining the bubble point would be similar to that shown earlier for a pretest drawdown. Basically linear regressions can be used to determine when a slope change occurs. Alternatively the first or second derivative as well as nonlinear regression methods can be used to determine the bubble point. It is also desirable to measure the piston displacement to more accurately monitor the actual rate and volume change. Alternatively the volume change over the total initial trapped volume can be plotted against pressure to improve the bubble point estimate and determine fluid compressibility. 
   To measure the bubble point pressure from the test, the formation tester  10  may use the position of the drawdown piston  170  as the drawdown piston  170  retracts during the drawdown portion of the pressure test. Knowing the position of the drawdown piston  170 , the volume of the cylinder  175  at all positions of drawdown piston  170  may then be calculated. One method to determine position of the drawdown piston  170  is to measure the amount of hydraulic fluid used to drawdown the drawdown piston  170 , the time, and the flowrate of the hydraulic fluid pumped by the hydraulic pump  66 . Then, knowing the surface area of the face of the drawdown piston  170  facing the flowline side  172   a  of the cylinder  172 , the position of the drawdown piston  1 . 70  may be calculated. The displacement distance of the drawdown piston  170  is the change in volume of the hydraulic fluid divided by the surface area of the drawdown piston  170  facing the flowline side  172   a . The change in volume is calculated by multiplying the amount of time by the flowrate of the hydraulic fluid. Another method of determining position is using a position indicator such as an acoustic sensor, an optical sensor, a linear variable displacement transducer, a potentiometer, a Hall Effect sensor, or any other suitable position indicator or any other suitable method of determining position of the drawdown piston  170 . 
   The pressure at which the formation fluid reaches the bubble point can be calculated during the pressure test manually or by using the controller  190 . The controller  190  continuously records elapsed time and the formation fluid pressure during the pre-test. The controller  190  can also calculate the volume of the formation fluid in the cylinder  175  by using the elapsed time, hydraulic pump rate, and the position information of the drawdown piston  170  by the following relationship: 
             Formation   ⁢           ⁢   Fluid   ⁢           ⁢   Volume     =         (     Area   dd     )     ⁢     (     Hydraulic   ⁢           ⁢   Pump   ⁢           ⁢   Rate     )     ⁢     (   Time   )         (     Area   hyd     )             
Where Area dd  is the area of the drawdown piston  170  on the flow line side  172   a  and Area hyd  is the area of drawdown piston  170  on the hydraulic oil side  172   b . The master controller  190  can continuously calculate the compressibility of the fluid in the flow line  93 , where compressibility is the ratio of the formation fluid pressure to the formation fluid volume. The bubble point may be the pressure where these calculated ratios change.
 
   An example of compressibility and bubble point determination is illustrated in  FIG. 14 , where volume change over the initial volume is plotted against pressure. The straight line portion is used to determine the fluid compressibility and the bubble point is determined with the pressure curve deviates from the straight line. The bubble point can be determined by the curve fitting methods previously discussed. 
   Once the bubble point pressure of the formation fluid has been determined, the operating mode of the formation tester  10  may be adjusted so as to stay above the bubble point and keep the gas in solution in the formation fluid during the pressure test. 
   For example, the formation tester  10  may variably control the drawdown volume created in the cylinder  175  during the pressure test. The most effective method of controlling the drawdown volume is by using the cutoff pressure discussed previously. It is normally desirable to also slow the rate to improve the cutoff pressure methods accuracy. 
   Alternatively, formation tester  10  may variably control the drawdown rate of the drawdown piston  170  so as to stay above the bubble point pressure. As discussed previously if the formation spherical mobility can be estimated then a rate can be calculated that would keep the drawdown pressure above the bubble point. 
   Also alternatively, the formation tester  10  may variably control both the drawdown volume and the drawdown rate of the drawdown piston  170  as discussed above. 
   The formation tester  10  may variably control the drawdown of the drawdown piston  170  to maintain a certain pressure within the cylinder  175  manually or automatically. When done manually, the measured pressure information from the pressure test is recorded and/or sent to the surface where it is monitored and analyzed. Using the calculated bubble point information, commands may be sent to the formation tester  10  to vary the drawdown procedure and avoid the bubble point for the next pressure test as discussed previously. When done automatically, the pressure test information is sent to the controller  190  for analysis of the bubble point. The controller  190  then automatically adjusts the drawdown volume and/or rate of the drawdown piston  170  for the next drawdown procedure to avoid breaching the bubble point as discussed above. 
   Another mode of operation involves the consistency of the drawdown rate of the drawdown piston  170  during a pressure test. Typically, the formation tester  10  does not change the drawdown rate of the drawdown piston  170  during a pressure test. However, the controller  190  may change the drawdown rate of the drawdown piston  170  during a drawdown by controlling the hydraulic pump  66 . Regardless, when being drawn down, the drawdown piston  170  should maintain a substantially constant drawdown rate until the controller  190  adjusts the drawdown rate. Although the positional information of the drawdown piston  170  during drawdown may be taken into account in any pressure test calculations, not maintaining the drawdown rate of the piston  170  constant may affect the accuracy of pressure test measurements and calculations. Maintaining a constant drawdown rate may be difficult to achieve, however, due to the start-up, shut-down, or otherwise inconsistent output of the electric motor  64  and hydraulic pump  66 , as well as other system factors. 
   To maintain the drawdown rate of the drawdown piston  170  substantially constant, the formation tester  10  may send the drawdown piston  170  positional information to the controller  190 . The controller  190  uses the positional information to calculate the drawdown rate of the piston  170 . Based on the calculations, the controller determines if adjustments need to be made in the hydraulic system  200  during the drawdown of the drawdown piston  170  to maintain a substantially constant drawdown rate. 
     FIG. 15  illustrates another method of maintaining a substantially constant drawdown rate using a hydraulic threshold  406 , for example a sequencing valve, downstream of the hydraulic pump  66 . The hydraulic threshold  406  requires that a certain hydraulic pressure be achieved by the electric motor  64  and hydraulic pump  66  before the hydraulic fluid is allowed to pass through the hydraulic threshold  406 . For example, the minimum hydraulic pressure might be 2500 psi above the borehole pressure. Thus, the hydraulic threshold  406  acts to allow the pressure to build up before the pressure is allowed to act on the drawdown piston  170 . Then, if the same hydraulic load is maintained on the hydraulic pump  66 , the displacement for a given depth and for a given set of environmental conditions will be constant and the drawdown rate of the drawdown piston  170  will be substantially constant. 
     FIG. 16  illustrates another method of maintaining a steady drawdown rate with a pressure compensated variable restrictor  408  in the hydraulic flowline  93  downstream of the hydraulic pump  66 . The variable restrictor  408  maintains a constant hydraulic flowrate independent of the required hydraulic load. Therefore, the drawdown piston  170  is able to drawdown at a constant rate independent of the actual drawdown pressure achieved within flowline  93 . 
     FIG. 17  illustrates another operating mode that allows the formation tester  10  to perform a burst test. The burst test may be performed when the drawdown piston  170  cannot drawdown fast enough to create a sufficient pressure drop for the pressure test. To perform the burst test, the formation tester  10  closes the flowline valve  179  to isolate the cylinder  175  from the pad  140 . The drawdown piston  170  is then drawn down to create a pressure drop within the cylinder  175  and flowline  93  behind the flowline valve  179 . The flowline valve  179  is then opened to create a pressure drop in the pad  140  side of the flowline  93  that is large enough to get sufficient drawdown for the pressure test. The flowline valve  179  is closed by actuating solenoid valve  412 , which directs pressurized hydraulic fluid from the pump  66  to the actuator of valve  179 . While the flowline valve  179  is closed, the pressure of the flowline upstream of the flowline valve  179  (pad side) may be monitored by the pressure transducer  160   d . The flowline valve  179  may be opened by de-actuating solenoid valve  412  and actuating solenoid valve  410 . The burst test thus allows the formation tester  10  to create a larger pressure drop than if the drawdown piston  170  were drawn down in a typical pressure test due to the creation of the pressure drop before the formation fluid enters the cylinder  175 . 
   Another operating mode allows the formation tester  10  to make adjustments during the pressure test relating to the seal formed by seal pad  140  of formation probe assembly  50  against the borehole wall  151  or the mudcake  49 . As mentioned above, the operating environment of the borehole  8  can change during the pressure test with either a change in pressure or a deterioration of the borehole wall  151 . The electric motor  64 , hydraulic pump  66 , hydraulic manifold  62 , equalizer valve  60 , formation probe assembly  50 , or any other parts of hydraulic system  200  may also affect the ability to maintain a proper seal against the mudcake  49  or borehole wall  151 . 
   The formation tester  10  makes adjustments by monitoring the integrity of the seal of the pad  140  using the pressure transducers  160   a–d . The formation tester  10  uses the transducer data to make adjustments manually using data sent back and forth between the surface and the controller  190  or automatically by sending the monitored information to the controller  190  for analysis. For example, if the monitored pressure approaches the previously measured borehole pressure, then the seal may have been formed improperly. If an improper seal was made, the controller  190  may retract the pad  140  and re-initiate the pressure test. Alternatively, a leak may occur during the pressure test causing the pad  140  to seal improperly. If the seal deteriorates, the formation tester  10  may make adjustments to the hydraulic system  200  to vary the pad force against the mudcake  149  or borehole wall  151 . For example, the controller  190  may increase the hydraulic pressure to exert more force by the pad  140  against the mudcake  49  or the borehole wall  151 . Additionally, even if the formation tester  10  makes any adjustments automatically, then the tool  10  may send information regarding the adjustments to the surface as well as information regarding the amount of additional time needed to properly run the pressure test. 
   Alternatively, the formation tester  10  may comprise a sequencing valve, similar to the valve  192  discussed above, that requires a minimum pressure on the pad  140  to create force against the mudcake  49  or the borehole wall  151  before the pressure test may be performed. Although the amount of pressure may not guarantee a good seal, the sequencing valve ensures that a designated minimum pressure be placed on the pad  140  before the pressure test may be performed. 
   The controller  190  may also be used to vary any one of the pressure test parameters to experiment with and optimize the testing procedures. For example, the buildup, drawdown rate, drawdown volume, pad load, or any other parameter may be varied to observe the changes, if any, to the results of the formation pressure test. The results may then be analyzed by the controller  190  and the testing procedures changed to obtain more precise formation pressure measurements. 
   While specific embodiments have been illustrated and described, one skilled in the art can make modifications without departing from the spirit or teaching of this invention. The embodiments as described are exemplary only and are not limiting. Many variations and modifications are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.