Patent Publication Number: US-9845675-B2

Title: Formation tester tool assembly and method

Description:
PRIORITY APPLICATIONS 
     This application is a continuation of and claims the benefit of priority to U.S. patent application Ser. No. 14/588,722, filed Jan. 2, 2015, which is a continuation of U.S. patent application Ser. No. 11/174,711, filed 5 Jul. 2005 and issued as U.S. Pat. No. 8,950,484 on Feb. 10, 2015. Both Applications are incorporated herein by reference in their entirety. 
    
    
     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, bubblepoint and formation pressure gradient. 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 testing (DST) have been commonly used to perform these tests. The basic DST test 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 clean formation fluids at the end of the test. WFTs generally employ the same testing techniques but use a wireline to lower the test tool into the well bore after the drill string has been retrieved from the well bore, although WFT technology is sometimes deployed on a pipe string. The wireline tool typically uses packers also, although the packers are placed closer together, compared to drill pipe conveyed testers, for more efficient formation testing. In some cases, packers are not 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 fluids, a non-representative sample will be obtained and the test will have to be repeated. 
     With the use of WFTs and DSTs, the drill string with the drill bit must 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 filtrate invasion and mudcake buildup because significant amounts of time may have passed before a DST or WFT engages the formation. 
     Another testing apparatus is a measurement while drilling (MWD) or logging while drilling (LWD) tester. Typical LWD/MWD formation testing equipment is suitable for integration with a drill string during drilling operations. Various devices or systems are provided for isolating a formation from the remainder of the wellbore, drawing fluid from the formation, and measuring physical properties of the fluid and the formation. With LWD/MWD testers, the testing equipment is subject to harsh conditions in the wellbore during the drilling process that can damage and degrade the formation testing equipment before and during the testing process. These harsh conditions include vibration and torque from the drill bit, exposure to drilling mud, drilled cuttings, and formation fluids, hydraulic forces of the circulating drilling mud, and scraping of the formation testing equipment against the sides of the wellbore. Sensitive electronics and sensors must be robust enough to withstand the pressures and temperatures, and especially the extreme vibration and shock conditions of the drilling environment, yet maintain accuracy, repeatability, and reliability. 
     Sometimes, smaller diameter formation testing equipment is needed as the tool goes deeper into a borehole. However, decreasing the size of the tool makes it difficult to incorporate the full functionality of features needed in the tool, as discussed above. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more detailed description of preferred embodiments of the present invention, reference will now be made to the accompanying drawings, wherein: 
         FIG. 1  is a schematic elevation view, partly in cross-section, of an embodiment of a formation tester apparatus disposed in a subterranean well; 
         FIG. 2A  is a side view of a portion the bottomhole assembly and formation tester tool assembly shown in  FIG. 1 ; 
         FIG. 2B  is a cross-section side view of  FIG. 2A ; 
         FIG. 3A  is an enlarged side view of the formation tester tool of  2 A; 
         FIG. 3B  is a cross-section side view of  FIG. 3A ; 
         FIG. 4  a cross-section side view of a formation probe assembly according to one embodiment; 
         FIG. 5  is an enlarged cross-section top view of the formation probe assembly of  FIG. 4 ; 
         FIG. 6  is a cross section view of a piston of the probe assembly of  FIG. 5 ; 
         FIG. 7  is a cross-section top view of a pad for a probe assembly, in accordance with one embodiment; 
         FIG. 8A  is a cross-section side view of the pad of  FIG. 7 ; 
         FIG. 8B  shows a perspective view of the pad of  FIG. 7 ; 
         FIG. 9  shows a cross-section side view of a draw drown assembly, in accordance with one embodiment; 
         FIG. 10  shows a cross-section side view of a draw drown assembly, in accordance with one embodiment; and 
         FIG. 11  shows a cross-section side view of a draw drown assembly, in accordance with one embodiment. 
         FIG. 12  shows a flow chart of a method in accordance with one embodiment. 
         FIG. 13  shows a flow chart of a method in accordance with one embodiment. 
     
    
    
     DETAILED DESCRIPTION 
     In the following detailed description, reference is made to the accompanying drawings which form a part hereof, and in which is shown by way of illustration specific embodiments in which the invention may be practiced. These embodiments are described in sufficient detail to enable those skilled in the art to practice the invention, and it is to be understood that other embodiments may be utilized and that structural changes may be made without departing from the scope of the present invention. Therefore, the following detailed description is not to be taken in a limiting sense, and the scope of the present invention is defined by the appended claims and their equivalents. 
     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 or distal end 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. 
     To understand the mechanics of formation testing, it is important to first understand how hydrocarbons are stored in subterranean formations. Hydrocarbons are not typically located in large underground pools, but are instead found within very small holes, or pore spaces, within certain types of rock. Therefore, it is critical to know certain properties of both the formation and the fluid contained therein. At various times during the following discussion, certain formation and formation fluid properties will be referred to in a general sense. Such formation properties include, but are not limited to: pressure, permeability, viscosity, mobility, spherical mobility, porosity, saturation, coupled compressibility porosity, skin damage, and anisotropy. Such formation fluid properties include, but are not limited to: viscosity, compressibility, flowline fluid compressibility, density, resistivity, composition and bubble point. 
     Permeability is the ability of a rock formation to allow hydrocarbons to move between its pores, and consequently into a wellbore. Fluid viscosity is a measure of the ability of the hydrocarbons to flow, and the permeability divided by the viscosity is termed “mobility.” Porosity is the ratio of void space to the bulk volume of rock formation containing that void space. Saturation is the fraction or percentage of the pore volume occupied by a specific fluid (e.g., oil, gas, water, etc.). Skin damage is an indication of how the mud filtrate or mud cake has changed the permeability near the wellbore. Anisotropy is the ratio of the vertical and horizontal permeabilities of the formation. 
     Resistivity of a fluid is the property of the fluid which resists the flow of electrical current. Bubble point occurs when a fluid&#39;s pressure is brought down at such a rapid rate, and to a low enough pressure, that the fluid, or portions thereof, changes phase to a gas. The dissolved gases in the fluid are brought out of the fluid so gas is present in the fluid in an undissolved state. Typically, this kind of phase change in the formation hydrocarbons being tested and measured is undesirable, unless the bubblepoint test is being administered to determine what the bubblepoint pressure is. 
     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 , a formation tester tool  10  is shown as a part of bottom hole assembly  6  which includes an MWD sub  13  and a drill bit  7  at its lower most end. Bottom hole assembly  6  is lowered from a drilling platform  2 , such as a ship or other conventional platform, via drill string  5 . Drill string  5  is disposed through riser  3  and well head  4 . Conventional drilling equipment (not shown) is supported within derrick  1  and rotates drill string  5  and drill bit  7 , causing bit  7  to form a borehole  8  through the formation material  9 . The borehole  8  penetrates subterranean zones or reservoirs, such as reservoir  11 , that are believed to contain hydrocarbons in a commercially viable quantity. It should be understood that 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  contains 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 formation tester  10  is shown as part of drill string  5 , the embodiments of the invention described below may be conveyed down borehole  8  via any drill string or wireline technology, as is partially described above and is well known to one skilled in the art. 
     Referring now to  FIGS. 2A-2B , portions of the formation tester tool  10  are shown. Tester tool  10  includes a fillport assembly having fillport  24  for adding or removing hydraulic or other fluids to the tool  10 . Below fillport  24  is hydraulic insert assembly  30 . Tool  10  also including an equalizer valve  60 , a formation probe assembly  50  and a draw down piston assembly  70 . Also included is pressure instrument assembly  80 , including the pressure transducers used by probe assembly  50 . 
     Referring now to  FIGS. 3A-3B , formation probe assembly  50  is disposed within probe drill collar  12 , and covered by probe cover plate  51 . Also disposed within probe collar  12  is equalizer valve  60  and draw down assembly  70 . Adjacent formation probe assembly  50  and equalizer valve  60  is a flat  136  in the surface of probe collar  12 . 
     As best shown in  FIG. 3B , it can be seen how formation probe assembly  50  and equalizer valve  60  and draw down assembly  70  are positioned in probe collar  12 . Formation probe assembly  50  and equalizer valve  60  and draw down assembly  70  are mounted in probe collar  12  just above the flow bore  14 . As will be further discussed below, flow bore  14  includes a curving longitudinal path as it advances longitudinally through drill collar  12 . 
     Further details of formation probe assembly  50  are shown in  FIGS. 4 and 5 . Formation probe assembly  50  generally includes stem a  92 , a piston chamber  94 , a piston  96  adapted to reciprocate within piston chamber  94 , and a snorkel  98  adapted for reciprocal movement within piston  96 . Snorkel  98  includes a base portion  125  and a central passageway  127 . Cover plate  51  fits over the top of probe assembly  50  and retains and protects assembly  50  within probe collar  12 . Formation probe assembly  50  is configured such that piston  96  extends and retracts through aperture  52  in cover plate  51 . Stem  92  includes a circular base portion  105 . Extending from base  105  is a tubular extension  107  having central passageway  108 . Central passageway  108  is in fluid connection with fluid passageways leading to other portions of tool  10 , including equalizer valve  60  and drawn down assembly  70 . Thus, a fluid passageway is formed from the formation through central passageway  127  and central passageway  108  to the other parts of the tool. 
     In one embodiment, piston chamber  94  is integral with drill collar  12  of tool  10  and includes an inner surface  113  having reduced diameter portions  114 ,  115  to guide piston  96  as it extends and retracts. A seal  116  is disposed in surface  114 . In some embodiments, piston chamber  94  can be a separate housing mounted within tool  10 , by a threaded engagement, for example. 
     Piston  96  is slidingly retained within piston chamber  94  and generally includes outer surface  141  having an increased diameter base portion  118 . A seal  143  is disposed in increased diameter portion  118 . Just below base portion  118 , piston  96  rests on stem base portion  105  when probe assembly  50  is in the fully retracted position as shown in  FIG. 4 . Piston  96  also includes a shoulder  172  and a central bore  120 . 
     Formation probe assembly  50  is assembled such that piston base  118  is permitted to reciprocate along surface  113  of piston chamber  94 , and piston outer surface  141  is permitted to reciprocate along surface  114 . Similarly, snorkel base  125  is disposed within piston  96  and is adapted for reciprocal movement along the inner surface of the piston. Central passageway  127  of snorkel  98  is axially aligned with tubular extension  107  of stem  92 . Formation probe assembly  50  is reciprocal between a fully retracted position, as shown in  FIG. 4 , and a partially extended position, as shown in  FIG. 5 . In use, snorkel  98  further extends into the formation wall to communicate with the formation fluid. 
     Sensors can also be disposed in formation probe assembly  50 . For example, a temperature sensor  51 , known to one skilled in the art, may be disposed on the probe assembly for taking annulus or formation temperature. In the probe assembly retracted position, the sensor would be adjacent the annulus environment, and the annulus temperature could be taken. In the probe assembly extended position, the sensor would be adjacent the formation, allowing for a formation temperature measurement. Such temperature measurements could be used for a variety of reasons, such as production or completion computations, or evaluation calculations such as permeability and resistivity. 
     At the top of piston  96  is a seal pad  180 . Seal pad  180  may be donut-shaped with a curved outer sealing surface and central aperture  186 . The base surface of seal pad  180  may be coupled to a skirt  182 . Seal pad  180  may be bonded to skirt  182 , or otherwise coupled to skirt  182 , such as by molding seal pad  180  onto skirt  182  such that the pad material fills grooves or holes in skirt  182 . Skirt  182  is detachably coupled to piston  96  by way of threaded engagement, or other means of engagement, such as a pressure fit with the central bore surface  120 . Alternatively, pad  180  may be coupled directly to extending portion  119  without using a skirt. 
     In one embodiment, seal pad  180  includes an elastomeric material, such as rubber or plastic. In other embodiments, seal pad  180  can be metallic or a metal alloy. Using a metallic pad is advantageous since the metallic pad does not break down under downhole conditions as elastomeric pads might. Seal pad  180  seals and prevents drilling fluid or other contaminants from entering the probe assembly  50  during formation testing. More specifically, seal pad  180  seals against the filter cake that may form on a 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 filter cake on the borehole wall and separates the two pressure areas. Pad  180 , when extended, contacts the borehole wall and, together with the filter cake, forms a seal through which formation fluids can be collected. 
     In an alternative embodiment of the seal pad, the pad may have an internal cavity such that it can retain a volume of fluid. A fluid may be pumped into the pad cavity at variable rates such that the pressure in the pad cavity may be increased and decreased. Fluids used to fill the pad may include hydraulic fluid, saline solution or silicone gel. By way of example, the pad may be unfilled or unpressured as the probe extends to engage the borehole wall, then when the probe contacts the wall the pad can be filled. In another example, the probe can be filled before the probe is extended. Depending on the contour of the borehole wall, the pad may be pressured up by filling the pad with fluid, thereby conforming the pad surface to the contour of the borehole wall and providing a better seal. 
     In yet another embodiment of the seal pad, the pad may be filled, either before or after engagement with the borehole wall, with an electro-visco rheological fluid. After the pad has engaged the borehole wall and conformed to it, an electrical current may be applied to the electro-visco rheological fluid such that the current changes the state of the fluid, for example from liquid to gel or solid, and sets the pad conformation, thereby providing a better seal. 
     Referring to  FIGS. 7, 8A, and 8B , in one embodiment the outer surface of pad  180  defines a partial cylinder surface shape, as opposed to flat or spherical surface.  FIG. 7  shows a top view of a cross-section of pad  180  and  FIG. 8A  shows cross-section from the side, while  FIG. 8B  shows a perspective view of pad  180 . The outer surface of pad  180  is generally congruent to the inner surface of a cylindrical wall of borehole  16  ( FIG. 5 ). This means the pad exerts generally equal pressure against the wall at all parts of it surface. This provides for a better seal. In some embodiments, skirt  182  can have an outer surface defining a partial cylindrical shape and the seal pad  180  can have equal thickness throughout. In that case, the pressure throughout the pad itself would be more equal. 
     Referring to  FIGS. 5 and 6 , further details of piston  96  will be described.  FIG. 6  shows a cross-section of piston  96 , it can be seen that the piston includes a non-circular shape around its outer surface  141 . Likewise surface  114  of chamber  94  is matched to the shape of piston  96 . 
     In some embodiments, the piston  96  and the chamber  94  are keyed to each other so that the piston does not rotate relative to chamber  94  as piston  96  is extended. In this example, the piston  96  defines an elliptical shape with a first diameter D 1  greater than a second diameter D 2 . Surface  114  defines a similar shape. For example, the ratio between D 1  and D 2  can be about 1.03:1.00. In other options, piston  96  can include one or more straight walls along its outer surface  141  and chamber  94  can include a similar shape. Another option is to provide one or more projections along the outer surface of piston  96  and corresponding guiding grooves in the surface of surface  114 . 
     This matching or keyed non-circular shape keeps the piston oriented in the proper position as it is extended so that pad  180 , which as noted above includes an outer cylindrical surface, meets the cylindrical wall  16  at the proper orientation to ensure a good seal. This can be an advantage in a small diameter tool, such as a 4¾″ tool  10 , where the wall  16  may be relatively far from the tool and if not oriented correctly piston  96  could rotate and the cylindrical outer surface of pad  180  would hit the wall at an odd orientation. 
     Referring now also to  FIG. 12 , which depicts a method  1200 , in accordance with one embodiment, of utilizing the formation probe assembly discussed above. Method  1200  includes using a formation tester tool having a formation probe assembly  50 , placing the probe assembly down a bore hole, extending a piston  96  such that a seal pad  180  extends towards the bore hole wall, and guiding the piston  96  such that the piston does not substantially rotate as the piston is extending. 
     Accordingly, as piston  96  is extended, the surface of outer surface  141  of the piston is guided by the inner surface  114  of chamber  94  so to keep piston  96  substantially oriented as it is extended towards the formation wall such that piston  96  does not rotate so much that it does not meet the wall at an acceptable angle. Moreover, by keeping the pad  180  properly oriented, the present system allows for use of a metallic pad in place of an elastomeric one since a properly oriented metallic, cylindrically-shaped pad can provide a proper seal. 
     The operation of formation probe assembly  50  will now be described. Probe assembly  50  is normally in the retracted position ( FIG. 4 ). Assembly  50  remains retracted when not in use, such as when the drill string is rotating while drilling if assembly  50  is used for an MWD application, or when the wireline testing tool is being lowered into borehole  8  if assembly  50  is used for a wireline testing application. 
     Upon an appropriate command to formation probe assembly  50 , a force is applied to the base portion of piston  96 , preferably by using hydraulic fluid. Piston  96  raises relative to the other portions of probe assembly  50  until base portion  118  comes into contact with a shoulder  170  of chamber  94 . After such contact, probe assembly  50  will continue to pressurize a reservoir  54  until reservoir  54  reaches a maximum pressure. Alternatively, if pad  180  comes into significant contact with a borehole wall before base portion  118  comes into contact with shoulder  170 , probe assembly  50  will continue to apply pressure to pad  180  by pressurizing reservoir  54  up to the previously mentioned maximum pressure. The maximum pressure applied to probe assembly  50 , for example, may be 1,200 p.s.i. 
     The continued force from the hydraulic fluid in reservoir  54  causes snorkel assembly  98  to extend such that the outer end of the snorkel extends beyond seal pad surface  183  through seal pad aperture  186 . Snorkel assembly  98  stops extending outward when shoulder  123  comes into contact with a shoulder  172  of piston  96 . 
     Alternatively, if snorkel assembly  98  comes into significant contact with a borehole wall before shoulder  123  comes into contact with shoulder  172  of piston  96 , continued force from the hydraulic fluid pressure in reservoir  54  is applied up to the previously mentioned maximum pressure. The maximum pressure applied to snorkel assembly  98 , for example, may be 1,200 p.s.i. Preferably, the snorkel and seal pad will contact the borehole wall before either piston  96  or snorkel  98  shoulders at full extension. 
     If, for example, seal pad  180  had made contact with the borehole wall  16  before being fully extended and pressurized, then seal pad  180  should seal against the mudcake on borehole wall  16  through a combination of pressure and pad extrusion. The seal separates central passageways  127  and  108  from the mudcake, drilling fluids and other contaminants outside of seal pad  180 . 
     To retract probe assembly  50 , forces, or pressure differentials, may be applied to snorkel  98  and piston  96  in opposite directions relative to the extending forces. Simultaneously, the extending forces may be reduced or ceased to aid in probe retraction. 
     In another embodiment, the probe can be a telescoping probe including a second inner piston to further extend the probe assembly. In other embodiments, formation tester tool  10  can further include fins or hydraulic stabilizers or a heave compensator located proximate formation probe assembly  50  so as to anchor the tool and dampen motion of the tool in the bore hole. 
     Referring again to  FIG. 4 , it can be seen that probe collar  12  also houses draw down assembly  70 . Referring now to  FIG. 9 , draw down piston assembly  70  generally includes an annular seal  502 , a piston  506 , a plunger  510  and an endcap  508 . Piston  506  is slidingly received in cylinder  504  and plunger  510 , which is integral with and extends from piston  506 , is slidingly received in cylinder  514 . In  FIG. 9 , piston  506  is biased to its uppermost or shouldered position at shoulder  516 . For example, a bias spring (not shown) biases piston  506  to the shouldered position, and can disposed in cylinder  504  between piston  506  and endcap  508 . Separate hydraulic lines (not shown) interconnect with cylinder  504  above and below piston  506  in portions  504 A,  504 B to move piston  506  either up or down within cylinder  504  as described more fully below. Plunger  510  is slidingly disposed in cylinder  514  coaxial with cylinder  504 . Cylinder  514 A is the upper portion of cylinder  514  that is in fluid communication with the fluid passageway that interconnects with probe assembly  50  and equalizer valve  60 . Cylinder  514 A is filled with fluid via its interconnection with the fluid passageways of tool  10 . Cylinder  514  is filled with hydraulic fluid via its interconnections with a hydraulic circuit. Cross piloted check valves can be used to stop the piston  506  when it has moved far enough. In this example, piston  506  moves in a longitudinal fashion relative to a length of the tool. This is necessary in a small diameter tool  10 , for example a 4¾″ tool. In various embodiments, tool  10  and probe collar  12  can be different sizes. For example, in any of the embodiments described herein, probe drill collar  12  can include a diameter of about 4¾″ or less, or a diameter of about 6¾″ or less, or a diameter of about 8″ or less, or a diameter of about 9″ or less. 
     In one embodiment, the tool  10  includes interchangeable draw down assemblies. For example, referring to  FIG. 10 , a second draw down assembly  272  is shown. Draw down assembly  272  is similar to assembly  70 , with the most notable difference being that the draw down volume is smaller since a plunger  510 B and a cylinder  514 B have smaller cross-sectional areas than the corresponding plunger and cylinder of assembly  70 . Other members of assembly  272  are the same as above for assembly  70 . 
     Referring to  FIG. 11 , a third draw down assembly  372  is shown. Draw down assembly  372  is similar to assembly  70  and assembly  272 , with the most notable difference being that the draw down volume is smaller since a plunger  510 C and a cylinder  514 C have smaller cross-sectional areas than the corresponding plunger and cylinder of assembly  70 , and smaller cross-sectional areas than the corresponding plunger and cylinder of assembly  272 . Other members of assembly  372  are the same as above for assembly  70  and assembly  272 . 
     Each draw down assembly  70 ,  272 ,  372  includes the same size and shape outer housing  970 . Referring to  FIG. 4 , tool  10  includes a mounting section  981  for draw down assembly  70 . Each housing  970  of each draw down assembly  70 ,  272 , and  372  mounts similarly and interchangeably to mounting section  981  of tool  10 . For example, outer housings  970  can includes holes or other means to fasten the assembly within the mounting section of the tool. This allows the draw down assemblies  70 ,  272 , and  372  to be interchangeably exchanged within the tool. This allows different drawdown rates and/or sample volumes, for example. Tool mounting section  981  includes hydraulic and electrical interconnects that are the same between each housing  970  of each assembly  70 ,  272 , and  372 . Likewise, each assembly  70 ,  272 , and  372  includes hydraulic, fluid, and electrical interconnections that match the interconnections of the other draw down assemblies and match the interconnections provided in mounting section  981 . 
     As noted, each different drawdown assembly  70 ,  272 , and  372  has a different plunger size/volume while each includes an outer housing  970  configured to mount interchangeably in the mounting section  981 . In other words, they each have the same size outer housing  970  with different size inner configurations. In use, one draw down assembly can be mounted in section  981  and used. When the tool is retrieved, the assembly can be removed a different assembly mounted to section  981 . Referring now also to  FIG. 13 , a method  1300  according to one embodiment will be described. Method  1300  includes selectively choosing one draw down assembly from a plurality of drawn down assemblies  70 ,  272 ,  372 , disposing a probe drill collar in a borehole, extending the extendable probe assembly, actuating the selected draw down assembly from a first position to a second position, and drawing fluid into the probe assembly. 
     Table 1 shows different values which are the result of using the different drawdown assemblies discussed above. 
     
       
         
           
               
               
               
               
             
               
                 TABLE 1 
               
               
                   
               
               
                 Draw down assembly 
                 Medium (FIG. 10) 
                 Low (FIG. 11) 
                 High (FIG. 9) 
               
               
                   
               
             
            
               
                 Max Draw down at 
                 5552 psi 
                 10070 psi 
                 2203 psi 
               
               
                 1600 psi 
                   
                   
                   
               
               
                 Draw down rate at 
                 2.0 cc/sec 
                 1.1 cc/sec 
                 5.1 cc/sec 
               
               
                 1500 RPM 
                   
                   
                   
               
               
                 Draw down rate at 
                 0.2 cc/sec 
                 0.1 cc/sec 
                 0.5 cc/sec 
               
               
                  150 RPM 
                   
                   
                   
               
               
                   
               
            
           
         
       
     
     Being able to interchange different draw down assemblies is especially advantageous in a low power MWD application where there is low power available and the draw down rate needs to be variable. 
     In some embodiments, a position indicator may also be applied to the draw down assemblies discussed above for knowing where in the cylinder the draw down piston is located, and how the piston is moving. For example, with reference to  FIG. 3B , the drawn down assembly  70  includes a position indicator  71 . Volume and diameter parameters of the cylinder may be used to calculate the distance the piston has moved. With a known radius r of the cylinder and a known volume V of hydraulic fluid pumped into the cylinder from either side of the piston, the distance d the piston has moved may be calculated from the equation V=π(r 2 )(d). Alternatively, sensors, such as optimal sensors, acoustic sensors, potentiometers, or other resistance-measuring devices can be used. Further, the steadiness of the draw down may be obtained from the position indicator. The rate may be calculated from the distance measured over a given time period, and the steadiness of the rate may be used to correct other measurements. 
     For example, to gain a better understanding of the formation&#39;s permeability or the bubble point of the formation fluids, a reference pressure may be chosen to draw down to, and then the distance the draw down piston moved before that reference pressure was reached may be measured by the draw down piston position indicator. If the bubble point is reached, the distance the piston moved may be recorded and sent to the surface, or to the software in the tool, so that the piston may be commanded to move less and thereby avoid the bubble point. 
     It will be understood that the draw down assemblies may have plungers that vary in size such that their volumes vary. The assemblies may also be configured to draw down at varying pressures. The embodiment just described includes three draw down assemblies, but the formation tester tool system may include more or less than three. 
     Use of the draw down assemblies will be discussed with reference to  FIGS. 4, 5 , and  9 . A hydraulic circuit can be used to operate the probe assembly  50 , equalizer valve  60  and draw down assembly  70 . As discussed above, probe assembly  50  extends until pad  180  engages the mud cake on borehole wall  16 . With hydraulic pressure continuing to be supplied to the extend side of piston  96  and snorkel  98  for assembly  50 , the snorkel may then penetrate the mud cake. The outward extensions of pistons  96  and snorkel  98  continue until pad  180  engages the borehole wall  16 . This combined motion continues until the pressure pushing against the extend side of piston  96  and snorkel  98  reaches a pre-determined magnitude, for example 1,200 p.s.i., controlled by a relief valve for example, causing pad  180  to be squeezed. At this point, a second stage of expansion takes place with snorkel  98  then moving within the bore  120  in piston  96  to penetrate the mud cake on the borehole wall  16  and to receive formation fluids or take other measurements. 
     After the equalizer valve  60  closes, thereby isolating the fluid passageway from the annulus, the fluid passageway from the formation, now closed to the annulus  15 , is in fluid communication with cylinder  514 A at the upper ends of cylinder  514  in draw down assembly  70 . 
     Pressurized fluid then enters portion  504 A of cylinder  504  causing draw down piston  506  to retract. When that occurs, plunger  510  moves within cylinder  514  such that the volume of the fluid passageway increases by the volume of the area of the plunger  510  times the length of its stroke along cylinder  514 . The volume of cylinder  514 A is increased by this movement, thereby increasing the volume of fluid in the passageway. 
     With reference to  FIG. 3B , a controller  91  may be used to command draw down assembly  70  to draw down fluids at differing rates and volumes. For example, draw down assembly  70  may be commanded to draw down fluids at 1 cc per second for 10 cc and then wait 5 minutes. If the results of this test are unsatisfactory, a downlink signal may be sent using mud pulse telemetry, or another form of downhole communication to command assembly  70  to now draw down fluids at 2 cc per second for 20 cc and then wait 10 minutes, for example. The first test may be interrupted, parameters changed and the test may be restarted with the new parameters that have been sent from the surface to the tool. These parameter changes may be made while probe assembly  50  is extended. 
     With the draw down assembly  70  in its fully, or partially, retracted positions and anywhere from one to 90 cc of formation fluid drawn into the closed system, the pressure will stabilize enabling pressure transducers to sense and measure formation fluid pressure. The measured pressure is transmitted to the controller in the electronic section where the information is stored in memory and, alternatively or additionally, is communicated to a master controller in the MWD tool  13  ( FIG. 1 ) below formation tester  10  where it can be transmitted to the surface via mud pulse telemetry or by any other conventional telemetry means. 
     The uplink and downlink commands used by tool  10  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 down hole receiver for downlink commands or data from the surface may reside within the formation test tool 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 test tool  10  or within an MWD tool  13  with which it communicates. In the preferred embodiment specifically described, the receivers and transmitters are each positioned in MWD tool  13  and the receiver signals are processed, analyzed and sent to a master controller in the MWD tool  13  before being relayed to a local controller in formation testing tool  10 . 
     Referring again to  FIGS. 2B, 3B, and 4 , in one embodiment, flow bore  14  includes a curved longitudinal path throughout the length of the probe drill collar  12  section of the tool. For example, flow bore  14  includes a depth deeper than the probe assembly  50  depth and is curved throughout a substantial portion of the drill collar housing. Again this is advantageous for making space within a 4¾″ diameter tool for probe assembly  50 . To form the continuously curving flow bore  14 , the flow bore is formed such that it is substantially curved all along the entire length. One company that can form such a longitudinally running, completely curving flow bore is Dearborn Precision Tubular Products, Inc. of Fryeburg, Me. 
     In other embodiments, the path of flow bore  14  can be substantially curved or partially straight and partially curved. For example, a path portion  13  at the beginning of drill collar  12  and a path portion  15  at the end of drill collar  12  can be substantially straight having angles of at least 2 degrees from a center axis  99  of drill collar  12 . Accordingly, flow bore  14  can extend longitudinally throughout the length of the longitudinal drill collar  12  and have a longitudinal path that is any one of curved, curved and straight, or including a first path portion  13  and a second path portion  15  having an angle of at least 2 degrees from a center axis of the drill collar. 
     In use, drilling fluid flowing down the flow bore  14  curves as it goes around probe  50 . As noted, in some embodiments, the curve of flow bore  14  is substantially continuous without any substantial discontinuations such that the flow is not substantially effected by the changes in direction. The flow bore  14  at path portion  13  is directed towards the outer wall and then with a continuous radius or other continuous curvature it comes back up towards the middle to path portion  15 . 
     In some embodiments flow bore  14  has a radius of curvature of about 120 inches at its lowest point  17 . In some examples, the path of flow bore  14  can include about three or more curvatures. For example, it can go from an almost straight-line curve at its beginning path portion  13  to the middle curve of about a 120-inch radius to another almost straight-line continuous curve of path portion  15 . 
     In other embodiments, a flow bore  14  can be incorporated in other drill collars holding other downhole tools, such as other MWD tools and LWD tools. 
     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.