Patent Publication Number: US-11021952-B2

Title: Formation pressure testing

Description:
CROSS-REFERENCES TO RELATED APPLICATIONS 
     This application is a continuation application of U.S. patent application Ser. No. 15/837,242 that was filed on Dec. 11, 2017, and is entitled “Formation Pressure Testing,” which claimed priority to U.S. Provisional Patent Application No. 62/435,926, filed on Dec. 19, 2016, now U.S. Pat. No. 10,711,608. The entirety of the foregoing applications are incorporated herein by reference. 
    
    
     BACKGROUND OF THE DISCLOSURE 
     Wells are generally drilled into the ground or ocean bed to recover natural deposits of oil, gas, and other natural resources that are trapped in subsurface rock formations. Such wells are drilled using a drill bit attached to the lower end of a drill string. Drilling fluid is pumped from the wellsite surface down through the drill string to the drill bit. The drilling fluid lubricates and cools the bit, and may additionally carry drill cuttings from the wellbore back to the surface. 
     In various oil and gas exploration operations, it may be beneficial to have information about the subsurface formations that are penetrated by the wellbore. Accordingly, certain formation testing operations may be performed to measure and analyze formation fluid pressure and/or composition of the formation and the formation fluid. Such tests may include extracting a sample of the formation fluid from the formation, cutting a sample of the rock formation, and analyzing the samples. These tests may be useful for predicting the production capacity and production lifetime of the subsurface formation. 
     SUMMARY OF THE DISCLOSURE 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter. 
     The present disclosure introduces an apparatus including a fluid testing tool to be coupled along a downhole tool string to convey within a wellbore extending into a subterranean formation. The fluid testing tool includes a tool base and a pressure testing module. The tool base is to be coupled along the downhole tool string and includes a hydraulic pump and a probe assembly operable to engage a sidewall of the wellbore and receive formation fluid from the subterranean formation. The pressure testing module is detachably coupled with the tool base and includes a chamber and a piston assembly. The piston assembly is slidably disposed within the chamber, thus dividing the chamber into a first chamber portion and a second chamber portion. The hydraulic pump is fluidly connected to the first chamber portion and is operable to pump hydraulic fluid into the first chamber portion to move the piston assembly to draw the formation fluid into the second chamber portion. 
     The present disclosure also introduces a method including coupling a pressure testing module with a tool base to assemble a fluid testing tool. The pressure testing module is separable from the tool base. The method also includes coupling the tool base along a downhole tool string to couple the fluid testing tool along the downhole tool string, conveying the downhole tool string within a wellbore extending from a wellsite surface, and operating the fluid testing tool to draw formation fluid into the pressure testing module and record pressure of the formation fluid. 
     The present disclosure also introduces an apparatus including a pressure testing module and a tool base. The pressure testing module comprising includes a first chamber with a first piston assembly slidably disposed within the first chamber, thus dividing the first chamber into a first chamber portion and a second chamber portion. The pressure testing module also includes a second chamber with a second piston assembly slidably disposed within the second chamber, thus dividing the second chamber into a third chamber portion and a fourth chamber portion. The tool base is to be coupled along a downhole tool string to be conveyed within a wellbore extending into a subterranean formation. The pressure testing module is separable from and coupled to the tool base. The tool base includes a probe assembly operable to engage a sidewall of the wellbore and receive formation fluid from the subterranean formation. The tool base also includes a hydraulic pump operable to pump hydraulic fluid. The pressure testing module and the tool base are operable to selectively convey the hydraulic fluid pumped by the hydraulic pump (i) into the first chamber portion to move the first piston assembly to draw the formation fluid into the second chamber portion and (ii) into the third chamber portion to move the first piston assembly to draw the formation fluid into the fourth chamber portion. 
     The present disclosure also introduces a pressure testing module separable from and configured to be coupled with a tool base that is to be coupled along a downhole tool string to be conveyed within a wellbore extending into a subterranean formation. The pressure testing module includes a chamber and a piston assembly slidably disposed within the chamber, thus dividing the chamber into a first chamber portion and a second chamber portion. The piston assembly is operable to move in response to hydraulic fluid being pumped into the first chamber portion and to draw formation fluid of the wellbore into the second chamber portion in response to the movement of the piston assembly. 
     These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. 
         FIG. 1  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 2  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 3  is a sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 4  is a perspective view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 5  is an exploded sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 6  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 7  is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure. 
         FIG. 8  is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. 
       FIG. 1  is a schematic view of at least a portion of an example implementation of a wellsite system  100  to which one or more aspects of the present disclosure may be applicable. The wellsite system  100 , which may be situated onshore or offshore, comprises a downhole tool string  110  operable for engaging a portion of a sidewall  104  of a wellbore  102  penetrating a subterranean formation  106 . The downhole tool string  110  may be suspended in the wellbore  102  from a lower end of a conveyance means  124 , such as a wireline, a slickline, an e-line, coiled tubing, production tubing, and/or other conveyance means, operably coupled with a tensioning device  126  disposed at a wellsite surface  108 . The tensioning device  126  may be, comprise, or form at least a portion of a crane, a winch, a drawworks, a top drive, and/or another conveyance device coupled to the downhole tool string  110  by the conveyance means  124 . 
     A multi-conductor cable, hereinafter referred to as a conductor  125 , may extend through the conveyance means  124  and at least partially within the downhole tool string  110  and surface equipment  120 . The conductor  125  may facilitate electrical and/or optical communication between one or more components of the surface equipment  120 , including an uphole processing system  122  (e.g., a controller) and one or more portions of the downhole tool string  110 , including a downhole processing system  132  (e.g., a controller). The conductor  125  may permit electrical power transfer and/or signal communication between the surface equipment  120  and the downhole tool string  110 . The uphole processing system  122  may comprise an interface for receiving commands from a human operator and may be operable to store programs or instructions, including for implementing one or more aspects of the methods described herein. 
     The downhole tool string  110  may be or comprise one or more downhole tools, subs, modules, and/or other apparatuses operable in wireline, coiled tubing, completion, production, and/or other operations. For example, the downhole tool string  110  may comprise a cable head  112 , a telemetry tool  130 , a power supply tool  140 , a formation fluid testing tool  160 , and a sample containment tool  170 . The downhole tool string  110  may also comprise one or more additional components or subs, such as additional tool  150 , at various locations along the downhole tool string  110 , each of which may perform various functions while performing downhole operations within the scope of the present disclosure. For example, the downhole tool string  110  may further comprise one or more of an additional sample containment tool, an acoustic tool, a density tool, an electromagnetic (EM) tool, a formation evaluation tool, a gravity tool, a formation logging tool, a magnetic resonance tool, a monitoring tool, a neutron tool, a nuclear tool, a photoelectric factor tool, a porosity tool, a reservoir characterization tool, a resistivity tool, a seismic tool, a fluid sampling tool, a coring tool, a surveying tool, a release tool, an anchor tool, a mechanical interface tool, a perforating tool, a cutting tool, a rotary actuator, a stroker tool, a downhole tractor, a jarring tool, an impact or impulse tool, a fishing tool, a valve key or engagement tool, and a plug setting tool, among other examples. 
     Each of the telemetry tool  130 , the power supply tool  140 , the additional tools  150 , the formation fluid testing tool  160 , and the sample containment tool  170  may convey or comprise a portion of the conductor  125  extending through the downhole tool string  110 . The conductor  125  may include various electrical and/or optical connectors or interfaces (not shown), such as may facilitate connection between the conductor  125  and one or more of the tools  130 ,  140 ,  150 ,  160 ,  170  to permit communication between one or more of the tools  130 ,  140 ,  150 ,  160 ,  170  and one or more component of the surface equipment  120 , including the uphole processing system  122 . For example, the conductor  125  may be operable to transfer electrical power, data, and/or control signals between the surface equipment  120  and one or more of the tools  130 ,  140 ,  150 ,  160 ,  170 . 
     The cable head  112  may be operable to connect the conveyance means  124  with the downhole tool string  110 . The telemetry tool  130  may facilitate positioning of the downhole tool string  110  along the wellbore  102  and communication with the surface equipment  120 . The telemetry tool  130  may comprise the downhole processing system  132  communicatively coupled with the surface equipment  114 , including the uphole processing system  122 , via the conductor  125 . The downhole processing system  132  may comprise a circuit board and/or various electronic components for controlling operational aspects of the downhole tool string  110 , and may have an interface for receiving commands from the human operator. The downhole processing system  132  may also store programs or instructions, including for implementing one or more aspects of the methods described herein. The uphole processing system  122  and/or the downhole processing system  132  may operate independently or cooperatively to control one or more portions of the tools  130 ,  140 ,  150 ,  160 ,  170 . The uphole processing system  122  and/or the downhole processing system  132  may also analyze and/or process data obtained from various sensors disposed within or making up the tools  130 ,  140 ,  150 ,  160 ,  170 , store measurements and/or processed data, and/or communicate the measurements and/or processed data to the surface equipment  120  for subsequent analysis. 
     The power supply tool  140  may be or comprise an electrical power source or a hydraulic power source. The electrical power source may comprise a battery (not shown), while the hydraulic power source may comprise a hydraulic fluid containment chamber and a hydraulic fluid pump (not shown), such as may be operable to selectively actuate or power portions of the downhole tool string  110 , including the formation fluid testing tool  160 . 
     The formation fluid testing tool  160  may be operable to extract, receive, or otherwise collect a formation fluid sample and/or test one or more properties of the formation fluid, including temperature, pressure, density, viscosity, porosity, and composition, among other examples. The formation fluid testing tool  160  may comprise a probe assembly  161  and an anchoring member  162  that are each selectively extendable and are respectively arranged on opposing sides. The probe assembly  161  and the anchoring member  162  may be operatively connected with and powered by the power supply tool  140 . During downhole conveyance or prior to the fluid testing operations, the probe assembly  161  and the anchoring member  162  may be in a retracted state (not shown). When the downhole tool string  110  is conveyed to an intended test position along the wellbore  102 , the probe assembly  161  and the anchoring member  162  may extend to engage the sidewall  104 , as shown in  FIG. 1 . 
     The probe assembly  161  may be operable to engage the sidewall  104  of the wellbore  102  to selectively seal off or isolate a portion of the sidewall  104 . For example, the probe assembly  161  may comprise a sealing pad  163  that may be urged against the sidewall  104  in a sealing manner to prevent movement of formation fluid into or out of the subterranean formation  106  other than through the probe assembly  161 . The probe assembly  161  may comprise one or more sensors (not shown) adjacent the sealing pad  163 , among other possible locations. The sensors may be utilized in the determination of petrophysical parameters of a portion of the subterranean formation  106  proximate the probe assembly  161 . For example, the sensors may be utilized to measure or detect one or more of temperature, composition, electric resistivity, dielectric constant, magnetic resonance relaxation time, nuclear radiation, and/or combinations thereof, although other types of sensors are also within the scope of the present disclosure. 
     The formation fluid extracted via the probe assembly  161  may be directed into and through the formation fluid testing tool  160  via a flow line  164 , which may be fluidly connected with other tools located above and/or below the formation fluid testing tool  160 . A drawdown chamber  166  containing a piston may be fluidly connected with the flow line  164  and operable to draw therein the formation fluid from the subterranean formation  106  during pressure testing or pretest operations. A pressure sensor  168  may be fluidly connected with the flow line  164 . The pressure sensor  168  may be operable to generate a signal indicative of the pressure along the flow line  164  and/or within the drawdown chamber  166 , such as may be utilized to monitor or record the pressure along the flow line  164  and/or within the drawdown chamber  166  during the pressure testing operations. The drawdown chamber  166  may be disposed within or form at least a portion of a pressure testing module  167 , such as may be selectively installed within or removed from the remaining portion or tool base of the formation fluid testing tool  160 . 
     The formation fluid testing tool  160  may further comprise a pump  165  fluidly connected with or along the flow line  164 . The pump  165  may be operable to selectively extract the formation fluid from the subterranean formation  106  and transfer the formation fluid to the sample containment tool  170 , the additional tool  150 , and/or other tools located above or below the formation fluid testing tool  160 . Prior to performing the pressure testing operations, the formation fluid sampling operations, or other formation fluid testing operations, the pump  165  may also expel the formation fluid into the wellbore  102  via a port  159  during a “clean-up” operation until the formation fluid extracted from the subterranean formation  106  reaches a sufficiently low contamination level, at which time the formation fluid testing operations may be performed. The formation fluid testing tool  160  may also comprise a fluid sensing unit  169  through which the obtained formation fluid may be transmitted, such as to measure properties and/or composition of the sampled fluid. For example, the fluid sensing unit  169  may comprise one or more of a spectrometer, a fluorescence sensor, an optical fluid analyzer, a density and/or viscosity sensor, a pressure sensor, and/or a temperature sensor, among other examples. 
     The sample containment tool  170  may contain one or more detachable sample containers  172  (e.g., bottles) disposed or installed within the sample containment tool  170 . The detachable sample containers  172  may receive and store the captured formation fluid for subsequent testing at the wellsite surface  108 . The detachable sample containers  172  may be certified for highway and/or other transportation. The detachable sample containers  172  may be fluidly connected with the flow line  164 , which may extend at least partially through the sample containment tool  170  to permit the pump  165  to transfer the formation fluid from the subterranean formation  106  into the detachable sample containers  172 . 
       FIG. 2  is a schematic view of at least a portion of an example implementation of a formation fluid testing tool  200 , which may correspond to the formation fluid testing tool  160  shown in  FIG. 1 , according to one or more aspects of the present disclosure. The formation fluid testing tool  200  may comprise one or more similar features of the formation fluid testing tool  160 , as described below. 
     Similar to as described above, the formation fluid testing tool  200  may be or comprise a tool operable to extract, receive, or otherwise collect a formation fluid sample and/or test one or more properties of the formation fluid, including temperature, pressure, density, viscosity, porosity, and composition, among other examples. The formation fluid testing tool  200  may comprise a pressure testing module  202 , such as may be operable to or utilized for detecting pressure of the formation fluid within the subterranean formation  106 . The pressure testing module  202  may be selectively installed within and removed from a tool base  204  of the formation fluid testing tool  200 , e.g., while the formation fluid testing tool  200  is deployed in the field at the wellsite, thereby permitting selection and installation of pressure testing modules  202  having different structures and/or modes of operation to change the mode of operation of the formation fluid testing tool  200  while utilizing the same tool base  204 . As described below, the pressure testing module  202  may be selected based on intended operation of the formation fluid testing tool  200  and/or downhole conditions within the wellbore  102 . 
     The tool base  204  may comprise a probe assembly  210  and an anchoring member  212  that are each selectively extendable and are respectively arranged on opposing sides of the tool base  204 . The probe assembly  210  and the anchoring member  212  may be operatively connected with and powered by the power supply tool  140 . During downhole conveyance or prior to the fluid testing operations, the probe assembly  210  and the anchoring member  212  may be in a retracted state (not shown). When the downhole tool string  110  is located at an intended test position along the wellbore  102 , the probe assembly  210  and the anchoring member  212  may extend to engage the sidewall  104 . 
     The probe assembly  210  may be operable to engage the sidewall  104  of the wellbore  102  to selectively seal off or isolate a portion of the sidewall  104 . For example, the probe assembly  210  may comprise a sealing pad  214  that may be urged against the sidewall  104  in a sealing manner to prevent movement of formation fluid into or out of the subterranean formation  106  other than through the probe assembly  210 . The probe assembly  210  may comprise one or more sensors  216  adjacent the sealing pad  214 , among other possible locations. The sensors  216  may be utilized in the determination of petrophysical parameters of a portion of the subterranean formation  106  proximate the probe assembly  210 . For example, the sensors  216  may be utilized to measure or detect one or more of temperature, composition, electric resistivity, dielectric constant, magnetic resonance relaxation time, nuclear radiation, and/or combinations thereof, although other types of sensors are also within the scope of the present disclosure. 
     The tool base  204  may further comprise various fluid conduits and valves utilized to selectively control flow of the formation fluid. For example, the probe assembly  210  may be fluidly connected with a flow line  220  via a fluid conduit  222 , such as may permit transfer of the formation fluid along the fluid conduit  222  and into the flow line  220 . The flow line  220  may extend through the formation fluid testing tool  200  and fluidly connect with the tools  150 ,  170  located above and/or below the formation fluid testing tool  200 , such as may permit transfer of the formation fluid into and/or between the tools  150 ,  170 . One or more fluid valves  224 ,  225 ,  226  may be fluidly connected along the flow line  220  and the fluid conduit  222  to selectively control the flow of formation fluid into the pressure testing module  202  and/or toward the tools  150 ,  170 . The fluid valves  224 ,  225 ,  226  may be or comprise ball valves, globe valves, butterfly valves, and/or other types of fluid valves, such as may be selectively opened and closed to permit and prevent fluid flow. Each fluid valve  224 ,  225 ,  226  may be actuated remotely by a corresponding actuator (not shown), such as a solenoid, motor, or other electric actuator, or a fluid actuator, such as a hydraulic cylinder or rotary actuator. 
     The tool base  204  may further comprise a pump  228  fluidly connected with or along the flow line  220 . The pump  228  may be operable to selectively extract the formation fluid from the subterranean formation  106  and transfer the formation fluid toward the tools  150 ,  170 . Prior to the testing operations, the pump  228  may expel the formation fluid into the wellbore  102  through a port  229  during the clean-up operation until the formation fluid extracted from the subterranean formation  106  reaches a sufficiently low contamination level, at which time the formation fluid testing operations may be performed. The formation fluid testing tool  200  may also comprise a fluid sensing unit  230  through which the formation fluid may be transmitted, such as to measure properties and/or composition data of the sampled formation fluid. For example, the fluid sensing unit  230  may comprise one or more of a spectrometer, a fluorescence sensor, an optical fluid analyzer, a density and/or viscosity sensor, a pressure sensor, and/or a temperature sensor, among other examples. 
     The pressure testing module  202  may comprise a drawdown chamber  232  fluidly connected with the fluid conduit  222  via a fluid conduit  234 . The drawdown chamber  232  may contain therein a piston assembly  236  (“drawdown piston”) slidably disposed within the drawdown chamber  232  and dividing the drawdown chamber  232  into chamber portions  238 ,  240 ,  242 . For example, the piston assembly  236  may comprise a smaller first piston  244  fluidly dividing the drawdown chamber  232  into the first chamber portion  238  and second chamber portion  240  and a larger second piston  246  fluidly isolating the second chamber portion  240  from the third chamber portion  242 . The piston assembly  236  may be movable along the drawdown chamber  232  to draw the formation fluid into the first chamber portion  238  (“pretest chamber”) via the probe assembly  210  and the fluid conduits  222 ,  234  during the pressure testing operations. 
     One or more fluid sensing units  248 ,  250  may be connected along the fluid conduit  234 , such as may permit monitoring of one or more properties of the formation fluid being transferred into or located within the first chamber portion  238 . The fluid sensing unit  248  may be located within the tool base  204 , and the fluid sensing unit  250  may be located within the pressure testing module  202 . The fluid sensing units  248 ,  250  may be operable to generate signals indicative of various fluid properties of the formation fluid within the fluid conduit  234  and the first chamber portion  238 . Among other fluid properties, the fluid sensing units  248 ,  250  may be operable to determine and/or record pressure of the formation fluid. The fluid sensing units  248 ,  250  may comprise substantially the same or similar structure and/or mode of operation as the fluid sensing unit  230  described above. 
     The tool base  204  may further comprise a hydraulic pump  252  fluidly connected with a tank  256  containing therein a volume of hydraulic fluid  258 . The tank  256  may supply the hydraulic fluid  258  to the hydraulic pump  252  and receive returning or used hydraulic fluid. The hydraulic fluid  258  may be pressure compensated with respect to wellbore pressure. For example, the tank  256  may be fluidly connected with the wellbore  102  via a port  257  and contain therein a piston  260  operable to equalize the hydraulic fluid pressure with the wellbore pressure while fluidly isolating the hydraulic fluid  258  from the wellbore fluid  259 . The hydraulic pump  252  may be fluidly connected with one or both of the chamber portions  240 ,  242  via one or more fluid conduits  261 ,  262 . A fluid valve  264  may be fluidly connected between the hydraulic pump  252  and the chamber portions  240 ,  242 , such as may be operable to selectively direct pressurized hydraulic fluid  258  discharged by the hydraulic pump  252  into one of the chamber portions  240 ,  242  to move the piston assembly  236  along or within the drawdown chamber  232 . For example, the valve  264  may be a fluid directional control valve operable to direct the hydraulic fluid  258  into the chamber portion  240  and out of the chamber portion  242  to retract the piston assembly  236  as indicated by arrow  266 , or the valve  264  may be operable to direct the hydraulic fluid into the chamber portion  242  and out of the chamber portion  240  to extend the piston assembly  236  as indicated by arrow  268 . The valve  264  may be actuated remotely by a corresponding actuator (not shown), such as a solenoid, motor, or other electric actuator, or a fluid actuator, such as a hydraulic cylinder or rotary actuator. 
     As described above, the formation fluid testing tool  200  may be utilized to perform formation pressure testing operations to determine and/or monitor the pressure of the formation fluid within the subterranean formation  106 . For example, once a fluid seal is achieved between the probe assembly  210  and the sidewall  104  and, perhaps, after the clean-up operation is performed, the piston assembly  236  may be retracted within the drawdown chamber  232  as indicated by the arrow  266  to form or increase the volume of the first chamber portion  238  to create a pressure drop within the first chamber portion  238  and the fluid conduits  222 ,  234  below the formation pressure to draw the formation fluid into the first chamber portion  238 . When the piston assembly  236  stops retracting, the formation fluid may continue to enter the first chamber portion  238  via the probe assembly  210  and the fluid conduits  222 ,  234  until the pressure of the formation fluid in the first chamber portion  238  is substantially equal to the pressure of the formation fluid within the subterranean formation  106 . The pressure recorded by a pressure sensor of one or both of the fluid sensing units  248 ,  250  when the formation fluid stops flowing into the first chamber portion  238  may be the formation fluid pressure and/or may be indicative of the formation fluid pressure. To discharge the formation fluid out of the first chamber portion  238 , the piston assembly  236  may be extended within the drawdown chamber  232  as indicated by the arrow  268 . Such pressure testing operations may be repeated. During the pressure testing operations, the fluid valves  224 ,  225  may be in a closed-flow position preventing fluid flow along the flow line  220  and the fluid valve  226  may be in an open-flow position permitting fluid flow between the probe assembly  210  and the first chamber portion  238 . Prior to or after the pressure testing operations, one or both of the fluid valves  224 ,  225  may be operated to the open-flow position to permit flow of the formation fluid toward the tools  150 ,  170 . 
     The pressure testing module  202  and the tool base  204  may further comprise fluid couplings or connectors along the fluid conduits  234 ,  261 ,  262 , such as may facilitate fluid connection between the pressure testing module  202  and the tool base  204 . For example, the tool base  204  may comprise fluid connectors  270  (e.g., female connectors or receptacles) operable to receive and fluidly connect with corresponding fluid connectors  272  (e.g., male connectors or stabbers) of the pressure testing module  202 , or in other examples, the pressure testing module  202  may comprise fluid connectors  270  operable to receive and fluidly connect with corresponding fluid connectors  272  of the tool base  204 . The fluid connectors  270 ,  272  may permit installation and removal of the pressure testing module  202  into and from the tool base  204 , such as may permit the transfer of the formation fluid and the hydraulic fluid as described above. The fluid connectors  270 ,  272  may permit “plug-and-play” fluid connection by simply mating the fluid connectors  270 ,  272  without utilizing specialized tools and, thus, permitting field removal and installation of the pressure testing module  202  without having to disconnect the tool base  204  of the formation fluid testing tool  200  from the tools  150 ,  170  adjacent to the formation fluid testing tool  200 . 
     The pressure testing module  202  may further comprise one or more position sensors  274  (e.g., linear sensors) operable to generate a signal or information indicative of the axial position and/or velocity of the piston assembly  236  within the drawdown chamber  232 , such as to monitor the position and/or velocity of the piston assembly  236  within or with respect to the drawdown chamber  232 . The position sensor  274  may be disposed in association with the piston assembly  236  in a manner permitting sensing of the position and/or velocity of the piston assembly  236 . The position and/or velocity signals generated by the position sensor  274  may be utilized to determine flow of the formation fluid into the first chamber portion  238  and/or volume (“pretest volume”) of the formation fluid within the first chamber portion  238 . For example, a portion of the position sensor  274  may extend axially into or partially through the piston assembly  236  to monitor relative position and/or velocity of a magnet or another marker  276  carried with the piston assembly  236 . However, the pressure testing module  202  may comprise other linear position sensors operable to monitor the position and/or velocity of the piston assembly  236 . For example, the position sensor  274  may be or comprise an echo sensor, a roller screw with a resolver or rotary encoder, a linear encoder, a linear potentiometer, a capacitive sensor, an inductive sensor, a magnetic sensor, a linear variable-differential transformer (LVDT), a proximity sensor, a Hall effect sensor, and/or a reed switch, among other examples. 
     A multi-conductor cable, hereinafter referred to as a conductor  206 , may extend through the tool base  204  to communicatively connect the formation fluid testing tool  200  with the tools  150 ,  170  adjacent to the formation fluid testing tool  200 . The conductor  206  may be or form a portion of the conductor  125  extending through the downhole tool string  110 . The conductor  206  may include various electrical and/or optical connectors or interfaces (not shown), which may facilitate connection between the conductor  206  and the various components of the formation fluid testing tool  200  to permit communication between the various components of the formation fluid testing tool  200  and one or more component of the surface equipment  120 , including the uphole processing system  122 , and one or more components of the downhole tool string  110 , including the downhole processing system  132 . For example, the valves  224 ,  225 ,  226 , the pumps  228 ,  252 , the fluid sensing units  230 ,  248 ,  250 , and the position sensor  274  may be communicatively connected with the conductor  206  via corresponding conductors (shown in  FIG. 2  as dashed lines), such as may permit transfer electrical power, data, and/or control signals between, e.g., the surface equipment  120  and one or more of the valves  224 ,  225 ,  226 , the pumps  228 ,  252 , the fluid sensing units  230 ,  248 ,  250 , and the position sensor  274 . 
     The pressure testing module  202  and the tool base  204  may further comprise electrical couplings or connectors along an electrical conductor  278  extending between the fluid sensing unit  250 , the position sensor  274 , and the conductor  206 . For example, the tool base  204  may comprise an electrical connector  280  (e.g., multi-pin female connector or receptacle) operable to receive and electrically connect with a corresponding electrical connector  282  (e.g., multi-pin male connector or plug) of the pressure testing module  202 , or in some examples, the pressure testing module may comprise an electrical connector  280  operable to receive and electrically connect with a corresponding electrical connector  282  of the tool base  204 . The electrical connectors  280 ,  282  may permit installation and removal of the pressure testing module  202  into and from the tool base  204 , such as may permit signal communication described above. Similar to as described above, the electrical connectors  280 ,  282  may permit “plug-and-play” electrical connection by simply mating the electrical connectors  280 ,  282  without utilizing specialized tools and, thus, permitting field installation and removal of the pressure testing module  202 . 
       FIGS. 3 and 4  are sectional and perspective views, respectively, of at least a portion of an example implementation of a pressure testing module  300 , which may correspond to the pressure testing module  202  shown in  FIG. 2 , according to one or more aspects of the present disclosure. The pressure testing module  300  may comprise one or more similar features of the pressure testing module  202 , including where indicated by like reference numbers as described below. 
     The pressure testing module  300  may comprise a module body  302  having a drawdown chamber  232  containing a piston assembly  236  and a plurality of fluid pathways  304 ,  308 ,  312  adapted to transfer the formation and hydraulic fluids between various portions of the drawdown chamber  232  and the tool base  204 , as described above. The pressure testing module  300  may comprise the fluid pathway  304  extending between a first chamber portion  238  and a fluid connector  306 . The pressure testing module  300  may further comprise the fluid pathway  308  extending between a second chamber portion  240  and a fluid connector  310 , and the fluid pathway  312  extending between a third chamber portion  242  and a fluid connector  314 . 
     The pressure testing module  300  may also comprise a plurality of bores or pathways  316 ,  322  operable to accommodate therethrough electrical conductors  318 ,  324 . For example, the pressure testing module  300  may comprise the pathway  316  operable to accommodate therethrough the electrical conductor  318  extending between a fluid sensing unit  250  and an electrical connector  320 , and the pathway  322  operable to accommodate therethrough an electrical conductor  324  extending between a position sensor  274  and the electrical connector  320 . The fluid connectors  306 ,  310 ,  314  and electrical connector  320  may be grouped together or in close proximity to each other at a connection area  326 . 
     The pressure testing module  300  may further comprise a plurality of openings  334  (e.g., bolt holes) extending laterally through the module body  302  to a mounting surface  332  of the pressure testing module  300 . 
       FIG. 3  additionally illustrates a chamber portion diameter  239  of the first chamber portion  238  of the drawdown chamber  232 , a piston diameter  245  of the first piston  244 , and a piston diameter  243  of the second piston  246 . The chamber portion diameter  239 , the piston diameter  243 , and the piston diameter  245  are perpendicular to the directional movement of the piston assembly  236 . 
       FIG. 5  is an exploded sectional view of the pressure testing module  300  shown in  FIGS. 3 and 4  and a tool base  340 , which may correspond to the tool base  204  shown in  FIG. 2 , according to one or more aspects of the present disclosure. The tool base  340  may comprise one or more similar features of the tool base  204  as described below. 
     The fluid connectors  306 ,  310 ,  314  and electrical connector  320  may be grouped together or in close proximity to each other at a connection area  326  and may be operable to connect with corresponding fluid connectors  346 ,  348 ,  350  and electrical connector  352  of the tool base  340 . Although the fluid connectors  306 ,  310 ,  314  and electrical connector  320  are shown as male connectors operable to mate with corresponding fluid connectors  346 ,  348 ,  350  and electrical connector  352  of the tool base  340 , which are female connectors, the fluid connectors  306 ,  310 ,  314  and electrical connector  320  may be implemented as female connectors operable to mate with corresponding male connectors of the tool base  340 . 
     The tool base  340  may comprise a cavity  342  along or extending into a side  341  of the tool base  340 . The cavity  342  may be adapted to accommodate therein the pressure testing module  300 , such as may permit fluid and electrical connection between the tool base  340  and the pressure testing module  300 . When the pressure testing module  300  is fully inserted into the cavity  342 , a mounting surface  332  of the pressure testing module  300  contacts a corresponding mounting surface  344  of the tool base  340 . When the mounting surfaces  332 ,  344  are in contact, the fluid connectors  306 ,  310 ,  314  and electrical connector  320  of the pressure testing module  300  properly engage the corresponding fluid connectors  346 ,  348 ,  350  and electrical connector  352  of the tool base  340  to facilitate the fluid and electrical connections between the pressure testing module  300  and the tool base  340 . As previously described, the pressure testing module  300  may further comprise a plurality of openings  334  extending laterally through the module body  302  to the mounting surface  332  of the pressure testing module  300 . The tool base  340  may comprise a plurality of corresponding threaded openings  354  (e.g., bolt holes) extending laterally at least partially into the tool base  340  through the mounting surface  344 . A plurality of bolts  356  may be inserted through the openings  334  and threadedly engaged with the threaded openings  354  to fixedly maintain the pressure testing module  300  in connection with the tool base  340 . Other mechanisms for securing the pressure testing module  300  to the tool base  340  may be used instead of or in addition to the bolts  356  and openings  334 ,  354 . 
     As described above, the pressure testing module  202 ,  300  within the scope of the present disclosure may be selectively disconnected and removed from the tool base  204 ,  340  and replaced with another pressure testing module  202 ,  300  while maintaining the same tool base  204 ,  340 . The pressure testing module  202 ,  300  may be selected based on operational parameters of the formation fluid testing tool  200  and/or downhole conditions within the wellbore  102 . The downhole conditions may include, for example, a differential between the wellbore pressure and the formation pressure, which may control the ratio between the piston diameter  243  of the larger second piston  246  and the piston diameter  245  of the smaller first piston  244 . When the formation fluid testing tool  200  is utilized to test a subterranean formation  106  having a lower pressure differential, the pressure testing module  202 ,  300  may include a first piston  244  having an increased piston diameter  245  (e.g., resulting in a smaller differential between piston diameters  243 ,  245 ) slidably disposed within a first chamber portion  238  having a correspondingly increased chamber portion diameter  239 . However, when the formation fluid testing tool  200  is utilized to test a subterranean formation  106  having a higher pressure differential, the pressure testing module  202 ,  300  may include a first piston  244  having a decreased piston diameter  245  (e.g., resulting in a larger differential between piston diameters  243 ,  245 ) slidably disposed within a first chamber portion  238  having a decreased chamber portion diameter  239 . The increased piston diameter  245  and chamber portion diameter  239  may result in a larger pretest volume of the first chamber portion  238 , while the decreased piston diameter  245  and chamber portion diameter  239  may result in a smaller pretest volume of the first chamber portion  238 . The relationship between the piston diameter  243  of the larger second piston  246  and the piston diameter  245  of the smaller first piston  244  may be determined by estimated and/or known fluid pressures exerted on the piston assembly  236  as demonstrated by Equation (1). 
                       d   2       d   1       =       (     1   +         P   hydrostatic     -     P   formation         P   pump         )     0.5             (   1   )               
where d 2  is the piston diameter  243  of the second piston  246 , d 1  is the piston diameter  245  of the first piston  244 , P hydrostatic  is the hydrostatic wellbore pressure, P formation  is the formation fluid pressure, and P pump  is the hydraulic pressure generated by the hydraulic pump  252 . Table 1 set forth below lists examples of piston diameters  243 ,  245  for selected pretest volumes of the first chamber portion  238  and estimated or known maximum differential pressures between the wellbore pressure and the formation pressure.
 
     
       
         
           
               
               
               
               
             
               
                 TABLE 1 
               
               
                   
               
               
                 Maximum 
                   
                   
                   
               
               
                 Differential 
                 Diameter of 
                 Diameter of 
                 Total Pretest 
               
               
                 Pressure 
                 Piston d 1   
                 Piston d 2   
                 Volume 
               
               
                 (PSI) 
                 (Centimeters) 
                 (Centimeters) 
                 (Cubic Centimeters) 
               
               
                   
               
             
            
               
                 10,000 
                 3.48 
                 6.35 
                 85 
               
               
                 15,000 
                 3.00 
                 6.35 
                 63 
               
               
                 20,000 
                 2.67 
                 6.35 
                 50 
               
               
                   
               
            
           
         
       
     
     The information in Table 1 shows that as the downhole pressure differential increases and the piston diameter  243  (d 2 ) remains constant, the piston diameter  245  (d 1 ) is decreased to increase the ratio between the piston diameter  243  of the second piston  246  and the piston diameter  245  of the first piston  244  (d 2 /d 1 ). The information in Table 1 further shows that as the piston diameter  245  of the first piston  244  (d 1 ) decreases, the pretest volume of the first chamber portion  238  also decreases. 
     In some example implementations, a pressure testing module may also or instead include two or more drawdown chambers and corresponding piston assemblies, wherein each set may be utilized one at a time, such as under different downhole conditions.  FIG. 6  is a schematic view of at least a portion of an example implementation of a pressure testing module  400  according to one or more aspects of the present disclosure. The pressure testing module  400  may comprise one or more similar features of the pressure testing modules  202 ,  300 , including where indicated by like reference numbers. 
     The pressure testing module  400  may comprise a first drawdown chamber  402  containing therein a piston assembly  404  slidably disposed within the first drawdown chamber  402  and dividing the first drawdown chamber  402  into chamber portions  406 ,  408 ,  410 . The piston assembly  404  may comprise a first piston  412  fluidly dividing the first drawdown chamber  402  into the first chamber portion  406  and second chamber portion  408  and a second piston  414  fluidly isolating the second chamber portion  408  from the third chamber portion  410 . The pressure testing module  400  may further comprise a second drawdown chamber  422  containing therein a piston assembly  424  slidably disposed within the second drawdown chamber  422  and dividing the second drawdown chamber  422  into chamber portions  426 ,  428 ,  430 . The piston assembly  424  may comprise a first piston  432  fluidly dividing the second drawdown chamber  422  into the first chamber portion  426  and the second chamber portion  428  and a second piston  434  fluidly isolating the second chamber portion  428  from the third chamber portion  430 . 
     The first pistons  412 ,  432  and corresponding first chamber portions  406 ,  426  may have different diameters, while the second pistons  414 ,  434  and corresponding third chamber portions  410 ,  430  may have the same diameter. For example, the first piston  412  of the first drawdown chamber  402  and corresponding first chamber portion  406  may have a diameter  407  that is larger than the diameter  427  of the first piston  432  of the second drawdown chamber  422  and corresponding first chamber portion  426 . Accordingly, the maximum pretest volume of the first chamber portion  406  of the first drawdown chamber  402  may be larger than the maximum pretest volume of the first chamber portion  426  of the second drawdown chamber  422 . 
     Each of the first chamber portions  406 ,  426  may be fluidly connected with a fluid connector  306 , such as may permit fluid connection with the corresponding fluid connector  346  of the tool base  340 . A fluid valve  440  may be fluidly connected between the fluid connector  306  and the first chamber portions  406 ,  426  and may be operable to selectively permit fluid communication between the fluid connector  306  and one of the first chamber portions  406 ,  426 . Furthermore, each of the second chamber portions  408 ,  428  may be fluidly connected with a fluid connector  310 , such as may permit fluid connection with the corresponding fluid connector  348  of the tool base  340 . A fluid valve  442  may be fluidly connected between the fluid connector  310  and the second chamber portions  408 ,  428  and may be operable to selectively permit fluid communication between the fluid connector  310  and one of the second chamber portions  408 ,  428 . Each of the third chamber portion  410 ,  430  may also be fluidly connected with a fluid connector  314 , such as may permit fluid connection with the corresponding fluid connector  350  of the tool base  340 . A fluid valve  444  may be fluidly connected between the fluid connector  314  and the third chamber portions  410 ,  430  and may be operable to selectively permit fluid communication between the fluid connector  314  and one of the third chamber portions  410 ,  430 . The fluid valves  440 ,  442 ,  444  may be or comprise fluid directional control valves and may be actuated remotely by corresponding actuators (not shown), such as solenoids, motors, or other electric actuators, or fluid actuators, such as hydraulic cylinders or rotary actuators. 
     Each of the piston assemblies  404 ,  424  may have a corresponding position sensor  274  operable to generate a signal or information indicative of the axial position and/or velocity of the corresponding piston assembly  404 ,  424 . The position sensors  274 , the fluid valves  440 ,  442 ,  444 , and the fluid sensing unit  250  may be electrically connected with an electrical connector  320 , such as may facilitate electrical connection with the corresponding electrical connector  352  of the tool base  340 . 
     Similar to as described above, the pressure testing module  400  may be utilized to perform pressure testing operations to determine and/or monitor the pressure of the formation fluid within the subterranean formation  106 . For example, once a fluid seal is achieved between the probe assembly  210  and the sidewall  104  and, perhaps, after the clean-up operation is performed, the selected one of the piston assemblies  404 ,  424  (e.g., by operation of the fluid valves  440 ,  442 ,  444 ) may be retracted within the corresponding drawdown chamber  402 ,  422  to form or increase the volume of the corresponding first chamber portion  406 ,  426  to create a pressure drop in the first chamber portion  406 ,  426  and the fluid conduit  222 ,  234  below the formation pressure to draw the formation fluid into the first chamber portion  406 ,  426  and monitor the formation fluid pressure via the fluid sensing unit  248  and/or the fluid sensing unit  250 . The piston assembly  404 ,  424  and drawdown chamber  402 ,  422  set utilized to perform the pressure testing operations may be selected based on the intended pretest volume of formation fluid and/or the downhole properties of the wellbore  102 , such as the differential between the wellbore pressure and the formation pressure. For example, if a larger pretest volume is to be used, then the first drawdown chamber  402  with the larger piston assembly  404  may be utilized. If the differential between wellbore pressure and formation pressure is relatively large, then the second drawdown chamber  422  with the smaller piston assembly  424  may be utilized. However, if the differential between wellbore pressure and formation pressure is relatively small, then the first drawdown chamber  402  with the larger piston assembly  404  may be utilized. 
     Although the pressure testing module  400  has been described as being removable from a tool base, such as the tool base  204 ,  340 , components of the pressure testing module  400  may be integral to a tool that is capable of being included in a downhole tool string, such as the downhole tool string  110  in other example implementations, according to one or more aspects of the present disclosure. 
     Various portions of the apparatuses described above and shown in  FIGS. 1-6  may collectively form and/or be controlled by a control system, such as may be operable to monitor and/or control at least some operations of the wellsite system  100 , including operations of the downhole tool string  110  and the formation fluid testing tool  160 ,  200 .  FIG. 7  is a schematic view of at least a portion of an example implementation of such a control system  500  according to one or more aspects of the present disclosure. The following description refers to one or more of  FIGS. 1-7 . 
     The control system  500  may comprise a controller  510 , which may be in communication with various portions of the wellsite system  100 , including the tensioning device  126  and the various tools of the downhole tool string  110  described within the scope of the present disclosure. For example, the controller  510  may be in signal communication with the tensioning device  126 , the probe assembly  210 , the anchoring member  212 , the fluid valves  224 ,  225 ,  226 ,  440 ,  442 ,  444 , the position sensors  274 , the pumps  228 ,  252 , and the fluid sensing units  230 ,  248 ,  250 , and/or other actuators and sensors of the wellsite system  100  and the downhole tool string  110 . For clarity, these and other components in communication with the controller  510  will be collectively referred to hereinafter as “sensor and operated equipment.” The controller  510  may be operable to receive coded instructions  532  from the human operator and signals generated by the position sensors  274  and the fluid sensing units  230 ,  248 ,  250 , process the coded instructions  532  and the signals, and communicate control signals to the fluid valves  224 ,  225 ,  226 ,  440 ,  442 ,  444 , the pumps  228 ,  252 , the tensioning device  126 , the probe assembly  210 , and/or the anchoring member  212  to execute the coded instructions  532  to implement at least a portion of one or more example methods and/or processes described herein, and/or to implement at least a portion of one or more of the example systems described herein. The controller  510  may be or comprise one or more of the uphole processing system  122  and/or the downhole processing system  132  described above. 
     The controller  510  may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers (e.g., desktop, laptop, and/or tablet computers) personal digital assistant (PDA) devices, smartphones, internet appliances, and/or other types of computing devices. The controller  510  may comprise a processor  512 , such as a general-purpose programmable processor. The processor  512  may comprise a local memory  514 , and may execute coded instructions  532  present in the local memory  514  and/or another memory device. The processor  512  may execute, among other things, the machine-readable coded instructions  532  and/or other instructions and/or programs to implement the example methods and/or processes described herein. The programs stored in the local memory  514  may include program instructions or computer program code that, when executed by an associated processor, facilitate the wellsite system  100  and the downhole tool string  110  to perform the example methods and/or processes described herein. The processor  512  may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples. Of course, other processors from other families are also appropriate. 
     The processor  512  may be in communication with a main memory  517 , such as may include a volatile memory  518  and a non-volatile memory  520 , perhaps via a bus  522  and/or other communication means. The volatile memory  518  may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices. The non-volatile memory  520  may be, comprise, or be implemented by a tangible, non-transitory storage medium, such as read-only memory, flash memory, and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory  518  and/or non-volatile memory  520 . 
     The controller  510  may also comprise an interface circuit  524 . The interface circuit  524  may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others. The interface circuit  524  may also comprise a graphics driver card. The interface circuit  524  may also comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network (e.g., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.). One or more of the sensor and operated equipment may be connected with the controller  510  via the interface circuit  524 , such as may facilitate communication between the sensor and operated equipment and the controller  510 . 
     One or more input devices  526  may also be connected to the interface circuit  524 . The input devices  526  may permit the human operators to enter the coded instructions  532 , including control commands, operational set-points, and/or other data for use by the processor  512 . The operational set-points may include, as non-limiting examples, a stop position within the wellbore  102  to which the tensioning device  126  conveys the formation fluid testing tool  160 ,  200 , test positions distributed longitudinally along the wellbore  102  at which the formation fluid testing tool  160 ,  200  is to perform the pressure testing operations, and/or longitudinal distances between the test positions. The input devices  526  may be, comprise, or be implemented by a keyboard, a mouse, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples. 
     One or more output devices  528  may also be connected to the interface circuit  524 . The output devices  528  may be, comprise, or be implemented by display devices (e.g., a liquid crystal display (LCD), a light-emitting diode (LED) display, or cathode ray tube (CRT) display), printers, and/or speakers, among other examples. The controller  510  may also communicate with one or more mass storage devices  530  and/or a removable storage medium  534 , such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples. 
     The coded instructions  532  may be stored in the mass storage device  530 , the main memory  517 , the local memory  514 , and/or the removable storage medium  534 . Thus, the controller  510  may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor  512 . In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code (e.g., software or firmware) thereon for execution by the processor  512 . 
     The coded instructions  532  may include program instructions or computer program code that, when executed by the processor  512 , may cause the wellsite system  100 , including the downhole tool string  110  to perform methods, processes, and/or routines described herein. For example, the controller  510  may receive, process, and record the operational set-points entered by the human operator and the signals generated by the position sensors  274  and the fluid sensing units  230 ,  248 ,  250 . Based on the received operational set-points and the generated signals, the controller  510  may send control signals or information to the fluid valves  224 ,  225 ,  226 ,  440 ,  442 ,  444 , the pumps  228 ,  252 , the tensioning device  126 , the probe assembly  210 , and/or the anchoring member  212 , and/or other portions of the downhole tool string  110  and/or the tensioning device  126  to automatically perform and/or undergo one or more operations or routines described herein or otherwise within the scope of the present disclosure. 
       FIG. 8  is a flow-chart diagram of at least a portion of an example implementation of a method ( 600 ) according to one or more aspects of the present disclosure. The method ( 600 ) may be performed utilizing or otherwise in conjunction with at least a portion of one or more implementations of one or more instances of the apparatuses shown in one or more of  FIGS. 1-7  and/or otherwise within the scope of the present disclosure. The method ( 600 ) may be performed manually by the human operator and/or performed or caused, at least partially, by the controller  510  executing the coded instructions  532  according to one or more aspects of the present disclosure. Thus, the following description of the method ( 600 ) also refers to apparatuses shown in one or more of  FIGS. 1-7 . However, the method ( 600 ) may also be performed in conjunction with implementations of one or more apparatuses other than those depicted in  FIGS. 1-7  that are also within the scope of the present disclosure. 
     The method ( 600 ) includes coupling ( 605 ) a pressure testing module (e.g., pressure testing module  202 ,  300 ,  400 ) with a tool base (e.g., tool base  204 ,  340 ) to assemble a formation fluid testing tool (e.g., formation fluid testing tool  160 ,  200 ), coupling ( 610 ) the tool base along a downhole tool string (e.g., downhole tool string  110 ) to couple the formation fluid testing tool along the downhole tool string, conveying ( 615 ) the downhole tool string within a wellbore (e.g., wellbore  102 ) at a wellsite surface, and operating ( 620 ) the formation fluid testing tool to draw formation fluid into the pressure testing module and obtain a pressure of the formation fluid. 
     Prior to and/or after coupling ( 605 ) the pressure testing module with the tool base, the method ( 600 ) may also include selecting ( 625 ) the drawdown chamber and/or pressure testing module from a plurality of drawdown chambers and/or pressure testing modules based on downhole conditions within the wellbore. One of various pressure testing modules, such as with different configurations of drawdown chambers, can be selected to be coupled with the tool base in some examples. Instead of or in addition to the selection of a pressure testing module, a utilized pressure testing module can include multiple drawdown chambers having different configurations, such as illustrated in  FIG. 6 , and one of the multiple drawdown chambers in the utilized pressure testing module may be selected by operation of various valves controlled by a controller during or before the operating ( 620 ), for example. The downhole conditions may include a differential between the wellbore pressure and the formation pressure. Furthermore, each of the plurality of pressure testing modules may comprise a different configuration adapted to operate under a different downhole condition. 
     Selecting ( 625 ) the drawdown chamber and/or pressure testing module from the plurality of drawdown chambers and/or pressure testing modules based on the downhole conditions within the wellbore may include selecting ( 630 ) a first drawdown chamber and/or pressure testing module comprising a piston assembly with a first piston having a smaller or decreased diameter when a differential between the wellbore pressure and the formation pressure is larger, or selecting a second drawdown chamber and/or pressure testing module comprising a piston assembly with a first piston having a larger or increased diameter when the differential between the wellbore pressure and the formation pressure is smaller. 
     Selecting ( 625 ) the drawdown chamber and/or pressure testing module from the plurality of drawdown chambers and/or pressure testing modules based on the downhole conditions within the wellbore may also include selecting ( 635 ) a first drawdown chamber and/or pressure testing module comprising a larger or increased drawdown volume of the first chamber portion of the drawdown chamber when a differential between wellbore pressure and formation pressure is smaller, and selecting a second drawdown chamber and/or pressure testing module comprising a smaller or decreased drawdown volume of the first chamber portion of the drawdown chamber when the differential between the wellbore pressure and the formation pressure is larger. 
     Coupling ( 605 ) the pressure testing module with the tool base may be performed while the tool base is coupled along the downhole tool string. Coupling ( 605 ) the pressure testing module with the tool base may include inserting ( 640 ) the pressure testing module into a cavity (e.g., cavity  342 ) located along a side (e.g., side  341 ) of the tool base. Coupling ( 605 ) the pressure testing module with the tool base may further comprise connecting ( 645 ) fluid connectors (e.g., fluid connectors  272 ) of the pressure testing module with corresponding fluid connectors (e.g., fluid connectors  270 ) of the tool base. The fluid connectors of the pressure testing module and the tool base may comprise male stabbers and female receptacles. Coupling ( 605 ) the pressure testing module with the tool base may also comprise connecting ( 650 ) an electrical connector (e.g., electrical connector  282 ) of the pressure testing module with a corresponding electrical connector (e.g., electrical connector  280 ) of the tool base. The electrical connectors of the pressure testing module and the tool base may comprise a male stabber and a female receptacle. 
     The tool base may comprise a probe assembly (e.g., probe assembly  210 ) and a hydraulic pump (e.g., hydraulic pump  252 ). The pressure testing module may comprise a drawdown chamber (e.g., drawdown chamber  232 ) and a piston assembly (e.g., piston assembly  236 ) slidably disposed within the drawdown chamber. The piston assembly may comprise a first piston (e.g., first piston  244 ) dividing the drawdown chamber into a first chamber portion (e.g., first chamber portion  238 ) and a second chamber portion (e.g., second chamber portion  240 ) and may comprise a second piston (e.g., second piston  246 ) fluidly isolating the second chamber portion from a third chamber portion (e.g., third chamber portion  242 ). Hence, connecting ( 645 ) the fluid connectors of the pressure testing module with the fluid connectors of the tool base may further comprise fluidly connecting ( 660 ) the first chamber portion with the probe assembly and fluidly connecting ( 665 ) the second chamber portion and the third chamber portion with the hydraulic pump. 
     Operating ( 620 ) the formation fluid testing tool may include engaging ( 655 ) the probe assembly with a sidewall of the wellbore, pumping hydraulic fluid into the second chamber portion to move the piston assembly to draw the formation fluid from the sidewall into the first chamber portion, and recording the pressure of the formation fluid within the first chamber portion. 
     The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure. 
     The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.