Patent Publication Number: US-2022228485-A1

Title: Direct drive for a reservoir fluid pump

Description:
TECHNICAL FIELD 
     This application is directed, in general, to monitoring of hydrocarbon wellbores and, more specifically, to an improved system and method for collecting formation fluid samples. 
     BACKGROUND 
     Many current hydrocarbon reservoir sampling tools use induction motors for downhole sampling. Unless a variable frequency control system is employed (e.g., as with production pumps), controlling motor speed or direction of rotation is either difficult or inefficient. Current solutions use a hydraulic pump and hydraulic power to control downhole tool mechanical functions, (e.g., the sample pumping of reservoir fluids). All required regulation is done hydraulically, and the electric motors used require that they continuously dissipate near maximum power. The above arrangements accumulate the inefficiencies of different energy conversions, resulting in overheating and their cohort of reliability concerns. Also, the operation of hydraulic valves to control pumping operations introduces additional reliability issues. 
    
    
     
       BRIEF DESCRIPTION 
       Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which: 
         FIG. 1A  illustrates an example of a wellbore system that performs sampling for testing on subterranean formations; 
         FIG. 1B  illustrates another example of a wellbore system that performs sampling for testing on subterranean formations; 
         FIG. 2  illustrates a block diagram example of a downhole measurement environment constructed according to the principles of the present disclosure; 
         FIG. 3  illustrates an example of a formation fluid pump constructed according to principles of the present disclosure; 
         FIG. 4  illustrates an example of a mechanical piston actuator as may be employed in a formation fluid pump such as the formation pump depicted in  FIG. 3 ; and 
         FIG. 5  illustrates an example of a formation fluid pumping method carried out according to the principles of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     When performing subterranean operations, wellbore fluid sampling may be used to determine many important characteristics of the downhole environment. For example, when performing subterranean operations, it may be desirable to monitor or sample certain properties of fluids used in conjunction with production of subterranean operations, such as pressure, temperature, density, viscosity, and other quantities such as the contents of oil including water or gas. Sampling of formation fluids requires that the fluid sample remains as true as possible to its in-situ formation condition to accurately reflect formation fluid conditions. This requirement dictates several constraints on formation fluid sampling devices that are challenging to meet with current equipment. Solutions for better managing these constraints are presented in examples of this disclosure. 
     One such solution includes a formation fluid pump that employs a brushless direct current motor and a mechanical piston actuator to linearly move a piston inside a formation fluid container to extract a quantity of formation fluid. The disclosed formation fluid pump provides several advantages compared to conventional formation fluid sampling devices. For example, direct drive of the formation fluid pump provides better efficiency and control than with the existing hydraulic drive thereby eliminating the need for a hydraulic circuit for formation fluid pumping. A more efficient and improved operational control and a more reliable operation is provided by suppressing the hydraulic circuit and reducing operating temperatures. More power is available for pumping rather than being wasted in heat. A smaller overall footprint is available with a resulting reduction in downhole tool length, weight and complexity. A more precise pump piston motion control is obtained, and a reduced overall maintenance is also obtained since a drive motor and a gearbox can reside at atmospheric pressure rather than in pressure compensated hydraulic oil. Reduced cost can also be achieved since the hydraulic drive components are eliminated. 
     Now turning to the figures,  FIG. 1A  illustrates an example of a wireline wellbore system, generally designated  100 , that performs sampling for testing on subterranean formations. During drilling or after final drilling of a wellbore  101  from a surface location  102  is complete, it is usually desirable to know additional details about types of formation fluids and their associated characteristics through sample collection employing formation logging or fluid sampling. The wellbore system  100  includes a downhole tool, measurement tool  110  having a depth correlation unit that forms part of a logging operation that can be used for accurate depth control. The depth correlation unit in the downhole measurement tool  110  provides current depth data from the wellbore  101  through a conveyance  133  for recording of current depth data in a logging unit  140  (i.e., a surface logging facility). The depth correlation unit can be, for example, a gamma ray logging sensor unit or a casing collar locator. Furthermore, a load sensor attached to the conveyance  133  and the downhole measurement tool  110  may be present to further aid in determination of the depth profile along conveyance  133 . 
     The wellbore system  100  also includes a derrick  130  that supports a traveling block  131  and the downhole measurement tool  110  in the form of a sonde or probe that is lowered by the conveyance  133  into the wellbore  101 . The conveyance  133  may be a wireline, slickline, coiled tubing, drill pipe, or other cable or conveyance suitable for a logging operation. Generally, any conveyance that allows for the operation of a downhole logging tool and provides depth control can be employed. In one example, the downhole measurement tool  110  may be lowered to a region of interest in the wellbore  101  and pulled upward at a substantially constant speed to gain logging information for wellbore structures such as subterranean formations  125 ,  126  and  127 . Additionally, the downhole measurement tool  110  may be held stationary within the wellbore  101  to gather wellbore or fluid formation samples at one or more of the subterranean formations  125 ,  126  and  127 . 
     In the illustrated example of  FIG. 1A , the downhole measurement tool  110  also includes a direct drive formation fluid pump  120  that is generally configured to gather formation fluid samples and then convey these samples to the surface  102  by retrieval of the conveyance  133  to the logging unit  140  for storage, processing or analysis. The logging unit  140  is provided with necessary equipment  144  to accomplish this storage, processing or analysis. 
       FIG. 1B  illustrates an example of a wellbore system, generally designated  150 , that performs formation drilling. The wellbore system  150  can incorporate logging operations of a borehole  160  and surrounding subterranean formations while drilling. Wellbore system  150  is configured to drive a bottom hole assembly (BHA)  170  positioned or otherwise arranged at the bottom of a drill string  165  extended into the earth from derrick  152  arranged at the surface. Derrick  152  includes a kelly  153  and a traveling block  155  used to lower and raise the kelly  153  and drill string  165 . 
     BHA  170  includes a drill bit  172  operatively coupled to a tool string  173  which may be moved axially within the wellbore  160  as attached to the tool string  173 . During operation, drill bit  172  penetrates the earth and thereby creates wellbore  160 . BHA  170  provides directional control of drill bit  172  as it advances into the earth. 
     Fluid or “drilling mud” from a mud tank  180  may be pumped downhole using a mud pump  182  powered by an adjacent power source, such as a prime mover or motor  184 . The drilling mud may be pumped from mud tank  180 , through a stand pipe  186 , which feeds the drilling mud into drill string  165  and conveys the same to drill bit  172 . The drilling mud exits one or more nozzles arranged in drill bit  172  and in the process cools drill bit  172 . After exiting drill bit  172 , the mud circulates back to the surface via the annulus defined between the wellbore  160  and the drill string  165 , and in the process, returns drill cuttings and debris to the surface. The cuttings and mud mixture are passed through a flow line  188  and are processed such that a cleaned mud is returned down hole through the stand pipe  186  once again. 
     Tool string  173  can be semi-permanently mounted with various measurement tools (not shown) such as, but not limited to, measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools, that may be configured to take downhole measurements of drilling conditions. For example, the tool string  173  can include a downhole tool  174  that collects logging data as the drill bit  172  extends the borehole  160  through subterranean formations  195 ,  196 ,  197 . 
     Additionally, the wellbore system  150  can employ a direct drive formation fluid pump  176  to gather formation fluid samples during a drilling operation. In these cases, the direct drive formation fluid pump  176  can be included in the tool string  173  and powered by a downhole power source. Formation fluid sample capture may be orchestrated by electrical, hydraulic, acoustic or electromagnetic initiation signals, at periodic or preprogrammed time intervals or triggered by a downhole event. A status of formation fluid sample capturing may be included in current up-hole communications of logging or drilling parameters. The captured formation fluid samples can be retrieved during bit replacement tripping or during additional tripping operations based on drilling operations protocol. 
     For purposes of communication, a downhole telemetry transceiver  178  can be included in the BHA  170 , either separately or as part of the tool string  173  or the downhole tool  174 . Downhole telemetry transceiver  178  can transfer measurement data to a surface transceiver  156  and receive commands from the surface, such as for the direct drive formation fluid pump  176 . Mud pulse telemetry is one common telemetry technique for transferring tool measurements to surface receivers and receiving commands from the surface. Other telemetry techniques typically used in LWD or MWD systems can also be used. In some embodiments, downhole telemetry transceiver  178  can store logging data for later retrieval at the surface when the logging assembly is recovered. 
     At the surface, surface transceiver  156  can receive the uplink signal from the downhole telemetry transceiver  178  and can communicate the signal to well controller equipment  158 . Well controller equipment  158  can include one or more processors, storage mediums, input devices, output devices, software, and other computing components and systems. Well controller equipment  158  can collect, store, and/or process the data received from downhole tool  174  as described herein. For example, the well controller equipment  158  can process wellbore sampling data such as disclosed herein. 
     In one example, operating control signals for the direct drive formation fluid pump  176  may be provided up-hole and conveyed to the direct drive formation fluid pump  176  downhole via the telemetry transceiver  178 . Operating power may be provided by a downhole power generator or battery within the tool string  173 , and control signals may be preprogrammed to orchestrate sample gathering downhole based on elapsed time or wellbore depth information. 
       FIG. 2  illustrates a block diagram example of a downhole measurement environment, generally designated  200 , constructed according to the principles of the present disclosure. The downhole measurement environment  200  includes a wellbore  205  containing a wellbore fluid  212 , a subterranean formation  207  containing a formation fluid  210 , a downhole measurement tool  215 , a logging cable  216 , a fluid pump  220  employing direct drive pumping and a collection of formation fluid sample containers  235   1 - 235   N  contained in a formation sample tool  217 . The subterranean formation  207  provides the formation fluid  210  to be sampled and the logging cable  216  connects the downhole measurement tool  215  electrically to surface equipment (not shown). The subterranean formation  207  is generally isolated from the well by drilling mud located on the wellbore  205 . A wellbore pad  227  presses against the wellbore  205  to isolate the formation fluid  210  from the wellbore fluid  212  for a formation fluid input port  226 . The fluid pump  220  includes a pump unit  225  employing the formation fluid input port  226  and a formation fluid output port  228  connected to the fluid sample containers  235   1 - 235   N . 
     The formation fluid input port  226  supplies formation fluids to the pump unit  225 , which in turn pumps one or more samples of each formation fluid of interest through the formation fluid output port  228  into the formation fluid sample containers  235   1 - 235   N  for storage. In this example, analysis of each formation sample is performed after the downhole measurement tool  215  is returned to the surface. In another example, analysis of one or more formation samples may be performed while the downhole measurement tool  215  and the formation sample tool  217  is still downhole by employing the logging cable  216  for analysis control from the surface or by use of analysis preprogramming downhole. Then, downhole analysis results may be transmitted to the surface employing the logging cable  216 . 
     In addition to the pump unit  225 , the fluid pump  220  includes a gear box  230 , an electric motor  232  and an electric motor controller  234 . The gear box  230  employs a gear ratio that provides an output shaft speed required by the fluid pump  220  to pump more effectively or efficiently, while allowing an output torque of the electric motor  232  to be controlled or maximized by the electric motor controller  234 . The gear box  230  may typically provide a rotary speed reduction to the pump unit  225 . In the illustrated example of  FIG. 2 , the pump unit  225  is pressure compensated at wellbore pressures while the gear box  230 , the electric motor  232  and the electric motor controller  234  may reside at atmospheric pressure. 
       FIG. 3  illustrates an example of a fluid pump, generally designated  300 , constructed according to principles of the present disclosure. The fluid pump  300  is a variable speed, mechanical direct-drive pump employing a pressure-balanced push-pull piston. In the illustrated example of  FIG. 3 , the pump piston is surrounded by hydraulic oil, which is only employed to provide pressure compensation and some lubrication of sliding piston seals. There is minimal contamination of the hydraulic oil from fluid leaking through the sliding seals due to the innate pressure balancing thereby generally reducing or avoiding major filtering, contaminated valves or extensive maintenance. Since the piston is pressure balanced, the only force a drive motor needs to supply is to overcome seal friction and fluid drag forces in associated fluid conduits. Additionally, only the pump enclosure or container employs the hydraulic oil, and mechanical drive components (e.g., the motor and a gear box) operate outside of the hydraulic oil thereby simplifying downhole tool construction and maintenance. A resulting smaller pressurized volume may allow reducing the size of the compensating piston thereby allowing for reduced downhole tool dimensions. 
     The fluid pump  300  includes a fluid container  305 , a formation fluid input port  306 , a formation fluid output port  307 , a moveable piston  310  having two fluid chambers  312   a ,  312   b , first, second and third seals  315 ,  316 ,  317 , container of formation fluid  320 , container of hydraulic oil  322 , a pair of input check valves  325  and a pair of output check valves  327 . The fluid pump  300  also includes a mechanical piston actuator  330  having a rotary portion  330   a  and a linear portion  330   b , first and second actuator bearing seals  333   a ,  333   b  and an alternative magnetic coupling device  335 . The fluid pump  300  further includes a wellbore pressure compensator  326  coupled to a hydraulic oil bypass line  328 , first and second torsion relief springs  340   a ,  340   b , a gear box  342  having a gear box output shaft  345 , a brushless direct current (BLDC) electric motor  348  having a motor output shaft  350 , and a BLDC motor driver  355  connected to the BLDC electric motor  348  via motor power and control lines  357 . The BLDC motor driver  355  receives electrical power and control signals to operate the BLDC electric motor  348 . The control signals can be received from the surface via an up-hole control input. The electrical power can also be received from the surface or can be provided from a downhole power source. A conveyance can provide the electrical power and up-hole control input. The conveyance can be, for different examples, the conveyance  133  or the drill string  165  noted above. Here, wellbore pressure is close to or slightly larger than formation pressure to keep the formation fluids in place but not to contaminate the formation with wellbore fluid. 
     The fluid container  305  and the moveable piston  310  are cylinders in this example, and the first, second and third seals  315 ,  316 ,  317  provide sliding seals between the fluid container  305  cylinder and the moveable piston  310  cylinder. The two fluid chambers  312   a ,  312   b  have comparable fluid capacities formed by the fluid container  305  and the moveable piston  310  and typically contain different quantities of formation fluid  320  as the moveable piston  310  traverses the fluid container  305 . In the example of  FIG. 3 , the fluid chamber  312   a  is at maximum fluid capacity and the fluid chamber  312   b  is at minimum fluid capacity, where the moveable piston  310  is about to reverse direction. The fluid chamber  312   a  has been filling by pulling formation fluid  320  through the fluid input port  306  while the fluid chamber  312   b  has been emptying by pushing formation fluid  320  through the formation fluid output port  307  for sample storage. This action provides a push-pull pumping action that allows the moveable piston  310  to pressure compensate itself. 
     As the moveable piston  310  reverses direction, the fluid chamber  312   b  starts pulling formation fluid  320  through the fluid input port  306  while the fluid chamber  312   b  begins emptying by pushing formation fluid  320  through the formation fluid output port  307  for sample storage. This action typically continues until a fluid sampling is complete. As noted earlier, the container hydraulic oil  322  is employed for reducing stress across or pressure balancing the first and second seals  315 ,  316 . Adding pressure compensation for the first and second seals  315 ,  316  serves to decrease or prevent wellbore fluid intrusion across the first and second seals  315 ,  316 . This hydraulic fluid pressure compensation is provided by the wellbore pressure compensator  326  coupled to the hydraulic oil bypass line  328 . The third seal  317  is immersed in the formation fluid  320 , where seal leakage only slightly reduces a pumping efficiency of the moveable piston  310 . The pair of input check valves  325  and the pair of output check valves  327  prevent any wellbore fluid backflow. 
     The mechanical piston actuator  330  converts rotary motion into linear motion. Here, the rotary portion  330   a  is coupled to the fluid container  305  and the linear portion  330   b  is coupled to the moveable piston  310 . Rotating the rotary portion  330   a  in opposite directions moves the linear portion  330   b  and therefore the moveable piston  310  in correspondingly opposite directions causing the formation fluid pump  300  to pump formation fluid. In one example, the rotary portion  330   a  of the mechanical piston actuator  330  is coupled to the fluid container  305  with first and second actuator bearing seals  333   a ,  333   b . This arrangement typically requires that the rotary portion  330   a  be mechanically connected to a rotary drive shaft that causes penetration of the fluid container  305  and requires the first actuator rotary bearing seal  333   a . The second actuator bearing seal  333   b  may typically require only a rotary bearing  333   b . The first and second torsion relief springs  340   a ,  340   b  are positioned at each end of the rotary portion  330   a  of the mechanical piston actuator  330  to assist with a rotational reversal of the mechanical piston actuator  330 . The first and second torsion relief springs  340   a ,  340   b  can facilitate a smooth rotational reversal of the mechanical piston actuator  330 . 
     The alternative magnetic coupling device  335  may be employed thereby replacing the rotary bearing seal  333   a . The magnetic coupling device  335  allows a special form of sealing that provides torque without rotating seal surfaces. With magnetic coupling, the container hydraulic oil  322  and an outside atmosphere may be hermetically separated from each other through static seals. Torque is not transferred through a classic mechanical shaft connection, but rather only through magnetic field coupling from a drive to the mechanical piston actuator  330 . The magnetic coupling may be synchronous magnetic coupling (i.e., the magnetic coupling works without slip) as long as a maximum transferable torque is not exceeded. Additionally, this form of magnetic coupling typically requires minimal maintenance and may be employed at elevated temperatures and pressures. 
     As discussed previously, the gear box  342  employs the gear box output shaft  345  to drive the mechanical piston actuator  330  and thereby the moveable piston  310 . The gear box  342  may be employed in the fluid pump  300  to reduce a rotary speed provided by the BLDC electric motor  348 . This “step-down” action allows the BLDC electric motor  348  to operate at a higher rotary speed for efficiency purposes, when required. The BLDC electric motor  348  driving the motor output shaft  350  is mechanically coupled through the gear box  342  to the rotary portion  330   a  of the mechanical piston actuator  330 . It is controlled to alternately rotate the rotary portion  330   a  of the mechanical piston actuator  330  in opposite directions to linearly move the linear portion  330   b  along with the moveable piston  310  in opposite directions and thereby pump wellbore fluid from the fluid pump  300 . As noted, the BLDC electric motor  348 , the gear box  342  and the mechanical piston actuator  330  provide a mechanical direct drive capability (as opposed to a hydraulic drive) for the moveable piston  310 . 
     The BLDC motor driver  355  accepts electrical power and up-hole control input and provides motor power and control to the BLDC electric motor  348  through the motor power and control lines  357 . Specifically, the BLDC motor driver  355  may provide downhole control of the BLDC electric motor  348  by employing field-oriented control (FOC) of the BLDC electric motor  348 , which provides an optimization of motor torque for a motor shaft rotary speed. Additionally, field-oriented motor control reduces torque ripple resulting in smoother motor performance and quieter motor operation. 
     Field-oriented control is a variable-frequency drive control technology in which motor stator currents of a three-phase electric motor are defined as two orthogonal components that can be visualized with a vector. One component defines the magnetic flux of the motor while the other component defines the torque of the motor. A common objective of field-oriented control is to maximize the motor&#39;s torque per ampere of load current. Typically a proportional-integral control approach may be used to keep measured current components at their reference values. Then, pulse-width modulation of the variable-frequency drive defines motor switching signals based on stator voltage references. Additionally, general downhole tool and wellbore pump control signals, and electrical power in some examples, is provided from a surface location, such as the wellbore systems  100  and  150 . 
       FIG. 4  illustrates an example of a mechanical piston actuator, generally designated  400 , as may be employed in a formation fluid pump such as the fluid pump  300  depicted in  FIG. 3 . In this example, the mechanical piston actuator  400  is a “ballscrew” and includes a rotary portion  405  having a helical raceway  407 , a linear portion  410  having a set of ball bearings  425  coupled to the helical raceway  407  and a moveable piston mounting  415 , having mounting support bearings  420   a ,  420   b  coupled to the linear portion  410 . 
     The mechanical piston actuator  400  is a mechanical linear actuator that translates rotational motion into linear motion with reduced friction. The helical raceway  407  and the set of ball bearings  425  coupled to the helical raceway  407  act as a precision screw. As well as being able to apply or withstand higher thrust loads, it can do so with reduced internal friction. It may be constructed to close tolerances and is therefore suitable for use in situations in which higher precision may be necessary. The set of ball bearings  425  acts as a “nut” for the threaded shaft, thereby giving rise to the term “ballscrew”. Ballscrew nuts are required to have a mechanism to re-circulate the balls, as seen on the set of ball bearings  425 . 
     Other forms of these rotary-to-linear actuators are based on employing rotating rods instead of ball bearings, which may provide higher thrust loads with reduced operating friction, if required. Another form of rotary-to-linear actuator based on a rotating rod is the “rolling ring drive”. In this design, a smooth (thread-less) rotary actuator rod or shaft is employed with at least three rolling-ring bearings arranged symmetrically in a surrounding housing. The rolling-ring bearings are set at an angle to the rotary actuator rod, and this angle determines the direction and rate of linear motion per revolution of the rotary actuator rod. An advantage of this design, over the conventional ballscrew, is the reduction of backlash and loading caused by preload nuts. Of course, other current or future rotary-to-linear actuators may be employed in the wellbore pump of  FIG. 3  to activate the moveable piston  310 . 
       FIG. 5  illustrates an example of a formation fluid pumping method, generally designated  500 , carried out according to the principles of the present disclosure. The method  500  starts in a step  505  and then, a formation fluid container is provided having a fluid input port and a fluid output port, in a step  510 . A moveable piston is positioned inside the formation fluid container having two fluid chambers to alternately pump a quantity of formation fluid in the formation fluid container from the fluid input port to the fluid output port, in a step  515 . A mechanical piston actuator is provided having a rotary portion attached to the fluid container and a linear portion attached to the moveable piston, in a step  520 . A brushless direct current motor is coupled to the rotary portion of the mechanical piston actuator to alternately rotate the rotary portion of the mechanical piston actuator in opposite directions and thereby linearly move the linear portion along with the moveable piston in opposite directions to pump the quantity of formation fluid, in a step  525 . 
     In one example, a gear box is positioned between the brushless direct current motor and the rotary portion of the mechanical piston actuator. In another example, the moveable piston is pressure compensated inside the wellbore fluid container. In yet another example, the brushless direct current motor is coupled to the rotary portion of the mechanical piston actuator with a magnetic coupling. In a further example, the brushless direct current motor provides an indication of motor axis rotation that relates directly to the quantity of formation fluid pumped. 
     In a still further example, the brushless direct current motor is controlled to vary a pumping rate of the quantity of formation fluid. In yet a further example, control of the brushless direct current motor is field-oriented thereby controlling a motor torque from the motor shaft of the brushless direct current motor. In a yet further example, a torsion relief spring is positioned at each end of the rotary portion of the mechanical piston actuator to assist with a rotational reversal of the mechanical piston actuator. The torsion relief springs can facilitate a smooth rotational reversal of the mechanical piston actuator. The method  500  ends in a step  530 . 
     While the method disclosed herein has been described and shown with reference to particular steps performed in a particular order, it will be understood that these steps may be combined, subdivided, or reordered to form an equivalent method without departing from the teachings of the present disclosure. Accordingly, unless specifically indicated herein, the order or the grouping of the steps is not a limitation of the present disclosure. 
     Those skilled in the art to which this application relates will appreciate that other and further additions, deletions, substitutions and modifications may be made to the described embodiments. 
     Various aspects of the disclosure can be claimed including the apparatuses, systems and methods as disclosed herein. Aspects disclosed herein include: 
     A. A formation fluid pump, including (1) a formation fluid container having a fluid input port and a fluid output port; (2) a moveable piston inside the formation fluid container having two fluid chambers positioned to alternately pump a quantity of formation fluid in the formation fluid container from the fluid input port to the fluid output port; (3) a mechanical piston actuator having a rotary portion attached to the formation fluid container and a linear portion attached to the moveable piston; and (4) a brushless direct current motor coupled to the rotary portion of the mechanical piston actuator and controlled to alternately rotate the rotary portion of the mechanical piston actuator in opposite directions to linearly move the linear portion along with the moveable piston in opposite directions and pump the quantity of formation fluid. 
     B. A method of pumping formation fluid, including: (1) providing a formation fluid container having a fluid input port, a fluid output port, and a moveable piston positioned therein having two fluid chambers to alternately pump a quantity of formation fluid in the formation fluid container from the fluid input port to the fluid output port; (2) providing a mechanical piston actuator having a rotary portion attached to the formation fluid container and a linear portion attached to the moveable piston; and (3) coupling a brushless direct current motor to the rotary portion of the mechanical piston actuator to alternately rotate the rotary portion of the mechanical piston actuator in opposite directions and thereby linearly move the linear portion along with the moveable piston in opposite directions to pump the quantity of formation fluid. 
     C. A wellbore system, including: (1) surface equipment connected through a communications link to a downhole tool; and (2) a formation fluid pump in the downhole tool, having: (a) a formation fluid container having a fluid input port and a fluid output port, (b) a moveable piston inside the formation fluid container having two fluid chambers positioned to alternately pump a quantity of formation fluid in the formation fluid container from the fluid input port to the fluid output port, and (c); a mechanical piston actuator having a rotary portion attached to the formation fluid container and a linear portion attached to the moveable piston; and a brushless direct current motor coupled to the rotary portion of the mechanical piston actuator and controlled to alternately rotate the rotary portion of the mechanical piston actuator in opposite directions to linearly move the linear portion along with the moveable piston in opposite directions and pump the quantity of formation fluid. 
     Each of aspects A, B and C can have one or more of the following additional elements in combination: 
     Element  1 : further comprising a gear box positioned between the brushless direct current motor and the rotary portion of the mechanical piston actuator. Element  2 : wherein the moveable piston is pressure compensated inside the formation fluid container. Element  3 : wherein the brushless direct current motor is coupled to the rotary portion of the mechanical piston actuator with a magnetic coupling. Element  4 : wherein the brushless direct current motor provides an indication of motor axis rotation that relates directly to the quantity of formation fluid pumped. Element  5 : wherein the brushless direct current motor is controlled to vary a pumping rate of the quantity of formation fluid. Element  6 : wherein control of the brushless direct current motor is field-oriented thereby controlling a motor torque from the motor shaft of the brushless direct current motor. Element  7 : wherein a torsion relief spring is positioned at each end of the rotary portion of the mechanical piston actuator to assist with a rotational reversal of the mechanical piston actuator. Element  8 : wherein the mechanical piston actuator is a ball screw. Element  9 : further employing a gear box positioned between the brushless direct current motor and the rotary portion of the mechanical piston actuator to alternately rotate the rotary portion. Element  10 : wherein the moveable piston is pressure compensated inside the formation fluid container. Element  11 : wherein the brushless direct current motor is coupled to the rotary portion of the mechanical piston actuator with a magnetic coupling. Element  12 : wherein the brushless direct current motor provides an indication of motor axis rotation that relates directly to the quantity of formation fluid pumped. Element  13 : further comprising controlling the brushless direct current motor to vary a pumping rate of the quantity of formation fluid. Element  14 : controlling a motor torque from the motor shaft of the brushless direct current motor employing field-oriented control. Element  15 : assisting with a rotational reversal of the mechanical piston actuator employing a torsion relief spring positioned at each end of the rotary portion of the mechanical piston actuator. Element  16 : wherein the mechanical piston actuator is a roller screw assembly. Element  17 : further comprising a gear box positioned between the brushless direct current motor and the rotary portion of the mechanical piston actuator.