Patent Publication Number: US-8967253-B2

Title: Pump control for formation testing

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a divisional of U.S. patent application Ser. No. 12/500,725, filed Jul. 10, 2009, which is a continuation of U.S. patent application Ser. No. 11/616,520, filed Dec. 27, 2006, now U.S. Pat. No. 7,594,541, which are both hereby incorporated by reference in their entireties. 
    
    
     BACKGROUND 
     1. Technical Field 
     This disclosure is directed toward geological formation testing. More specifically, this disclosure is directed toward controlling the pump or fluid displacement unit (FDU) of a formation testing tool. 
     2. Description of the Related Art 
     Wells are generally drilled into the ground or ocean bed to recover natural deposits of oil and gas, as well as other desirable materials, that are trapped in geological formations in the Earth&#39;s crust. A well is typically drilled using a drill bit attached to the lower end of a “drill string.” Drilling fluid, or “mud,” is typically pumped down through the drill string to the drill bit. The drilling fluid lubricates and cools the drill bit, and it carries drill cuttings back to the surface in the annulus between the drill string and the borehole wall. 
     For successful oil and gas exploration, it is necessary to have information about the subsurface formations that are penetrated by a borehole. For example, one aspect of standard formation evaluation relates to the measurements of the formation pressure and formation permeability. These measurements are essential to predicting the production capacity and production lifetime of a subsurface formation. 
     One technique for measuring formation properties includes lowering a “wireline” tool into the well to measure formation properties. A wireline tool is a measurement tool that is suspended from a wire as it is lowered into a well so that is can measure formation properties at desired depths. A typical wireline tool may include a probe that may be pressed against the borehole wall to establish fluid communication with the formation. This type of wireline tool is often called a “formation tester.” Using the probe, a formation tester measures the pressure of the formation fluids, generates a pressure pulse, which is used to determine the formation permeability. The formation tester tool also typically withdraws a sample of the formation fluid for later analysis. 
     In order to use any wireline tool, whether the tool be a resistivity, porosity or formation testing tool, the drill string must be removed from the well so that the tool can be lowered into the well. This is called a “trip” downhole. Further, the wireline tools must be lowered to the zone of interest, generally at or near the bottom of the hole. A combination of removing the drill string and lowering the wireline tools downhole are time-consuming measures and can take up to several hours, depending upon the depth of the borehole. Because of the great expense and rig time required to “trip” the drill pipe and lower the wireline tools down the borehole, wireline tools are generally used only when the information is absolutely needed or when the drill string is tripped for another reason, such as changing the drill bit. Examples of wireline formation testers are described, for example, in U.S. Pat. Nos. 3,934,468; 4,860,581; 4,893,505; 4,936,139; and 5,622,223. 
     As an improvement to wireline technology, techniques for measuring formation properties using tools and devices that are positioned near the drill bit in a drilling system have been developed. Thus, formation measurements are made during the drilling process and the terminology generally used in the art is “MWD” (measurement-while-drilling) and “LWD” (logging-while-drilling). A variety of downhole MWD and LWD drilling tools are commercially available. Further, formation measurements can be made in tool strings which are not have a drill bit a lower end thereof, but which are used to circulate mud in the borehole. 
     MWD typically refers to measuring the drill bit trajectory as well as borehole temperature and pressure, while LWD refers to measuring formation parameters or properties, such as resistivity, porosity, permeability, and sonic velocity, among others. Real-time data, such as the formation pressure, allows the drilling company to make decisions about drilling mud weight and composition, as well as decisions about drilling rate and weight-on-bit, during the drilling process. The distinction between LWD and MWD is not germane to this disclosure. 
     Formation evaluation while drilling tools capable of performing various downhole formation testing typically include a small probe or pair of packers that can be extended from a drill collar to establish hydraulic coupling between the formation and pressure sensors in the tool so that the formation fluid pressure may be measured. Some existing tools use a pump to actively draw a fluid sample out of the formation so that it may be stored in a sample chamber in the tool for later analysis. Such a pump may be powered by a generator in the drill string that is driven by the mud flow down the drill string. 
     However, as one can imagine, multiple moving parts involved in any formation testing tool, either of wireline or MWD, can result in equipment failure or less than optimal performance. Further, at significant depths, substantial hydrostatic pressure and high temperatures are experienced thereby further complicating matters. Still further, formation testing tools are operated under a wide variety of conditions and parameters that are related to both the formation and the drilling conditions. 
     Therefore, what is needed are improved downhole formation evaluation tools and improved techniques for operating and controlling such tools so that such downhole formation evaluation tools are more reliable, efficient, and adaptable to both formation and mud circulation conditions. 
     SUMMARY OF THE DISCLOSURE 
     In one embodiment, a fluid pump system for a downhole tool connected to a pipe string positioned in a borehole penetrating a subterranean formation is disclosed. The system includes a pump that is in fluid communication with at least one of the formation and the borehole, and that is powered by mud flowing downward through the pipe string. The pump is linked to a controller which controls the pump speed based upon at least one parameter selected from the group consisting of mud volumetric flow rate, tool temperature, formation pressure, fluid mobility, system losses, mechanical load limitations, borehole pressure, available power, electrical load limitations and combinations thereof. 
     In another embodiment, a fluid pump system for a downhole tool connected to a pipe string positioned in a borehole penetrating a subterranean formation is disclosed. The system includes a turbine, a transmission, a pump, a first sensor and a controller. The turbine is powered by mud flowing downward through the pipe string. The turbine and pump are operatively connected to the transmission with a first sensor being coupled to one of the turbine and the mud flow for sensing at least one of turbine speed and mud flow rate. The controller is communicably coupled to the transmission and the sensor, such that the controller adjusts the transmission based on one of the speed of the turbine and the mud flow rate. 
     In yet another embodiment, a method for controlling the pump of a downhole tool is disclosed. The method includes providing the tool with a downhole controller for controlling a pump; measuring at least one system parameter of the tool disposed in a wellbore; calculating a pump operation limit for the pump based upon the at least one system parameter; operating the pump; and limiting the pump operation of the pump with the controller. 
     In another embodiment, a method for operating a pump system for a downhole tool connected to a pipe string positioned in a borehole penetrating a subterranean formation is disclosed. The method includes rotating a turbine disposed in the wellbore with mud flowing downward through the pipe string; obtaining a power output from the turbine; operating a pump with the power output from the turbine; measuring the speed of the turbine; and adjusting a transmission disposed between the turbine and the pump with a controller disposed in the tool based on the speed of the turbine. 
     Other advantages and features will be apparent from the following detailed description when read in conjunction with the attached drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the disclosed methods and apparatuses, reference should be made to the embodiments illustrated in greater detail on the accompanying drawings, wherein: 
         FIG. 1  is a front elevation view depicting a drilling system in which the disclosed formation testing system may be employed; 
         FIG. 2  is a front elevation view depicting one embodiment of a bottom hole assembly (BHA) in a wellbore made in accordance with this disclosure; 
         FIG. 3  is a sectional view illustrating a fluid analysis and pump-out module of a disclosed formation testing system; 
         FIG. 4  schematically illustrates a pump for delivering formation fluid from a probe disposed in a tool blade into sample chambers, which are also illustrated; 
         FIG. 5  is a flow diagram illustrating one method disclosed herein for utilizing formation and system parameters for controlling a pump in a formation testing tool; 
         FIG. 5A  is a graph depicting a turbine power curve including a maximum power output; 
         FIG. 6  is an electrical diagram illustrating one sampling control loop used to carry out the method of  FIG. 5  to control the pump motor of the disclosed formation testing system; 
         FIG. 7  is a diagram illustrating an alternative pumping unit assembly for use with the disclosed formation testing system; and 
         FIG. 8  is a diagram illustrating an alternative throttle valve for the pump unit assembly illustrated in  FIG. 7 . 
     
    
    
     It should be understood that the drawings are not necessarily to scale and that the disclosed embodiments are sometimes illustrated diagrammatically and in partial views. In certain instances, details which are not necessary for an understanding of the disclosed methods and apparatuses or which render other details difficult to perceive may have been omitted. It should be understood, of course, that this disclosure is not limited to the particular embodiments illustrated herein. 
     DETAILED DESCRIPTION 
     This disclosure relates to fluid pumps and sampling systems described below and illustrated in  FIGS. 2-8  that may be used in a downhole drilling environment, such as the one illustrated in  FIG. 1 . In some refinements, this disclosure relates to methods for using and controlling the disclosed fluid pumps. In one or more refinements, a formation evaluation while drilling tool includes an improved fluid pump and an improved method of controlling the operation of the pump. In some other refinements, improved methods of formation evaluation while drilling are disclosed. 
     Those skilled in the art given the benefit of this disclosure will appreciate that the disclosed apparatuses and methods have application during operation other than drilling and that drilling is not necessary to practice this invention. While this disclosure relates mainly to sampling, the disclosed apparatus and method can be applied to other operations including injection techniques. 
     The phrase “formation evaluation while drilling” refers to various sampling and testing operations that may be performed during the drilling process, such as sample collection, fluid pump out, pretests, pressure tests, fluid analysis, and resistivity tests, among others. It is noted that “formation evaluation while drilling” does not necessarily mean that the measurements are made while the drill bit is actually cutting through the formation. For example, sample collection and pump out are usually performed during brief stops in the drilling process. That is, the rotation of the drill bit is briefly stopped so that the measurements may be made. Drilling may continue once the measurements are made. Even in embodiments where measurements are only made after drilling is stopped, the measurements may still be made without having to trip the drill string. 
     In this disclosure, “hydraulically coupled” is used to describe bodies that are connected in such a way that fluid pressure may be transmitted between and among the connected items. The term “in fluid communication” is used to describe bodies that are connected in such a way that fluid can flow between and among the connected items. It is noted that “hydraulically coupled” may include certain arrangements where fluid may not flow between the items, but the fluid pressure may nonetheless be transmitted. Thus, fluid communication is a subset of hydraulically coupled. 
       FIG. 1  illustrates a drilling system  10  used to drill a well through subsurface formations, shown generally at  11 . A drilling rig  12  at the surface  13  is used to rotate a drill string  14  that includes a drill bit  15  at its lower end. The reader will note that this disclosure relates generally to work strings that do not include a drill bit  15  at the lower end thereof which are lowered into the wellbore like a drill string and that allow for mud circulation similar to the way a drill string  14  circulates mud. As the drill bit  15  is being rotated, a “mud” pump  16  is used to pump drilling fluid, commonly referred to as “mud” or “drilling mud,” downward through the drill string  14  in the direction of the arrow  17  to the drill bit  15 . The mud, which is used to cool and lubricate the drill bit, exits the drill string  14  through ports (not shown) in the drill bit  15 . The mud then carries drill cuttings away from the bottom of the borehole  18  as it flows back to the surface  13  as shown by the arrow  19  through the annulus  21  between the drill string  14  and the formation  11 . While a drill string  14  is shown in  FIG. 1 , it will be noted here that this disclosure is also applicable to work strings and pipe strings as well. 
     At the surface  13 , the return mud is filtered and conveyed back to the mud pit  22  for reuse. The lower end of the drill string  14  includes a bottom-hole assembly (“BHA”)  23  that includes the drill bit  15 , as well as a plurality of drill collars  24 ,  25  that may include various instruments, such as LWD or MWD sensors and telemetry equipment. A formation evaluation while drilling instrument may, for example, may also include or be disposed within a centralizer or stabilizer  26 . 
     The stabilizer  26  comprises blades that are in contact with the borehole wall as shown in  FIG. 1  to limit “wobble” of the drill bit  15 . “Wobble” is the tendency of the drill string, as it rotates, to deviate from the vertical axis of the wellbore  18  and cause the drill bit to change direction. Advantageously, a stabilizer  26  is already in contact with the borehole wall  27 , thus, requiring less extension of a probe to establish fluid communication with the formation. Those having ordinary skill in the art will realize that a formation probe could be disposed in locations other than in a stabilizer without departing from the scope of this disclosure. 
     Turning to  FIG. 2 , a disclosed fluid sampling tool  30  hydraulically connects to the downhole formation via pressure testing tool shown generally at  31 . The tool  31  comprises an extendable probe and resetting pistons as shown, for example, in U.S. Pat. No. 7,114,562. The fluid sampling tool  30  preferably includes a fluid description module and a fluid pumping module, both of which are disposed in the module or section  32  and, optionally, a sample collection module  33 . Various other MWD instruments or tools are shown at  34  which may include, but are not limited to, resistivity tools, nuclear (porosity and/or density) tools, etc. The drill bit stabilizers are shown at  26  and the drill bit is shown at  15  in  FIG. 2 . It will be noted that the relative vertical placement of the components  31 ,  32 ,  33  and  34  can vary and that the MWD modules  34  can be placed above or below the pressure tester module  31  and the fluid pumping and analyzing module  32  as well as the fluid sample collection module  33  can also be placed above or below the pressure testing module  31  or MWD modules  34 . Each module  31 - 34  will usually have a length ranging from about 30 to about 40 feet. 
     Turning to  FIG. 3 , a formation fluid pump and analysis module  32  is disclosed with highly adaptive control features. Various features disclosed in  FIGS. 3 and 4  are used to adjust for changing environmental conditions in-situ. To cover a wide performance range, ample versatility is necessary to run the pump motor  35 , together with sophisticated electronics or controller  36  and firmware for accurate control. 
     Power to the pump motor  35  is supplied from a dedicated turbine  37  which drives and alternator  38 . The pump  41 , in one embodiment, includes two pistons  42 ,  43  connected by a shaft  44  and disposed within corresponding cylinders  45 ,  46  respectively. The dual piston  42 ,  43 /cylinder  45 ,  46  arrangement works through positive volume displacement. The piston  42 ,  43  motion is actuated via the planetary roller-screw  47  also detailed in  FIG. 4 , which is connected to the electric motor  35  via a gearbox  48 . The gearbox or transmission  48  driven by the motor may be used to vary a transmission ratio between the motor shaft and the pump shaft. Alternatively, the combination of the motor  35  and the alternator  38  may be used to accomplish the same objective. 
     The motor  35  may be part or integral to the pump  41 , but alternatively may be a separate component. The planetary roller screw  47  comprises a nut  39  and a threaded shaft  49 . In a preferred embodiment, the motor  35  is a servo motor. The power of the pump  41  should be at least 500 W, which corresponds to about 1 kW at the alternator  38  of the tool  32 , and preferably at least about 1 kW, which corresponds to at least about 2 kW at the alternator  38 . 
     In lieu of the planetary roller-screw  47  arrangement shown in  FIG. 4 , other means for fluid displacement may be employed such as lead screw or a separate hydraulic pump, which would output alternating high-pressure oil that could be used to reciprocate the motion of the piston assembly  42 ,  43 ,  44 . 
     Returning to  FIG. 3 , the sampling/analysis drill module  32  is shown with primary components in one particular arrangement, but other arrangements are obviously possible and within the knowledge of those skilled in the art. The arrows  51  indicate the flow of drilling mud through the module  32 . An extendable hydraulic/electrical connector  52  is used to connect the module  32  to the testing tool  31  (see  FIG. 2 ) and another extendable hydraulic/electrical connector  59  is used to connect the module  32  to the sample collection module  33  ( FIG. 2 ). Examples of hydraulic connectors suitable for connecting collars can be found for example in U.S. patent application Ser. No. 11/160,240, assigned to the assignee of the present invention, and incorporated by reference herein. The downhole formation fluid enters the tool string through the pressure testing tool  31  ( FIG. 2 ) and is routed to the valve block  53  via the extendable hydraulic/electrical connector  52 . Still referring to  FIG. 3 , at the valve block  53 , the fluid sample is initially pumped through the fluid identification unit  54 . The fluid identification unit  54  comprises an optics module  55  together with other sensors (not shown) and a controller  56  to determine fluid composition—oil, water, gas, mud constituents—and properties such as density, viscosity, resistivity, etc. 
     From the fluid identification unit  54 , the fluid enters the fluid displacement unit (FDU) or pump  41  via the set of valves in the valve block  53  which is explained in greater detail in connection with  FIG. 4 . As seen in  FIG. 3 , before the fluid reaches the valve block  53 , it proceeds from the probe of the pressure tester  31  through the hydraulic/electrical connector  52  and through the analyzer  54 . 
       FIG. 3  also shows a schematic diagram from a probe  201  disposed, for example, in a blade  202  of the tool  31  (see also  FIG. 2 ). Two flow lines  203 ,  204  extend from the probe  201 . The flow lines  203 ,  204  can be independently isolated by manipulating the sampling isolation valve  205  and/or the pretest isolation valve  206 . The flow line  203  connects the pump and analyzer tool  32  to the probe  201  in the tester tool  31 . The flow line  204  is used for “pretests.” 
     During a pretest, the sampling isolation valve  205  to the tool  32  is closed, the pretest isolation valve  206  to the pretest piston  207  is open, and the equalization valve  208  is closed. The probe  201  is extended toward the formation is indicated by the arrow  209  and, when extended, is hydraulically coupled to the formation (not shown). The pretest piston  207  is retracted in order to lower the pressure in the flow line  204  until the mud cake is breached. The pretest piston  207  is then stopped and the pressure in the flow line  204  increases as it approaches the formation pressure. The formation pressure data can be collected during the pretest. The data collected during the pretest (or other analogous test) may become one of the parameters used in part  85  of  FIG. 5  as discussed below. The pretest can also be used to determine that the probe  201  and the formation are hydraulically coupled. 
     Referring to  FIG. 4 , the fluid gets routed to either one of the two displacement chambers  45  or  46 . The pump  41  operates such that there is always one chamber  45  or  46  drawing fluid in, while the opposite  45  or  46  is expulsing fluid. Depending on the fluid routing and equalization valve  61  setting, the exiting liquid is pumped back to the borehole  18  (or borehole annulus) or through the hydraulic/electrical connector  59  to one of the sample chambers  62 ,  63 ,  64 , which are located in an adjoining separate drill collar  33  (see also  FIG. 2 ). While only three sample chambers  62 ,  63 ,  64  are shown, it will be noted that more or less than three chambers  62 ,  63 ,  64  may be employed. Obviously, the number of chambers is not critical and the choice of three chambers constitutes but one preferred design. 
     Still referring to  FIG. 4 , the pumping action of the FDU pistons  42 ,  43  is achieved via the planetary roller screw,  47  nut  39  and threaded shaft  49 . The variable speed motor  35  and associated gearbox  48  drives the shaft  49  in a bi-directional mode under the direction of the controller  36  shown in  FIG. 3 . Gaps between the components are filled with oil  50  and an annulus bellows compensator is shown at  50   a.    
     Still referring to  FIG. 4 , during intake into the chamber  45 , fluid passes into the valve block  53  and past the check valve  66  before entering a the chamber  45 . Upon output from the chamber  45 , fluid passes through the check valve  67  to the fluid routing and equalization valve  61  where it is either dumped to the borehole  18  or passed through the hydraulic/electrical connector  59 , check valve  68  and into one of the chambers  62 - 64 . Similarly, upon intake into the chamber  46 , fluid passes through the check valve  71  and into the chamber  46 . Upon output from the chamber  46 , fluid passes through the check valve  72 , through the fluid routing and equalization valve  61  and either to the borehole  18  or to the fluid sample collector module  33 . 
     During a sample collecting operation, fluid gets initially pumped to the module  32  and exits the module  32  via the fluid routing and equalization valve  61  to the borehole  18 . This action flushes the flow-line  75  from residual liquid prior to actually filling a sample bottle  62 - 64  with new or fresh formation fluid. Opening and closing of a bottle  62 - 64  is performed with sets of dedicated seal valves, shown generally at  76  which are linked to the controller  36  or other device. The pressure sensor  77  is useful, amongst other things, as a indicative feature for detecting that the sample chambers  62 - 64  are all full. Relief valve  74  is useful, amongst other things, as a safety feature to avoid over pressuring the fluid in the sample chamber  62 - 64 . Relief valve  74  may also be used when fluid needs to be dumped to the borehole  18 . 
     Returning to  FIG. 3 , a dedicated turbine-alternator  37 ,  38  is needed to provide the necessary amount of electrical power to drive the pump  41 . It is an operational requirement that during sampling operations mud is being pumped through the drill string  14 . Pumping rates need to be sufficient to ensure both MWD mud pulse telemetry communication back to surface as well (if utilized) as sufficient angular velocity for the turbine  37  to provide adequate power to the motor  35  for the pump  41 . 
       FIG. 5  illustrates one disclosed method  80  for controlling the pumping system  41  of the tool  32  during fluid sampling. The pumping system  41  is controlled preferably by a downhole controller  36  (see  FIG. 3 ) that executes instructions stored in a permanent memory (EPROM) of the tool assembly  30 . The downhole controller may insure that the pumping  41  system is not driven beyond its operational limits and may ensure that the pumping system is operating efficiently. The downhole controller collects in situ measurements from the sensor(s) in the tool  31  and/or a sensor(s) in the tool  32  (see  FIG. 4 ) and uses these measurements in adaptive feedback loops of the method  80  to optimize the performance of the pump  41 /pumping system. 
     The method  80  is capable of operating the pumping system  41  of the tool  32  with no or minimal operator interference. Typically, the surface operator may initiate the sampling operation when the tool string  14  has stopped rotating (during a stand pipe connection for example), by sending a command to one or more of the downhole tools  31 - 33  by telemetry. The tool  32  will operate the pumping system  41  according to the method  80 . Any one or more of the tools  31 - 33  may periodically send information to the surface operator about the status of the sampling process, thereby assisting the surface operator in making decisions such as aborting the sampling, instructing the tool  33  to store a sample in a chamber, etc. The decision of the surface operator may be communicated to the downhole tools  31 - 33  by mud pulse telemetry. The tools  31 ,  32  may share downhole clock information. 
     Beginning at the left in  FIG. 5 , in part  85 , the tool  31  obtains formation/fluid characteristics/parameters that can be computed from the pressure data collected during a pretest as set forth above (see also U.S. Pat. Nos. 5,644,076 and 7,031,841 or U.S. Publication No. 2005/0187715) and sends the parameters to the tool  32  in part  86 . Alternatively or in addition, other information from other tools may be sent to the tool  32  in part  86 , such as depth of invasion from a resistivity tool, etc. 
     The following are examples that may be collected or assimilated in part  85  and sent to the tool in part  86 : a hydrostatic pressure in the wellbore, a circulating pressure in the wellbore, a mobility of the fluid, which may be characterized as the ratio of the formation permeability to the fluid viscosity, and formation pressure. The pressure differential between the hydrostatic pressure and the formation pressure is also called the overbalance pressure. A pretest, or any other pressure test, may give more information, such as mudcake permeability, that can also be sent to tool  32 . Also, fewer or other parameters may be sent to tool  32 , for example if the parameters listed above are not available. 
     In part  87 , two operations are performed— 87   a  and  87   b . In  87   a  a desired pump parameter is determined based on information obtained about the formation parameter(s) determined in part  85 . In one embodiment, the desired pump parameter may be a “sampling protocol/sequence,” which refers to a control sequence for the sampling pump. The sequence may be formulated as prescribed pressure levels, pressure variations, and/or flow rates of the pump and/or the flowlines. These formulations may be expressed as a function of time, volume, etc. 
     In one embodiment, this sequence contains: (1) an investigation phase where the formation/wellbore model is confirmed, refined or completed, where the pump rate is fine tuned and where the mud filtrate is usually pumped out of the formation; and (2) a storage phase, usually stationary or “low shock”, where the fluid is pumped into a sample chamber. 
     In another example, the sampling protocol/sequence is derived from the mobility in part  85 . If the mobility is low, the sampling protocol corresponds to increasing the pump flow rate (“Q”) monotonically at a low rate, e.g., Q=0.1 cc/s after 1 min, Q=0.2 cc/s after 2 min, etc. If the mobility is high, the sampling protocol corresponds to increasing the pump flow rate monotonically at a high rate, e.g., Q=1 cc/s after 1 min, Q=2 cc/s after 2 min, etc. The reader will note that these values are for illustrative purposes only, and the actual values will depend typically upon probe inlet diameter among other system variables. The increase in flow rate may continue until system drive limits (power, mechanical load, electrical load) are approached in part  89 . The tool  32  may then continue to pump at that level arrived at in part  89  until sufficient mud filtrate is pumped out of the formation and a sample is taken. 
     In another example, the sampling protocol/sequence is derived by achieving an optimum balance between minimum pump drawdown pressure and maximum fluid volume pumped in a given time. The formation/wellbore model uses a cost function to determine an ideal/optimum/desired pump flow rate Q and its corresponding drawdown pressure differential for the storage phase. The cost function may penalize large drawdown pressure and low pump flow rate. The values or the shape of cost function may be adjusted from data collected during prior sampling operations by the tool  32 , and/or from data generated by modeling of sampling operations. Ideally, the ideal/optimum/desired pump flow rate Q and its corresponding drawdown pressure differential lie inside the system capabilities. Optionally, the formation/wellbore model includes a prediction of the contamination level of the sampled fluid by mud filtrate and the cost function includes a contamination level target. The ramping to this ideal/optimum/desired pump flow rate Q may further be determined by minimizing the time taken to investigate formation fluid prior to sample storage. The sampling protocol/sequence may further include variations around the ideal/optimum/desired pump flow rate Q used to confirm or further improve the value of the ideal/optimum/desired pump flow rate Q. 
     In yet another example, an Artificial Intelligence engine is used to learn proper protocol/sequences, preferably the system capabilities. Artificial Intelligence is used to combine previous sampling operation by the tool and real time measurements to determine a sampling protocol/sequence. The Artificial Intelligence engine uses a down-hole database storing previous run scenarios. 
     In  87   b , an expected formation response is calculated based on the formation parameters of part  85  and the corresponding pump parameters of part  87   a . For example, a formation/wellbore model may be generated that provides a prediction of the formation response to sampling by the tool  32 . In one example, the formation/wellbore model is an expression that expresses the drawdown pressure differential, the difference between the hydrostatic pressure in the wellbore and the pressure in the flow line, as a function of the formation flow rate. In particular, this expression is parameterized by the overbalance and the mobility. In another example, the formation/wellbore model comprises a parameter that describes the depth of invasion by the mud filtrate, and the model is capable of predicting the evolution of a fluid property, such as the gas oil ratio, or a contamination level for various sampling scenarios. In yet another example, models known in the art and derived to analyze a pretest (sandface pressure measurement) are adapted to analyze sampling operations (see U.S. Publication No. 2004/0045706) and to predict of the formation response to sampling by the tool  32  under various sampling scenarios. In yet another example, empirical models based on curve fitting techniques or neural network and techniques can also be used. 
     Note that the formation flow rate and pump flow rate are not always the same. These flow rate usually are predictable from each other with a tool or flow line model, as is well known in the art. In some cases, the formation flow rate is close to the pump flow rate. For simplicity it will be assumed that these two quantity are equals in the rest of the disclosure, but it should be understood that it may be necessary to use a tool of flow line model to compute one from the other one. 
     Referring now to the right side of  FIG. 5 . In part  81 - 84 , system parameters are determined. Specifically, in part  81  turbine parameters are determined, which may include determining the maximum power available downhole. 
     As mentioned previously, the pump  41  is powered by mud flowing downward through a work pipe, in this case through a turbine. The maximum power available for the pump  41  depends on the mudflow rate. The mudflow rate is dependent upon borehole parameters such as depth, diameter, hole deviation, upon the type of mud that is used and upon the local drilling rig. Thus, the mudflow rate is not known in advance and may change for various reasons. 
     The maximum available power determined in part  81  may be predicted using a model for the turbine  37  and/or turbo-alternator  37 ,  38 . This model may comprise power curves. For example, each power curve expresses the power generated by the turbo-alternator as a function of the turbine angular velocity.  FIG. 5A  shows one example of a power curve for a given mudflow rate. 
     As shown in the example of  FIG. 5A , the maximum power available P max  may be determined from a free spin angular velocity ω FS  and the associated power zero. These values will generate a power curve corresponding to the mud flow rate. This generated power curve has a peak power value P max  for limiting pumping operation. Assuming the mud flow rate stays constant, the power curve may be used to correlate a angular velocity ω OP  to any operational power P OP . 
     The maximum of this curve determines the maximum power available downhole in part  81 . Note that variations using values of the turbine angular velocity and the generated power over a time period may also be used. These methods may involve regressions techniques, for examples to determine the power curve corresponding to the current mudflow rate from data points collected over a period, and/or to track variations of the mudflow rate over a time period. 
     The calculated maximum power available downhole computed in part  81  may be used as a pump operation limit. The operation of the pump  41  may be limited based on this and/or other operation limits, as described below with respect to part  89 . In one example, the measured operational power by the turbo-alternator  37 ,  38  P OP  is compared to the maximum power P max . When the measured generated power approaches the maximum power, the pump flow rate and/or the differential pressure across the pump may be prevented to increase further. Limiting the pumping power, and consequently the power drawn from the turbo-alternator  37 ,  38 , may prevent the turbine from stalling. Preferably, the operating point (“L”) may be limited when the measured generated power by the turbo-alternator  37 ,  38  is around 80% of maximum power available downhole. 
     In part  82 , the control of the pump  41  is further based upon electrical load limitations. Specifically, the motor driver peak current is limited. The peak current is related to the torque required from the motor  35 . The motor  35  may thus be controlled by a feedback loop based upon the torque requirement. The driving value of the torque may be limited in part  89  as not to exceed the driver peak current. 
     In part  83 , the pump  41  is further controlled based upon mechanical load limitations. For example, the torque applied on the roller screw  39  may be limited. The motor  35  may be controlled by a feedback loop based upon the torque. The driving value of the torque may be limited as not to exceed the torque load on the roller screw  39  in part  89 . 
     In another example, other mechanical parts, such as the FDU pistons  42 ,  43  may have limitations in position, tension, or in linear speed. The motor  35  may be controlled by a feedback loop on the torque, rotation speed or number of revolution in order to satisfy these limitations. 
     In part  84 , the control of the pump is further based upon losses in the pumping system or the system loss(es). The maximum available power at the pump output is estimated, tracked or predicted as a function of the maximum available power downhole and losses in the pumping system in part  84 . For example, the high power electronics and the electrical driver losses vary with the motor angular velocity, the motor torque, and the temperature. Other losses such as friction losses may also take place in the system. The losses may be predicted by a loss model, that can be continuously adapted as part of the method  80 . The motor  35  may be controlled such that the product of motor torque and actual pump rate (the pump output power), does not exceed the maximum available power at the pump output. 
     Turning to part  89 , the pump parameters are updated. Briefly returning to  FIG. 4 , at the start of the pumping operation, the set pump drive parameters are preferably updated according to the initial pumping operation, which takes place at the finish of the formation pressure test by the probe  201 . At the start of the pumping operation, the flowline  204  in the tool  32  is at equilibrium with the formation pressure. The flow line tool three, which is leading to the sampling tool  33  is still closed off by the valve  205  and filled with fluid under hydrostatic pressure. In order not to introduce any pressure shocks to the formation, the pump  41  is operated prior to opening the flowline  203  and the valve block  53  to reduce the lower flowline pressure in the line  75  until it is equal to the formation pressure. Once this has occurred, the lower flowline valve block  53  is opened, and communication to the sampling probe  31  is established to commence pumping. At the beginning of sampling operations, the fluid routing and equalization valve  61  is actuated (i.e., the upper box  61   a  is active) and the pump  41  is activated until the pressure read by sensor  57  is equal to formation pressure, as read by the sensor  210  in the tool  31 . Then the sampling isolation valve  205  is opened. 
     Returning to part  89  of  FIG. 5 , the operation of the pump is then updated according to the desired pump parameters in part  87   a , under the control of the prevailing operational conditions determined in one or more of parts  81 ,  82 ,  83 , and  84 . If the desired pump parameters meet the operational conditions, the desired pump parameters are used to update the pump operation; if not, operational condition limits are used to update the pump operation. If the operational limits are reached, the tool  32  may communicate this information to the surface operator. A tool status flag may be sent by telemetry in part  94 . The operator upon review of this information can change mudflow rate to increase the turbine  37  speed and generate more power downhole. Also, an increased mudflow rate may lower the temperature of the mud reaching the tool  32  thereby cooling of parts in the tool  32 . 
     In part  90 , the formation/wellbore response to sampling by the tool  32  is measured. Specifically, the flow line pressure is measured along with the pump flow rate. Then, the formation flow rate is computed with a tool model. As mentioned before, the formation flow rate may be approximated by pump flowrate. 
     In addition to the measured formation/wellbore response to sampling by the tool  32 , the fluid analysis module  54  may be used to provide feedback to the algorithm. The fluid analysis module  54  may provide optical densities at different wavelength that can be used for example to compute the gas oil ratio of the sampled fluid, to monitor the contamination of the drawn fluid by the mud filtrate, etc. Other uses include the detection bubbles or sand in the flow line which may be indicated by scattering of optical densities. 
     Part  92   a  relates to comparing the formation/wellbore response measured in part  90  to the expected formation response of part  87   b . This comparison may be used to fine tune the sampling protocol/sequence  92   b . In one example, the drawdown differential pressure and the formation flow rate may be compared to a linear model. A pressure drop with respect to a linear trend or a rise less than proportional may indicate a lost seal, gas in the flow line, etc. These events may be confirmed by monitoring a flowline property (such as optical property) in the fluid analysis module. 
     Furthermore, part  92   a  may include comparing the evolution of a fluid property as measured in part  90  to an expected trend, for example part of model of part  87   b . For example, a fluid property related to the contamination (such as gas oil ratio) can be monitored and any deviation from an expected trend (known in the art as a clean-up trend) may be interpreted as a lost seal. A lost seal may require an adjustment of the sampling protocol/sequence ( 92   b ), for example reducing the pump flow rate in order to reduce the pressure differential across the probe packer. Other events may require an adjustment of the sampling protocol/sequence. 
     In another example, a fluid property is monitored in part  90  to detect if the sample fluid that enters the tool comes in single phase, that is that the sampling pressure is not below the bubble point or the dew precipitation of the reservoir fluid. The fluid property should be sensitive to the presence of bubbles or of solids in a fluid. Fluid optical densities, fluid optical fluorescence, and fluid density or viscosity are properties that can be used for early gas or solid detection when the drawdown pressure drops inadvertently too low in part  90 . 
     In yet another example, the evolution of a fluid property may also be used to calibrate a contamination model. The updated model can be used to predict the time required to achieve a target contamination level, by using methods derived from the art. In another example, a fluid property is monitored and its stationarity is detected and used to inform the surface operator that the pumped fluid is likely uncontaminated and that a sample may be stored. 
     In part  91 , the critical temperatures of pump system are measured, which may include the alternator  38  temperature, the high power electronics temperature and the electrical motor temperature, among others. In part  93 , the temperature measured in part  91  is compared to limit values, for example predetermined limit values. Assume for illustration purposes that the alternator temperature was measured in part  91 . If this temperature is too high, the motor speed limit may be reduced in part  93   b  in order to reduce the amount of power drawn from the alternator  38  and the heat generated in the alternator  38 . In another example, the motor driver temperature may have been measured in part  91 . If this temperature is too high, the motor speed limit may be reduced in order to reduce the torque required from the motor  35  and thus the heat generated by the current used to drive the motor  35 . 
     In part  94 , data that may be sent to the surface operator include formation pressure and calculated pump rate actual value. The transmission to the surface is usually achieved by mud telemetry. Other values that may be transmitted to the surface include fluid flow data cumulative sampling volume, one or more fluid properties from the fluid analyzer  54 , and tool status. The data sent by telemetry are encoded/compressed to optimize communication bandwidth between tools  31 / 32  and surface during a sampling operation. Operational data may also stored downhole on non-volatile memory (flash memory) for later retrieval upon return to the surface and use. 
       FIG. 6  illustrates one example of implementation of the method in  FIG. 5 . The control loop consists of a two layer cascaded control loop system. The control structure is typical for a constant speed motor regulation. The advantage of the proposed tool architecture is that the pump rate is directly coupled with the motor and therefore can be measured and controlled with very high resolution. The resolution is dependent on the motor position measurement implementation. A resolver coupled to the motor delivers high resolution motor position information. The actual pump flow rate Q act  can be computed from the motor position information and a system transmission constant. The motor torque actual value τ act  can be computed from the motor phase current and the motor position information. 
     The inner layer regulates the torque at measured positions; the outer layer regulates the motor speed and thus the pump rate. The actuators in the control loops operate with very fast dynamic response. The dynamic behavior of the formation is much slower than the pump control. 
     The sampling rate optimizer  105  sets an ideal sampling rate protocol/sequence, and reacts to any change in the behavior of the formation, such as flow line pressure drops detected by the sensor  57 , or to any change in the properties of the drawn fluid, such as gas in the flow line detected by optical fluid analyzer  55 . The sampling rate analyzer  105  may also continuously adapt the formation model. The sampling rate optimizer  105  feeds the speed limiter  104  with an ideal/optimum/desired flow rate. 
     The speed limiter  104  tracks temperatures of the system, and predicts the maximum available power from mud circulation. The speed number  104  limits the ideal/optimum/desired flow rate so that the power used by the pumping system does not exceed the maximum available power (within a safety factor of 0.8 for example) and so that the system does not overheats. The PID (proportional integral derivative) regulator  109  adjusts the value of the set torque τ set  from the difference between the pump rate set value Q set  and the calculated pump rate actual value Q act . The torque limiter  110  insures that the torque required to match the set sampling rate does not exceed the roller screw peak torque and the torque corresponding to the motor driver peak current. The PID (proportional integral derivative) regulator  112  compares the motor torque set value Q set  with the calculated pump rate actual value Q act . 
     The symbols used in  FIGS. 5 and 6  are listed below for convenience: 
     Q set : Pump rate set value 
     Q act : Calculated pump rate actual value 
     p f : Measured flow line pressure 
     τ set : Motor torque set value 
     τ act : Motor torque actual value 
     P max : Tracked maximum available turbine power 
     PWM: Pulse width modulator 
     PID: Proportional Integral Derivative regulator 
     Finally,  FIGS. 7 and 8  illustrate an alternative motor FDU arrangement  41   a . The motor  41   a  is a Moineau motor which is coupled to a gearbox or other mechanical transmission  48   a . The gearbox  48   a  is driven by a turbine  37   a  which, in turn, is driven by drilling mud flowing in the direction of the arrows  17   a . A mud outlet port is shown at  120  and a turbine stator coil is shown at  121 . Thus, the pump  41   a  does not include an alternator. Fluid flow to the turbine  37   a  is controlled by way of a solenoid valve  122 , which includes a throttle or cone-shaped seat  123 . The throttle  123  is adjusted to control the flow of mud going to the turbine  37   a , therefore controlling the flow of formation fluid pumped by the pumping unit  41   a . The valve  122  can be controlled at a fixed rate is preferably automatically controlled by the tool embedded software, using flow rate measured by flow meter  124  or pressure of the drawn fluid. 
     A mud check-valve is shown at  61   a  and a flowmeter at the outlet to the borehole is shown at  124 . Sample fluid is communicated from the pump  41   a  through a valve  53   a , which in this case is another solenoid valve similar to that shown at  122 . The flowline  75   a  leads to the sample chambers indicated schematically by the arrow  62   a - 64   a . The probe inlet is shown at  31   a  with a rubber packer  134 . A sensor (not shown) could also be included that monitors properties such as optical densities, fluorescence, resistance, pressure and temperature of the fluid drawn into the tool. 
     As an alternative, the gearbox  48   a  may be a continuously variable transmission (“CVT”), for example one made with rollers in the transmission ratio controlled by tool embedded software. The gearbox  48   a  may also allow reversing the direction of flow using a continuously variable transmission and an episode click here in combination. The tool of  FIG. 7  may also be used for injection procedures. 
     Turning to  FIG. 8 , an alternative to the solenoid valve  122  of  FIG. 7  is illustrated at  122   a . A motor  125  is used to drive a sleeve  126  with ports  127  therein into or out of alignment with the mud flow line  128 . A flow path of the mud is shown generally by the arrows  17   b.    
     While only certain embodiments have been set forth, alternatives and modifications will be apparent from the above description to those skilled in the art. These and other alternatives are considered equivalents and within the spirit and scope of this disclosure and the appended claims.