goodwin mud pump free sample

Manufactured since 1982, Goodwin pumps have been continually developed to create the world’s most dependable submersible pumps. Goodwin pumps can have electric or hydraulic motors to suit a multitude of tasks. The range of heavy duty slurry pumps us complemented by specialist acid resisting and high head dirty water submersible pumps.

Goodwin can supply a range of cables specially selected and tested for use with slurry pumps. For 100 size pumps cable is supplied with galvanised steel armouring to protect against damage. The IP68 rated cable gland seals against both the inner and outer sheaths, so even if the outer sheath is damaged water cannot ingress to the electrical connections.

The Goodwin pump uses high quality brass end rings and bars in the rotor that are brazed together. Brazed brass construction is proven as being more robust and reliable than die cast alternatives when the pumps are subjected to high energy Direct On Line (DOL) starts.

The Goodwin pump motor runs submerged in oil that lubricates and cools the bearings and the mechanical seal. The oil dissipates heat from the hottest part of the motor to the high mass stator housing that acts as a heat sink, eliminating motor hot spots which can give premature motor winding failure.

The Goodwin pump benefits from forced convection cooling by nature of the pumped fluid passing around the motor housing before it leaves the pump. This allows the pump to run for extended periods of time even if it is run semi-submerged. This is an integral part of the design and makes the requirement of additional motor cooling unnecessary.

To balance the load on the pump shaft, bearings and mechanical seal, Goodwin use a twin volute casing, reducing vibration and extending the life of all component parts especially the mechanical seal.

Removable Discharge ElbowThe 150 and 200mm Goodwin Pumps are supplied with a removable and replaceable discharge elbow made from precipitation hardened Stainless Steel.

Non-Pressurised Mechanical SealSuitable for submergence depth up to 28 metres as standard. The Goodwin mechanical seal is only subjected to the pressure from the submergence depth of the pump which generally is only a few metres of head and not the discharge pressure of the product. This greatly reduces the chance of fluid ingress into the motor itself and the destructive consequences which can result. The seal is positioned directly below the lower bearing to give it maximum support and protection from vibration.

The wet end of all Goodwin slurry pumps are made of NiHard alloy. For very abrasive applications Goodwin can offer tungsten carbide coated impellers, inducers and wear plates as it is possible to coat 100% of the rotating surface exposed to the slurry and thus provide the customer with excellent component life. Closed vane impeller designs have surfaces which can’t be tungsten carbide coated. 150 and 200 size slurry pumps have tungsten carbide coated wet end parts as standard. For 100 size pumps, coating is optional.

This feature assists the breakdown of large particles in the impeller that might ultimately lead to a blocked pump. There is little if any chance of the impeller becoming blocked as opposed to closed vane impellers which are often blocked and tend to stay blocked.

To reduce the bending moment on the shaft, when it comes into contact with large particles, the Goodwin inducer is kept as close as possible to the lower bearing.

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Goodwin submersible slurry pumps are a great choice for drying, slurry pumping like a water pump, is allows for water volume to flow through. The water circulates the liquids into the liquids pool, and allows liquids to evaporate faster.@@@@@

Goodwin slurry pumps are water efficient, and they don"t require water because all the components of the water are similar to their pumps, they are water-efficient, and has a wide volume of flow. It also has a low water consumption, and long service life. They also have a great water quality, low maintenance, and long-term life.

Created specifically for drilling equipment inspectors and others in the oil and gas industry, the Oil Rig Mud Pump Inspection app allows you to easily document the status and safety of your oil rigs using just a mobile device. Quickly resolve any damage or needed maintenance with photos and GPS locations and sync to the cloud for easy access. The app is completely customizable to fit your inspection needs and works even without an internet signal.Try Template

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.

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"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.

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.

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.

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. 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;

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

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.

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.

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 covet 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 collar 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 collar 32. An extendable hydraulic/electrical connector 52 is used to connect the collar 32 to the testing tool 31 (see FIG. 2) and another extendable hydraulic/electrical connector 59 is used to connect the collar 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 touted 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.

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.

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 aand 87 b. In 87 aa 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 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.

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 late 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 Pmaxmay be determined from a free spin angular velocity ωFSand 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 Pmaxfor limiting pumping operation. Assuming the mud flow rate stays constant, the power curve may be used to correlate a angular velocity ωOPto any operational power POP.

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 POPis compared to the maximum power Pmax. 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 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 ais 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.

Furthermore, part 92 amay 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 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 bin 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 Qactcan be computed from the motor position information and a system transmission constant. The motor torque actual value τactcan 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 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 τsetfrom the difference between the pump rate set value Qsetand the calculated pump rate actual value Qact. 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 Qsetwith the calculated pump rate actual value Qact.

Finally, FIGS. 7 and 8 illustrate an alternative motor FDU arrangement 41 a. The motor 41 ais a Moineau motor which is coupled to a gearbox or other mechanical transmission 48 a. The gearbox 48 ais driven by a turbine 37 awhich, 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 adoes not include an alternator. Fluid flow to the turbine 37 ais 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.

The mud check-valves is shown at 61 aand a flowmeter at the outlet to the borehole is shown at 124. Sample fluid is communicated from the pump 41 athrough a valve 53 a, which in this case is another solenoid valve similar to that shown at 122. The flowline 75 aleads to the sample chambers indicated schematically by the arrow 62 a-64 a. The probe inlet is shown at 31 awith a rubber packer 124. A sensor (not shown in would also be included that monitors properties such as optical densities, fluorescence, resistance, pressure and temperature of the fluid drawn into the tool.

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.

Historically, the fluid samples were brought to the surface for analysis in a laboratory, but recent developments have facilitated directly measuring fluid properties downhole during a pumping or sampling sequence using downhole fluid analysis (DFA) techniques. In contrast to laboratory analyses or surface wellsite analyses, which may require a relatively extended amount of time to produce results and may result in undesirable phase transitions as well as the loss of key constituents in samples, DFA techniques may be used to perform fluid analysis in situ and to provide analysis results in real-time.

To draw a fluid (e.g., a formation fluid from the subterranean formation F or a wellbore fluid from the wellbore W) through a sample flowline 210, the downhole tool 200 is provided with a pump 208. In particular, the pump 208 draws fluid through the flowline 210, an ionizer 218, and a fluid measurement unit 220. In other example implementations, the ionizer, 218 and/or the fluid measurement 220 may be positioned along a bypass line (not shown). In the illustrated example, the ionizer 218 is implemented in connection with a depressurizing device 214 and a sensor 219, as described below in connection with FIGS. 2A and 2B. However, in other example implementations, the depressurizing device 214, the ionizer 218, and the sensor 219 may be in a serial arrangement connected by a flowline. To store or discard formation fluid samples, the pump 208 moves the fluid away from the flow line 210 to a valve 222, which has a first selectable outlet 224 that is fluidly coupled to a fluid store 226 and a second selectable outlet 228 that expels fluid out of the downhole tool 200 into the wellbore W for example.

The fluid measurement unit 220 may be used to determine properties of a fluid sample. The fluid measurement unit 220 may be provided with one or more other types of suitable sensors, for example, a nuclear magnetic resonance (NMR) sensor, a density sensor, a capacitance sensor, a viscosity sensor, a volumetric flowrate sensor, a resistivity measurement unit (an ohmmeter), an optical spectrometer, etc . . . to measure fluid characteristics (e.g. composition data). The properties measured with the fluid measurement unit 220 may be used for example to monitor formation fluid sample contamination by mud filtrate and to determine when the extract formation fluid has a sufficiently low contamination level for the depressurizing device 214, the ionizer 218 and the sensor 219 to be activated. Further, the properties measured with the fluid measurement unit 220 may also be used to determine the type of fluid being sampled. The fluid type data (e.g. composition data) can be used in conjunction with data provided by the sensor 219 to determine concentration levels of one or more analyte(s) in the fluid sample.

To convert at least a portion of the downhole fluid samples from a liquid state to a gaseous state and/or to decrease the pressure or density of an extracted formation fluid, the downhole tool 200 is provided with a depressurizing device 214. When formation fluid is drawn from the formation F or the wellbore W, it is typically in a liquid state having a relatively large density. The probability of ionizing a sample and the ionizing products not immediately reforming to the same molecule may be reduced in proportion to the sample density. Thus, the power required to ionize a high density fluid sample (e.g., a liquid) is usually relatively higher than the power required to ionize a low density sample (e.g., a gas). Due to the limited availability of power in a downhole tool, the depressurizing device 214 can be advantageously used to convert at least a portion of the downhole fluid samples into a gaseous phase to facilitate ionizing the fluid using relatively less electrical power. Alternatively, the depressurizing device 214 can be advantageously used to decrease the density of a formation fluid sample already in a gaseous state to facilitate ionizing the fluid using relatively less electrical power. For example, the depressurizing device 214 can depressurize the fluid sample or a portion thereof to induce phase separation. Alternatively, the fluid may be depressurized using the pump 208 by closing a valve (for example the valve 1008 in FIGS. 2A and 2B) on the flowline 210 and reducing the pressure in an isolated portion of the flow line 210.

To control or collect data from the hydraulic system 202, the pump 208, the depressurizing device 214, the ionizer 218, the sensor 219, the fluid measurement unit 220, and the valve 222, the downhole tool 200 is provided with a downhole control and data acquisition system 230. Although not shown, the downhole control and data acquisition system 230 may include a processor, one or more memories, and a communication interface (e.g., a modem). The communication interface of the downhole control and data acquisition system 230 may be communicatively coupled to a surface system to communicate analysis data and/or receive control data. The wires or lines 232 may include a databus (e.g., carrying digital information and/or analog information), electrical power lines, etc. and may be implemented using a single conductor or multiple conductors.

In operation, the piston 1012 is initially in the non-depressurized position 1019 and the first valve 1008 and the second valve 1010 are in an open position. A sample of the downhole fluid flows through the flowline 1002 under the action of a pump (e.g. the pump 208 of FIG. 1). When sufficient clean or representative fluid is captured in the flowline 1002 between the first and second valves 1008 and 1010 (as determined for example using measurements performed with the fluid measurement unit 220 of FIG. 1), the first valve 1008 and the second valve 1010 are actuated to a closed position. Thus, as the fluid at relatively high pressure is captured between the first valve 1008, the second valve 1010 and the piston 1012.

After the sample is ionized and/or measurements are obtained from the sample, the piston 1012 is moved back to the non-depressurized position 1019, the first valve 1008 and the second valve 1010 are opened, and the sample flows through the flowline 1002 under the action of the pump 208 (FIG. 1) for example.

FIG. 3 is a flow diagram depicting an example method 500 that may be used to draw and analyze formation fluid samples using, for example, the downhole tool 200 of FIG. 1. Initially, the sampling probe 204 (FIG. 1) extracts (e.g., admits, draws, etc.) downhole fluid, for example from the formation F or the wellbore W (block 502). In the cases the downhole fluid is extracted from the formation, the fluid measurement unit 220 (FIG. 1) may be used to determine a fluid property as the downhole fluid is drawn into the downhole tool 200. The value of the property is monitored while pumping and a contamination level of the fluid extracted from the formation by mud filtrate is determined using methods known in the art. When the contamination level is deemed sufficiently low to have a downhole fluid representative of the connate formation fluid in the ionizer 218, fluid extraction may stop. Regardless the type of downhole fluid (formation fluid or wellbore fluid) the ionizer 218 (FIG. 1) then obtains a formation fluid sample for measurement (block 504).

In the illustrated example implementation, the wellsite system further includes drilling fluid or mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers the drilling fluid 26 to the interior of the drill string 12 via a port in the rotary swivel 19, causing the drilling fluid 26 to flow downwardly through the drill string 12 as indicated by a directional arrow 8. The drilling fluid 26 exits the drill string 12 via ports in the drill bit 40, and then circulates upwardly through the annulus region between the outside of the drill string 12 and the wall of the borehole 11, as indicated by directional arrows 9. In this well-known manner, the drilling fluid 26 lubricates the drill bit 40 and carries formation cuttings to the surface as it is returned to the pit 27 for recirculation.

The MWD module 34 is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string 12 and the drill bit 40. The MWD module 34 further includes an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid 26, it being understood that other power and/or battery systems may be employed. In the illustrated example implementation, the MWD module 34 includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device. The MWD module 34 also includes capabilities for processing, and storing information signals from the LWD module 32 and 36, as well as for communicating with the surface equipment.

The probe 152 is configured to selectively seal off or isolate selected portions of the wall of the wellbore 160 to fluidly couple to the adjacent formation F and draw fluid samples from the formation F into the LWD tool 150 in a direction generally indicated by arrows 156, for example by using a pump 175 (for example similar to the pump 208 of FIG. 1). Once the probe 152 fluidly couple to the adjacent formation F, various measurements may be conducted on the sample such as, for example, a pretest parameter or a pressure parameter may be measured. The LWD module 36 also includes a fluid analysis module 170 through which the obtained fluid samples flow. The fluid may thereafter be expelled through a port (not shown) or it may be sent to one or more fluid collecting chambers (not shown), which may receive and retain the formation fluid for subsequent testing at the surface or a testing facility. In the illustrated example, a downhole control system 180 is configured to control the operations of the LWD module 36 to draw fluid samples from the formation F and to control the fluid analysis module 170 to measure the fluid samples. The fluid analysis module 170 may be configured to generate the measurement data as described therein, and in particular in connection with the sensor 219 and optionally the fluid measurement unit 220 of FIG. 1. In some example implementations, the downhole control system 180 may be configured to analyze the measurement data of the fluid samples as described herein. The downhole control system 180 capabilities for processing, and storing information, in particular for subsequent retrieval at the surface and/or for real time communication with the surface equipment.

The wireline tool 100 also includes a formation tester 114 having a selectively extendable fluid admitting assembly 116 and a selectively extendable tool anchoring member 118 that are respectively arranged on opposite sides of the body 108. The fluid admitting assembly 116 is configured to selectively seal off or isolate selected portions of the wall of the wellbore 102 to fluidly couple to the adjacent formation F and draw fluid samples from the formation F using for example a pump 121 (for example similar to the pump 208 of FIG. 1). The formation tester 114 also includes a fluid analysis module 120 through which the obtained fluid samples flow. The fluid may thereafter be expelled through a port (not shown) or it may be sent to one or more fluid collecting chambers 122 and 124 (for example similar to the fluid store 226 of FIG. 1), which may receive and retain the formation fluid for subsequent testing at the surface or a testing facility. In the illustrated example, the electrical control and data acquisition system 106 and/or the downhole control system 112 are configured to control the fluid admitting assembly 116 to draw fluid samples from the formation F and to control the fluid analysis module 120 to measure the fluid samples. The fluid analysis module 120 may be configured to generate the measurement data as described therein, and in particular in connection with the sensor 219 and optionally the fluid measurement unit 220 of FIG. 1. In some example implementations, the downhole control system 112 may be configured to analyze the measurement data of the fluid samples as described herein, for example in connection with the downhole control and data acquisition 230 of FIG. 1. In other example implementations, the fluid analysis module 120 may be configured to generate the measurement data and subsequently communicate the measurement data to the surface for subsequent analysis at the surface via the downhole control system 112. In this case, the electrical control and data acquisition system 106 may be configured to analyze the measurement data of the fluid samples as described herein. Although the downhole control system 112 is shown as being implemented separate from the formation tester 114, in some example implementations, the downhole control system 112 may be implemented in the formation tester 114.

The 2,200-hp mud pump for offshore applications is a single-acting reciprocating triplex mud pump designed for high fluid flow rates, even at low operating speeds, and with a long stroke design. These features reduce the number of load reversals in critical components and increase the life of fluid end parts.

The pump’s critical components are strategically placed to make maintenance and inspection far easier and safer. The two-piece, quick-release piston rod lets you remove the piston without disturbing the liner, minimizing downtime when you’re replacing fluid parts.