mud pump controls free sample

I’ve run into several instances of insufficient suction stabilization on rigs where a “standpipe” is installed off the suction manifold. The thought behind this design was to create a gas-over-fluid column for the reciprocating pump and eliminate cavitation.

When the standpipe is installed on the suction manifold’s deadhead side, there’s little opportunity to get fluid into all the cylinders to prevent cavitation. Also, the reciprocating pump and charge pump are not isolated.

The suction stabilizer’s compressible feature is designed to absorb the negative energies and promote smooth fluid flow. As a result, pump isolation is achieved between the charge pump and the reciprocating pump.

The isolation eliminates pump chatter, and because the reciprocating pump’s negative energies never reach the charge pump, the pump’s expendable life is extended.

Investing in suction stabilizers will ensure your pumps operate consistently and efficiently. They can also prevent most challenges related to pressure surges or pulsations in the most difficult piping environments.

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.

Centerline Manu-facturing introduces the CLM 7.5 x 10D hydraulic mud pump, a pump which utilizes common fluid end parts. Its advantages are said to be its flow capacity, rated pressure, size and weight. It is designed to pump 100 percent more rated flow than a standard 5x6 and up to 3.25 times the rated pressure. However, it only has a third of the weight and 77 percent of the length.

Cavitation is an undesirable condition that reduces pump efficiency and leads to excessive wear and damage to pump components. Factors that can contribute to cavitation, such as fluid velocity and pressure, can sometimes be attributed to an inadequate mud system design and/or the diminishing performance of the mud pump’s feed system.

When a mud pump has entered full cavitation, rig crews and field service technicians will see the equipment shaking and hear the pump “knocking,” which typically sounds like marbles and stones being thrown around inside the equipment. However, the process of cavitation starts long before audible signs reveal themselves – hence the name “the silent killer.”

Mild cavitation begins to occur when the mud pump is starved for fluid. While the pump itself may not be making noise, damage is still being done to the internal components of the fluid end. In the early stages, cavitation can damage a pump’s module, piston and valve assembly.

The imperceptible but intense shock waves generated by cavitation travel directly from the fluid end to the pump’s power end, causing premature vibrational damage to the crosshead slides. The vibrations are then passed onto the shaft, bull gear and into the main bearings.

If not corrected, the vibrations caused by cavitation will work their way directly to critical power end components, which will result in the premature failure of the mud pump. A busted mud pump means expensive downtime and repair costs.

To stop cavitation before it starts, install and tune high-speed pressure sensors on the mud suction line set to sound an alarm if the pressure falls below 30 psi.

Although the pump may not be knocking loudly when cavitation first presents, regular inspections by a properly trained field technician may be able to detect moderate vibrations and slight knocking sounds.

Gardner Denver offers Pump University, a mobile classroom that travels to facilities and/or drilling rigs and trains rig crews on best practices for pumping equipment maintenance.

Severe cavitation will drastically decrease module life and will eventually lead to catastrophic pump failure. Along with downtime and repair costs, the failure of the drilling pump can also cause damage to the suction and discharge piping.

When a mud pump has entered full cavitation, rig crews and field service technicians will see the equipment shaking and hear the pump ‘knocking’… However, the process of cavitation starts long before audible signs reveal themselves – hence the name ‘the silent killer.’In 2017, a leading North American drilling contractor was encountering chronic mud system issues on multiple rigs. The contractor engaged in more than 25 premature module washes in one year and suffered a major power-end failure.

Gardner Denver’s engineering team spent time on the contractor’s rigs, observing the pumps during operation and surveying the mud system’s design and configuration.

The engineering team discovered that the suction systems were undersized, feed lines were too small and there was no dampening on the suction side of the pump.

Following the implementation of these recommendations, the contractor saw significant performance improvements from the drilling pumps. Consumables life was extended significantly, and module washes were reduced by nearly 85%.

Although pump age does not affect its susceptibility to cavitation, the age of the rig can. An older rig’s mud systems may not be equipped for the way pumps are run today – at maximum horsepower.

Heating, Ventilation and Air Conditioning Landlord shall furnish to the Premises heating, ventilation and air-conditioning (“HVAC”) in accordance with the Design Standards set forth in Exhibit D during Ordinary Business Hours. Landlord shall have access to all air-cooling, fan, ventilating and machine rooms and electrical closets and all other mechanical installations of Landlord (collectively, “Mechanical Installations”), and Tenant shall not construct partitions or other obstructions which may interfere with Landlord’s access thereto or the moving of Landlord’s equipment to and from the Mechanical Installations. No Tenant Party shall at any time enter the Mechanical Installations or tamper with, adjust, or otherwise affect such Mechanical Installations. Landlord shall not be responsible if the HVAC System fails to provide cooled or heated air, as the case may be, to the Premises in accordance with the Design Standards by reason of (i) any equipment installed by, for or on behalf of Tenant, which has an electrical load in excess of the average electrical load and human occupancy factors for the HVAC System as designed, or (ii) any rearrangement of partitioning or other Alterations made or performed by, for or on behalf of Tenant. Tenant shall install, if missing, blinds or shades on all windows, which blinds and shades shall be subject to Landlord’s approval, and shall keep operable windows in the Premises closed, and lower the blinds when necessary because of the sun’s position, whenever the HVAC System is in operation or as and when required by any Requirement. Tenant shall cooperate with Landlord and shall abide by the rules and regulations which Landlord may reasonably prescribe for the proper functioning and protection of the HVAC System. Tenant acknowledges that the server room in the Premises currently has three heat pumps installed, being two 4-ton units, and one 2.5-ton unit (the “Existing Heat Pumps”). The 2.5-ton unit is currently connected and operational. Tenant shall determine whether it is satisfied with the condition of the Existing Heat Pumps and Landlord shall not have any responsibility or liability for the condition, operation, maintenance, repair or replacement of the Existing Heat Pumps. Tenant may operate the Existing Heat Pumps. Tenant shall be responsible for, and pay directly for, all necessary maintenance and repairs to the Existing Heat Pumps. Tenant shall reimburse Landlord monthly for the cost of all utility services used to operate the Existing Heat Pumps within 10 Business Days after receipt of Landlord’s invoice for such amount. Landlord may measure Tenant’s usage of such utility services by either a sub-meter or by other reasonable methods such as by temporary check meters or by survey. Tenant, at its cost, may replace the Existing Heat Pumps with one or more new heat pumps, provided, however, that the capacity of such replacement heat pump(s) shall not exceed the 10.5-ton capacity cooling capacity of the Existing Heat Pumps.

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.

The present disclosure relates to a drilling mud management system and method. The system and method have application in the field of ground drilling where drilling mud is used or required for various purposes including not limited to downhole pressure control, hole stabilisation, lubrication, flushing of drill cuttings and downhole temperature control.

Drilling muds are used extensively in ground drilling particularly for oil and gas exploration. The composition of the drilling mud is critical to particularly, though only, controlling the pressure conditions of the hole. For example, the composition of the drilling mud can be varied to provide an under pressure or overpressure condition as required in the hole; as well as to kill a well.

In order to ensure the correct drilling mud composition it is common for a specialist mud engineer to be on-site 24 hours a day to monitor downhole conditions and ensure the drilling mud composition is as required to achieve a desired effect. Due to the margins involved in oil and gas industry the cost of the specialist mud engineers can be readily absorbed and amortised. However, this is not the case for mineral exploration which may be typically conducted using a land-based mobile drill rig operating in regional/outback areas with two operators. While drilling mud is still critical for efficient mineral exploration drilling the risk of catastrophic events due to lack of control of downhole pressure conditions is substantially lower than for oil and gas exploration. For this and other reasons the cost of having a specialist mud engineer on-site 24 hours a day cannot usually be not justified for mineral

To address the lack of on-site drilling mud expertise it is a regular practice in the mineral exploration industry to provide the ingredients for the drilling mud and mixing instructions to the drill rig operators. There is an expectation that the drill rig operators will follow the instructions to provide a supply of drilling mud to meet predicted ground conditions. However, there is no substantive quality control and no ability to modify the drilling mud composition in the event that downhole conditions are not in line with predictions.

a portable mud measurement system having: one or more measurement devices arranged to measure at least one property and/or characteristic of drilling mud; and a pumping system arranged to pump a batch sample of drilling mud from a supply of drilling mud to the one or more measurement devices and subsequently flush the batch sample of drilling mud from the one or more measurement devices; and a communications system enabling bidirectional communications between the mud management system and a remote location to enable transfer of data therebetween and the exertion of control from the remote location to the mud management system.

In one embodiment the automated drilling mud management comprises a dosing system arranged upon instruction from: the mud measurement system; or the communications system; to automatically dose the drilling mud supply with one or more drilling mud ingredients on a basis of minimising differences between the measured at least one property or characteristic of the mud and a desired

In one embodiment the automated drilling mud management comprises an interface to enable a local operator to enter data relating to a manual additional of one or more ingredients to the drilling mud supply and wherein the communications system is arranged to communicate the entered data to the remote location.

In one embodiment the mud measurement system is arranged to automatically issue a notification at least one property or characteristic of the mud falls outside the desired specification.

In one embodiment the mud management system is arranged to provide feedback control in association with the dosing system and the mud measurement system to perform a test cycle on the mud after operation of the dosing system and cause subsequent operations of the dosing system and the mud management system

In one embodiment the automated drilling mud management comprises a supply of one or more components or ingredients for making drilling mud operatively associated with the dosing system.

In one embodiment the automated drilling mud management comprises a supply of a flushing fluid for delivery by the pumping system to the one or more measurement devices.

In one embodiment the pumping system is arranged to circulate mud from an external mud supply through a hose and back to the mud supply through a return pipe prior to delivering a batch sample of mud to the one or more measurement devices.

In one embodiment the pumping system is arranged to maintain a volume of the flushing fluid in contact with the one or more measurement devices after a

In one embodiment the pumping comprises a mud pump and a separate flushing fluid pump; wherein the pumping system is arranged to: run the flushing fluid pump to introduce a flushing fluid into the one or more measurement devices; and subsequently operate the mud pump to empty the flushing fluid from the one or more measurement devices.

In one embodiment the mud pump is reversible to enable the mud pump to pump the mud sample or the flushing fluid from the one or more measurement devices to the mud supply.

In one embodiment the pumping system comprises valve connected between the mud pump, the return pipe and the one or more measurement devices, the valve having: a recycling state where the valve directs mud from the pump to flow only to the return pipe; and a flow-through state where the valve allows mud to flow from the pump to the at least one more measurement devices and blocks flow of mud to the return pipe.

In one embodiment the automated drilling mud management comprises a single reversible pump having first and second ports and a first three-way valve connected

between the first port, the supply of drilling mud and the one or more measurement devices; and a second three-way valve connected between the second port of the pump, the supply of drilling mud and the supply of flushing fluid. In one embodiment the automated drilling mud management comprises a filtrate measurement system arranged to measure fluid loss of the drilling mud;

In one embodiment the mobile unit further carries one or more of: the dosing system; the supply of one or more components or ingredients for making drilling mud; the supply of flushing fluid; and the filtrate system. In a second aspect there is disclosed a drilling mud management system comprising: a portable housing;

one or more measurement devices are arranged to measure at least one property or characteristic of drilling mud, the one or more measurement devices being located within the housing;

a pumping system located within the housing and arranged to pump a sample of mud to the one or more measurement devices and subsequent pump the sample from the housing.

one or more measurement devices that are arranged to measure at least one property or characteristic of drilling mud, the one or more measurement devices being located within the housing; and

a pumping system located within the housing and arranged to pump a sample of mud to the one or more measurement devices and subsequent pump the sample from the housing the pumping system having a mud pump and a separate flushing fluid pump;

wherein the pumping system is arranged to: run the flushing fluid pump to introduce a flushing fluid into the housing and the one or more measurement devices; and subsequently operate the mud pump to empty the flushing fluid from the one or more measurement devices.

one or more measurement devices arranged to measure at least one property and/or characteristic of drilling mud wherein one of the properties measured is viscosity; and

a pumping system located within the housing and arranged to pump a sample of mud to the one or more measurement devices and subsequent pump the sample from the housing, the pumping system arranged to pump a sample volume of drilling mud no more than 1 L to the one or more measurement devices.

a pumping system located within the housing, the pumping system arranged to pump a sample of drilling mud to the one or more measurement devices and subsequently flush the sample of drilling mud from the housing. In some embodiments of some the above aspects the pumping system is arranged to maintain a volume of the flushing fluid in contact with the one or more

In some embodiments of some the above aspects the mud pump is arranged to pump the sample of mud from an external mud supply through a hose to enable all of the properties and/or characteristics to be measured. In embodiments of the above aspects the mud pump is reversible to enable the mud pump to pump the mud sample from the housing to the mud supply.

In one embodiment of the above aspects the pumping system comprises a return pipe capable of receiving mud from the mud pump pumped in a forward direction to enable a recirculating flow of mud from the supply through the hose and mud pump and back to the supply. In this embodiment the pumping system comprises valve connected between the mud pump, the return pipe and the one or more

measurement devices, the valve having: a recycling state where the valve directs mud from the pump to flow only to the return pipe; and a flow-through state where the valve allows mud to flow from the pump to the at least one more measurement devices and blocks flow of mud to the return pipe. Also, in this embodiment the flush fluid pump may be arranged to introduce flushing fluid into the housing at a location downstream of where the return pipe receives mud from the mud pump operated in the forward direction, and upstream of the one or more measurement devices.

In one embodiment of the above aspects the pumping system may be arranged to operate in a flushing cycle in which the flushing fluid pump pumps flushing fluid into the housing and the drilling mud pump is operated in a reverse direction wherein the

In some embodiments the drilling mud measurement system comprises a mud density measurement system having at least two fluid pressure transducers the pressure transducers arranged to be suspended at a known vertical separation from each other in a volume of the drilling mud.

In one embodiment the drilling mud measurement system comprises a float arranged to suspend the at least two fluid pressure transducers above a bottom of a container or other receptacle or reservoir holding the volume of drilling mud.

In one embodiment the drilling mud measurement system is arranged to provide real time or near real-time information from the one or more measurement devices to an in-situ user of the drilling mud management system.

In one embodiment the drilling mud measurement system comprises an electronic data collection system arranged to automatically collect measurement data from the one or more measurement devices.

In one embodiment the drilling mud measurement system is arranged to make an in situ comparison between the measurement data and reference data relating to properties and/or characteristics of the drilling mud and provide, to a user of the drilling mud measurement system, information indicative of (a) the properties and/or characteristics of the drilling mud; and/or (b) one or more differences between the measurement data and reference data.

In one embodiment the drilling mud measurement system comprises one or both of (a) an internal memory device capable of storing the reference data; and (b) a provision for receiving the reference data from an external source.

In one embodiment the drilling mud measurement system comprises a data communication system arranged to electronically transmit the measurement data to a remote location.

In one embodiment the drilling mud measurement system is arranged for operable association with a dosing system wherein the dosing system is arranged upon instruction from the drilling measurement system to dose the drilling mud supply with one or more drilling mud ingredients on a basis of minimising differences between the measurement data and the reference data.

In one embodiment the drilling mud measurement system comprises an audit system arranged to automatically issue a notification when a quantity of a drilling mud ingredient in a supply of one or more drilling mud ingredients falls below a threshold level.

In one embodiment the drilling mud measurement system comprises a filtrate measurement system arranged to measure loss of a fluid component of the drilling mud.

In one embodiment the drilling mud measurement system comprises a dosing system arranged upon instruction from the drilling measurement system to dose a drilling mud supply with one or more drilling mud ingredients on a basis of minimising

In one embodiment the drilling mud measurement system comprises an electronic controller enabled to automatically control the one or more measurement devices and the pumping system.

In one embodiment the drilling mud measurement system comprises one or both of a local user interface and remote user interface for inputting instructions for execution by the controller to automatically control the one or more measurement devices and the pumping system

In one embodiment the drilling mud measurement system comprises a power module arranged to connect with and provide power to one or more of the: one or more measurement devices; the pumping system; the filtrate measurement system; and the dosing system.

Figure 1 is a schematic representation of an embodiment of the disclosed drilling mud management system and which may be used to perform the disclosed method;

Figure 2A is a schematic representation of a drill mud measurement system which may constitute or form part of a first embodiment of the drilling mud management system shown in Figure 1 ;

Figure 2B is a schematic representation of a drill mud measurement system which may constitute or form part of a second embodiment of the drilling mud management system shown in Figure 1 ;

Figure 2C is a schematic representation of a drill mud measurement system which may constitute or form part of a third embodiment of the disclosed drilling mud management system shown in Figure 1 ;

Figure 4 schematic representation of a filtrate management system which may be incorporated in either the drilling mud management system shown in Figure 1 or the drill mud measurement system shown in either Figure 2A or Figure 2B.

Figure 1 is a schematic layout of an embodiment of the disclosed drilling mud management system 1 (hereinafter referred to as the "system 1 "). The system 1 includes at least a mud measurement system 10 which is arranged to measure at least one property and/or characteristic of the drilling mud (also known as "drilling fluid"). Additional subsystems or modules of the system 1 include: a filtrate measurement system 70; a mud dosing and mixing system 1 10; a communications module 120; a power module 130; and a portable "smart" device 140. Each of the modules and subsystems 10, 70, 1 10, 120, 130 and 140 is a stand-alone item with plug and play connectivity to provide corresponding functionality to the system 1 . The hub 150 shown in Figure 1 is not a part of the system 1 , but rather is a remote data collection and storage facility with which the system, 1 is able to

As explained in the following description the system 1 provides a portable and in substance complete and automated mud management system for drilling without the need for an on-site mud engineer. The management provided by the system 1 includes measurement and diagnostics of the mud, the ability to automatically vary the mud composition, conduct audits of mud characteristics compared with ratios of components used in mixing the mud, and just-in-time ordering and delivery of mud components to site. The mud management system 1 is automated to the extent that once it has been set up it is able to function automatically to perform a measurement of the characteristics of the mud, the filtrate, and operator otherwise control the mud dosing and mixing system 1 10. The system can be activated to perform its automates functions either locally by for example a drill operator, or remotely using the comm