System and method for calculating mud density

Abstract

Drilling mud is passed through a valve assembly set at a particular opening amount, mud flow rate and force applied by the drilling mud to a portion of the valve assembly are measured, and density of the drilling mud is estimated based on historical data. Historical data is generated by directing multiple flows through the valve assembly, where the flows are at different flow rates, and at each flow rate, different drilling fluids having different densities are directed through the valve assembly. For each flow, the valve assembly is adjusted to a different amount of opening, and a respective force exerted on the valve assembly by the flow is measured. An example of the valve assembly is a mud pulse generator having a plug member engaged with an orifice opening, a sensor in the pulse generator measuring a force applied by the mud flow.

Description

[0001] This application claims priority and interest in co-pending U.S. non-provisional application serial number No. 18 / 771,399, filed July 12, 2024, and U.S. provisional application serial number No. 63 / 513,785, filed July 14, 2023. Background Technology 1. Technical Field

[0003] This disclosure relates to a mud pulse system, and more specifically to estimating mud density based on the monitoring characteristics of the mud pulse system.

[0004] 2. Description of the prior art

[0005] Drilling systems with a drilling bit at the end of the drill string are commonly used in the oil and gas industry to create wells that penetrate hydrocarbon-bearing geological formations. Drilling mud is typically injected into the drill string during drilling. The drilling mud exits the drill string through nozzles formed in the drill bit and flows back to the surface in the annular gap between the drill string and the wellbore wall. Drilling mud serves a variety of purposes, such as preventing uncontrolled fluid flow from the formation to the surface through the hydrostatic head of the drilling mud string in the well. As the drilling mud exits the nozzles, it also cools the drill bit and removes formation cuttings generated during drilling from the bottom of the well.

[0006] Drilling mud also provides a medium for transmitting signals, typically in the form of pressure pulses, to convey downhole monitoring information such as pressure, temperature, formation resistivity, formation density, and tool location. These pressure pulses are usually generated by a mud pulse generator installed in the drill string, which measures the fluid in discrete sequences and durations. The pressure pulses are monitored by sensors on the surface and then decoded to identify underlying information. Summary of the Invention

[0007] An example of a downhole valve assembly for use in a wellbore to determine fluid density is disclosed. The downhole valve assembly includes: a housing; a flow restrictor having an opening; fluid flowing through the valve assembly and through the opening of the flow restrictor; a plug member configured to at least partially block the opening of the flow restrictor; an actuator configured to drive the plug member relative to the flow restrictor to select a flow restriction region; a flow meter for measuring the flow velocity of the fluid flowing through the valve assembly; and a measuring device located in or on the valve assembly, configured to measure parameters related to the forces acting on at least one of the flow restrictor and the plug member due to the fluid flowing through the valve assembly. In this example, the valve assembly includes a processor configured to position the plug member at a selected location corresponding to the selected flow restriction region, and configured to, when the plug member is at the location corresponding to the selected flow restriction region, obtain measurement data from the measuring device using the actuator, and use the obtained measurement data and the measured flow velocity to determine the fluid density. In one example, the measuring device is a force sensor configured to measure the force acting on at least one of the flow restrictor and the plug member, and the measurement data is force data. An actuator embodiment includes an electric motor, the measuring device being configured to measure parameters related to the electric power consumption of the motor, which is required for the motor to hold the plug member at a position corresponding to a selected flow restriction area, and the measurement data is one of electric power consumption data and motor current data; optionally, the processor is configured to oscillate the plug member about a position corresponding to the selected flow restriction area, and determining the fluid density includes calculating the average of the electric power consumption data and the motor current data. In one example, the valve assembly includes a piston and a motorized connection. In one embodiment, the valve assembly is a shear valve, the flow restrictor is a stator including at least one opening, and the plug member is a rotor disk including at least one blade. Examples of selected locations include a first selected location corresponding to a first selected flow restriction region and a second selected location corresponding to a second selected flow restriction region, and the measurement data includes first measurement data and second measurement data. The processor is configured to position the plug member at the first selected location and at the second selected location, and to acquire first measurement data from a measuring device when the plug member is at the first selected location, and to acquire second measurement data from the measuring device when the plug member is at the second selected location, and to use the first and second measurement data to determine the fluid density. In an alternative example, the actuator includes a spindle, and the measuring device is a torque meter configured to measure the torque acting on the spindle, and the measurement data is torque data.In another alternative, the valve assembly is part of a downhole telemetry system, and the fluid is drilling mud. The valve assembly generates pressure pulses in the drilling mud within the wellbore, and the downhole telemetry system includes a pressure transducer at a surface location configured to detect these pressure pulses. The processor is optionally configured to use historical data to determine the fluid density, and in this alternative, the measuring device is located in or on an actuator.

[0008] A method for measuring fluid density in a wellbore is also disclosed, the method comprising guiding fluid flow through a valve assembly in the wellbore, wherein the valve assembly includes a housing, an actuator, a plug member, a processor, a measuring device, a flow meter, and a flow restrictor. The exemplary method further includes: defining a selected flow restriction area by positioning the plug member relative to an opening of the flow restrictor using the processor and the actuator; detecting the flow velocity of the fluid flow using the flow meter; measuring measurement data related to a force exerted by the fluid flow on at least one of the flow restrictor and the plug member using the measuring device; obtaining the measurement data from the measuring device using the processor; determining the fluid density using the processor and based on the measurement data and the detected flow velocity; and adjusting operating parameters based on the determined fluid density. In one example, the measuring device is a force sensor, and the measurement data is force data. Such embodiments exist, in which the actuator is an electric motor, and the measured data includes current data or power consumption data measured using a measuring device; alternatives to this embodiment include using a processor and actuator to oscillate the plug member around a position corresponding to a selected flow restriction region, and determining the fluid density includes calculating the average of at least one of the current data and the power consumption data. In one alternative, the valve assembly includes a piston and a motorized connection, or the valve assembly is a shear valve, and the flow restrictor is a stator, and the plug member is a rotor disk. In another example, the selected position includes a first selected position corresponding to a first flow restriction region and a second selected position corresponding to a second flow restriction region, and the measured data includes first and second measured data, positioning the plug member at the first selected position and positioning the plug member at the second selected position, obtaining the first measured data from the measuring device when the plug member is at the first selected position, and obtaining the second measured data from the measuring device when the plug member is at the second selected position, and determining the fluid density using the first and second measured data. In an alternative, the actuator includes a spindle, and the measuring device is a torque meter, and the method includes using the torque meter to measure the torque acting on the spindle. Determining fluid density may optionally include using historical data, which may be obtained in a laboratory, in a probing well, or through calculation. Alternatively, fluid density determination may be performed while the processor is in the wellbore and during downhole operations. Optionally, adjusting operating parameters may include one or more of the operating parameters of the regulating valve assembly and the drilling system. In another embodiment, the measuring device is located in or on the actuator. Attached Figure Description

[0009] Some features and beneficial effects of the present invention have already been stated, and other features and beneficial effects will become clear when described in conjunction with the accompanying drawings, wherein:

[0010] Figure 1This is a partial sectional side view of an example drilling system with valve assemblies.

[0011] Figure 2 yes Figure 1 A partial sectional side view of the valve assembly;

[0012] Figure 3 yes Figure 1 The exemplary force in the valve assembly is a graph relative to different set distances, and is used for drilling mud with different mud densities.

[0013] Figure 4 Is Figure 1 A graph showing the drilling mud density versus the measured force at a specific set distance in the valve assembly.

[0014] Figure 5 yes Figure 1 An exemplary pressure drop curve in a valve assembly versus different opening values, used for drilling mud with different flow rates.

[0015] Figure 6 yes Figure 1 The exemplary pressure drop in the valve assembly versus different set distances is plotted and used for drilling mud with different densities at a constant flow rate.

[0016] Figure 7 and Figure 8 yes Figure 1 A partial sectional side view of an alternative embodiment of the valve assembly.

[0017] Figure 9 and Figure 10 yes Figure 1 A partial sectional side view of an example of the operation of an alternative implementation of the valve assembly.

[0018] Figure 11 This is a graph showing the valve position versus motor current for an exemplary valve assembly used with drilling mud of different densities.

[0019] While the subject matter has been described in conjunction with the embodiments disclosed herein, it should be understood that the scope of this disclosure is not limited to any particular embodiment. Rather, it is intended to cover all its alternatives, modifications, and equivalents. Detailed Implementation

[0020] The methods and systems of this disclosure will now be described more fully below with reference to the accompanying drawings, which illustrate embodiments. The methods and systems of this disclosure may take many different forms and should not be construed as limited to the exemplary embodiments listed herein; rather, these embodiments are provided so that this disclosure will be comprehensive and complete, and will fully convey its scope to those skilled in the art. Similar figures throughout the specification denote similar elements. In one embodiment, the term “about” is used to include + / - 5% of the referenced value. In one embodiment, the term “substantially” includes + / - 5% of the referenced value, comparison, or description. In one embodiment, the term “approximately” includes + / - 10% of the referenced value.

[0021] It should be further understood that the scope of this disclosure is not limited to the exact details of the architecture, operation, specific materials, or embodiments shown and described, as modifications and equivalents will be clear to those skilled in the art. Exemplary embodiments have been disclosed in the drawings and specification, and although specific terminology has been used, they are used in a general and descriptive sense only, and not for limiting purposes.

[0022] An example of forming a wellbore 12 using drilling assembly 10 is shown in Figure 1 The diagram is shown in a partial side cross-sectional view, where the wellbore 12 extends from the surface 16 into the subsurface formation 14. Assembly 10 includes a drill string 18 composed of multiple end-to-end mating joints of drill pipe 20. A valve assembly 22 is integrally located within the drill string 18, selectively restricting the flow of drilling mud DM through the drill string 18 as described in more detail below, and alternatively operating as a mud pulse generator that produces mud pulses traveling to the surface. Figure 1In this process, drilling mud DM flows within the borehole 24 of drill string 18 to drill bit 26, which is connected to the lower end of drill string 18. Drilling mud DM exits drill bit 26 through a nozzle (not shown) at the lower end of drill bit 26 and flows back to the surface within an annular portion 28 between the sidewall of wellbore 12 and drill string 18. Drilling mud DM is supplied by mud sources 30, such as mud pits, suction tanks, and / or oscillating tanks, located outside wellbore 12 on surface 16. A pipeline connected to the outlet of mud source 30 supplies drilling mud DM to pump 32, which pressurizes the drilling mud DM. The pressurized drilling mud DM flows from pump 32 through pipeline to a connector on drill pipe 34, which is suspended within derrick 36, shown assembled above the opening of wellbore 12. The upper end of drill string 28 connects to the lower end of drill pipe 34. Below its connection with drill pipe 34, drill string 18 is inserted into wellhead assembly 38 mounted on top of the opening of wellbore 12. At the lower end of drill string 18 is a bottom hole assembly (“BHA”) 35, which in this example includes downhole components for drilling the borehole. Embodiments of BHA 35 include components for determining the downhole location of BHA 35 and drill bit 26 and for determining the properties of rock formation 14 surrounding wellbore 12, including detecting hydrocarbon-bearing rock formations. BHA 35 optionally includes a mud motor and / or steering unit (not shown) to control the trajectory of wellbore 12, and one or more of the following: formation assessment devices (FE devices), such as resistivity devices, nuclear resonance devices, acoustic devices, density devices, or formation sampling devices; measurement-while-drilling (MWD) devices configured to detect borehole inclination and azimuth; accelerometers; magnetometers; power sources, such as downhole generators or batteries; and telemetry devices that communicate with the surface. Examples of telemetry devices include mud pulse generators, electromagnetic telemetry devices, or acoustic telemetry devices. In alternative configurations, BHA 35 and drill string 18 include a line (not shown) (wire tube) to the surface. The term "upstream" in this application refers to a direction closer to the Earth's surface. The term "downstream" refers to a direction closer to the bottom end of drill string 18 in the borehole. The term "upstream" refers to a direction relative to the location where drilling mud DM is pumped into the borehole of the drill string. The upstream direction is closer to pump 32, which pumps drilling mud into the borehole of the drill string. The downstream direction is further away from pump 32.

[0023] Figure 2 This is a partial side sectional view of an example of valve assembly 22, which includes a housing 40, as shown, which is a tool collar that is annular and part of BHA 35. Valve assembly 22 includes an orifice or flow restrictor 42 mounted within the housing 40, the orifice or flow restrictor being a generally cylindrical member with a diameter exceeding its length. An opening 44 is formed axially through the orifice 42, as shown, and this opening is aligned with axis A of valve assembly 22. XThe components are generally coaxial, and the seal 45 surrounds the orifice 42. A plug member 46 is spaced axially downstream of the opening 44, and this plug member has a generally tapered or frustoconical surface facing the opening 44. Downstream of the plug member 46 is an actuator 48 for selectively repositioning the plug member 46 at different distances away from the opening 44; Figure 2 In the example, this distance is shown as a set distance D2, also referred to herein as a second set distance. The set distance D2 is the distance between the lower end of the orifice 42 and the upper end of the plug member 46. Alternatively, the set distance D2 is the axial distance (resting area) between the valve seat 49 in the orifice 42 and the position on the plug member 46 adjacent to the valve seat 49 when the valve is rested (closed position), or the distance the plug member 46 travels from position V2 to the resting position. An example of the valve resting or closed position is a plug member 46 inserted into the orifice 42 to substantially block the flow of drilling mud DM through the opening 44. When the plug member 46 is adjacent to the valve seat 49, the opening 44 is closed and no fluid flows through the opening 44. The valve stem 50 is shown having an end connected to the plug member 46 on the side opposite the opening 44 and an opposite end connected to the actuator 48. In the example, the actuator 48 is operated to displace the valve stem 50 and the plug member 46 to move the plug member 46 to a different set distance D1, also referred to herein as the first set distance and as shown in the dashed outline. The first set distance D1 is the distance between the valve seat 49 in the orifice 42 and the position on the plug member 46 adjacent to the valve seat when the valve is rested (valve closed position), or the distance the plug member 46 travels from position V1 to the rested position. In one embodiment, the percentage of opening of the valve assembly 22 depends on the position of the plug member 46 and defines the effect of the position of the plug member 46 on the flow of fluid through the valve assembly 22. In the example, when the plug member 46 is positioned to contact the opening 44 (the plug member contacts the valve seat 49) and blocks the flow of fluid (including any fluid, including drilling mud) through the valve assembly 22, the percentage opening of the valve assembly 22 is essentially 0% (fully closed), and when the plug member 46 is positioned away from the opening 44 and has no effect on the flow of fluid through the valve assembly, the percentage opening of the valve assembly 22 is essentially 100% (fully open). Between the fully closed and fully open positions, a pressure drop is generated through the valve assembly 22, which lies between the maximum pressure drop (fully closed position) and the minimum pressure drop (fully open position). In a non-limiting operational example where drilling mud flows in the drill string 18, the plug member 46 does not completely close the opening 44 and does not contact the valve seat 49. Furthermore, since the plug member does not contact the valve seat, there is an advantage in avoiding wear between the plug member 46 and the valve seat 49. Setting distance D1 or plug member position V1 is an example of the valve closed position, and setting distance D2 or plug member position V2 is an example of the valve open position. Figure 2 In the example, the plug member positions V1 and V2 correspond to axial positions on the plug member 46, where the shape of the plug member transitions from a truncated cone to a cylindrical shape, and where these positions are respectively in the valve closed and valve open positions. Alternatively, the actuator 48 includes an electric motor (not shown) or a hydraulic device as an energy source for selectively moving the plug member 46, for example, from the opening 44 and along axis A. X Move to a selected set distance (e.g., D1 or D2). In one example, the set distance is D2, and the different set distance (dashed outline) is D1. The set distance D1 is a given stroke ΔD away from the set distance D2. In an alternative embodiment, the set distance is D1 (dashed outline), and the different set distance is D2. The different set distance D2 is a given stroke ΔD away from the set distance D1, i.e., the given stroke is ΔD = |D1 - D2| = |D2 - D1. For most applications of valve assembly 22, all drilling mud is directed through opening 44 in orifice 42. However, in another embodiment, a bypass (not shown) may optionally exist for a small amount of drilling mud to bypass orifice 42 and seal 45, for example: (1) an additional flow passage located in housing 40 (tool collar); or (2) leakage in seal 45. In an alternative, the bypass allows about 0.1% to about 10% of the drilling mud to bypass orifice 42 and opening 44.

[0024] Figure 2 The actuator 48 is typically cylindrical, forming an annular slit 51 between the actuator 48 and the inner surface of the housing 40. A collar 52 is shown, disposed near the end of the actuator 48 where it connects to the valve stem 50. The collar 52 has an annular configuration and extends radially within the annular slit 51. The end of the housing 40 remote from the orifice 42 is closed to define a partition 54 extending radially between the sidewalls of the housing 40. The end of the actuator 48 opposite the plug member 46 axially abuts the partition 54. In one embodiment, the actuator 48 is fixedly connected to the partition 54. Drilling mud DM is shown flowing through the opening 44, around the plug member 46, and through passages 56, 58 formed axially through the collar 52 and the partition 54, respectively. The baffle 54 provides an axial stop or support for the actuator 48 in response to the flow of drilling mud DM, interfering with the axial movement of the actuator 48 when an axial force is applied. The baffle 54 provides an operative connection between the actuator 48 and the housing 40, which is part of the BHA 35. The orifice 42, collar 52, actuator 48, and baffle 54 are not limited to cylindrical or circular (annular) shapes, and in alternatives may have edges (e.g., a rectangular or polygonal cross-section in a plane perpendicular to axis Ax).

[0025] Still referencing Figure 2 The support sidewall 59 of the orifice 42 transitions radially outward at the lower end of the opening 44 and has a lower or downstream end supported on the collar 52. The support sidewall 59 is the connecting portion between the orifice 42 and the collar 52, providing a mechanical connection between them. As shown, the support sidewall 59 is an annular member that surrounds the plug member 46 and has an axial end extending between the orifice 42 and the collar 52. The support sidewall 59 provides a medium for force transmission from the orifice 42 to the collar 52 without interfering with the movement of the plug member 46 along the axis Ax. In one example, the upper end of the support sidewall 59 is fixedly connected to the lower end of the orifice 42, or alternatively removably connected to the lower end of the orifice 42. The lower end of the support sidewall is fixedly connected to the upper end of the collar 52, or alternatively removably connected to the upper end of the collar 52. Fixed connections include threaded connections, adhesive connections, welding, etc. Removable connections include abutment connections. In an alternative embodiment, the interference structures are located between the lower end of the orifice 42 and the upper end of the support sidewall 59, or between the upper end of the collar 52 and the lower end of the support sidewall 59. Examples of interference structures include spacer rings, etc. The collar 52 has a centering function for the actuator 48 in the housing 40. The orifice 42, collar 52, and support sidewall 59 are movable relative to the housing 40. The plug member 46 is movable relative to the housing 40 and relative to the orifice 42, support sidewall 59, collar 52, actuator 48, and partition 54 via the actuator 48. The lower end of the actuator 48, away from the plug member 46, is fixedly connected to the housing 40 via the partition 54. The lower end of the collar 52 abuts the upper end of the actuator 48 and is configured to transmit force to the actuator 48. In an alternative embodiment, the collar 52 is attached or fixedly connected to the actuator 48. As described in more detail below, the support sidewall 59 transmits the force applied to the orifice 42 by the drilling mud DM to the actuator 48 via the collar 52. In one embodiment, the orifice 42, support sidewall 59, and collar 52 are fixedly connected to each other; alternatively, these components form a single integral part. In this embodiment, the collar 52 is fixedly connected to the actuator 48 such that the orifice 42, support sidewall 59, and collar 52 move together relative to the housing 40, and in this way, force is applied to the actuator 48. Due to the partition 54, the actuator 48 cannot move relative to the housing 40. An optional flow meter 60 is schematically depicted within the bore 24, located upstream of the housing 40 and upstream of the actuator 48; alternatively, the flow meter 60 is mounted within the housing 40 or may be located downstream of the actuator 48. In this example, the flow meter 60 is depicted as a turbine flow meter and is attached to the axis A. XThe shaft is composed of multiple blades positioned coaxially. In the illustrated embodiment, the blades generate shaft rotation in response to the flow of fluid (drilling mud DM). Monitoring the shaft's rotational speed (revolutions per minute (RPM)) provides an estimate of the flow velocity of the fluid. In one embodiment, the flow velocity is measured by a turbine of a generator (not shown) located in BHA 35 for power generation purposes. In an embodiment, the support sidewall 59 is made of a single integral piece, or optionally of more than one integral piece, such as a half-shell. The sidewall 59 includes embodiments that are broken up to save weight and optionally has any form configured to transmit force from orifice 42 to collar 52 or to actuator 48.

[0026] Figure 2 The diagram also shows a sensor or measuring device 62 mounted on or within the housing of actuator 48. In this example, sensor 62 senses an axial force F applied to actuator 48, generated by causing drilling mud DM to flow through the bore 24 of drill string 18, through orifice 42, around plug member 46, and through collar 52. The force sensed by sensor 62 is the resistance acting on components of valve assembly 22. Sensor 62 may optionally include a temperature sensor, which alternatively allows for temperature compensation of the axial force F measurement data provided by sensor 62. The contribution to the force F measured by force sensor 62 includes the force F applied to orifice 42. O and the force F applied to the plug member 46 P The force F exerted on orifice 42 by the flow of drilling mud DM. O The force F exerted on the plug member 46 by means of the support sidewall 59 fixedly connected to the collar 52 is transmitted to the actuator 48, wherein the collar 52 is attached to the actuator 48. P The force is transmitted to the actuator 48 via the valve stem 50. The total force F detected by the sensor 62 is F = F O +F P In an alternative embodiment, sensor 62 or another sensor (not shown) is mounted in housing 40 to sense the axial force applied to housing 40. In such an embodiment, the force transmitted to actuator 48 is transmitted to housing 40 via partition 54, where the force is detected by a force sensor, which is equivalent to the force detected by sensor 62 in actuator 48. Valve stem 50 moves via actuator to move plug member 46. Force F P The force acts on actuator 48, while actuator 48 resists the force to hold plug member 46 in a specific position and prevent valve stem 50 from being pushed back into actuator 48 and away from valve seat 49. In this way, the force acting on plug member 46 is transmitted through valve stem 50 to actuator 48 and detected by sensor 62.

[0027] In a non-limiting example of operation, the density of the drilling mud DM is estimated by spacing the plug member 46 a distance D1 or D2 (referred to herein as the “set distance”) from the downstream end of the opening 44 and by using sensor 62 to sense the forces applied by the drilling mud DM to the orifice 42 and the plug member 46. In this example, sensor 62 is composed of a strain gauge that signals in response to strain within the housing of actuator 48. These signals are decoded to obtain values ​​representing the forces applied to actuator 48 or housing 40, respectively, from the flow of drilling mud DM. With the measured forces (from sensor 62), drilling fluid flow velocity, and set distance values, historical data is then consulted to identify the density of the drilling mud DM. Actuator 48 undergoes a length change due to the axial force acting on it. The axial force causing compression of actuator 48 (a reduction in axial length) can be detected by force sensor 62. Strain gauges are optionally connected to actuator 48 or housing 40 in various ways that allow for proper detection of compression of actuator 48. In an alternative, the strain gauge is glued, welded, or sputtered to the actuator 49. Instead of using a strain gauge, in an embodiment, the force is detected by a piezoelectric force sensor, optical force sensor, force sensor, or hydraulic force gauge located at or within the actuator housing and between the actuator and the partition 54.

[0028] Now for reference Figure 3 A graph 64 with a vertical axis 66 is shown, which represents the force F exerted by the drilling mud DM on the orifice 42 and the plug member 46. Figure 2 The horizontal axis 68 is included in the curve graph 64, which represents the set distances D1 and D2 (). Figure 2 The value of ), that is, the distance from the plug member 46 to the lower end of the opening 44 or the valve seat 49. Figure 64 includes a family of curves 70. 1-3 This represents the flow of different drilling muds acquired at different times, having the same flow velocity q but different densities ρ. In the example shown, curve 701 represents drilling mud with a first density ρ1, which is greater than that of curve 70. 2,3 The density of the drilling mud (measured at set distances D1 and D2) is represented by curve 702. Similarly, curve 702 represents drilling mud with a second density ρ2, which is greater than the density of the drilling mud (measured at set distances D1 and D2) represented by curve 703. Curve 703 represents drilling mud with a third density ρ3, which is less than the density of the drilling mud represented by curve 703. 1,2 The density of the drilling mud (measured at designated distances D1 and D2) is indicated. The distances D1 and D2 from the resting area of ​​the plug member 46 to the valve seat 49 of the orifice 42 are measured along axis Ax. Figure 2It should be understood that there are examples where the set distance is measured from any defined reference position on the plug member 46 along axis Ax to any defined reference point on the orifice 42, such as the resting area on the plug member 46 and the orifice 42, or the upper end of the plug member 46 along axis Ax to the lower end of the orifice 42, or the lower end of the plug member 46 along axis Ax to the lower end of the orifice 42.

[0029] Figure 4 The diagram shows how to merge from Figure 3 The data was used to create the curve 72. In curve 72, the vertical axis 74 represents the mud density, and the horizontal axis 76 represents the force difference ΔF between the first force F1 measured at the first set distance D1 and the second force F2 measured at the second set distance D2. Figure 3 In the alternative, the plug member 46 ( Figure 2 The distance or movement between the first set distance D1 and the second set distance D2 is called the given stroke ΔD. Figure 3 The given stroke ΔD is generated by D2-D1. Curve 78 in graph 72 graphically represents the situation when the plug member 46 is at the first set distance D1 and after moving the given stroke ΔD to the second distance D2, relative to curve 70. 1-3 The force difference ΔF represents each drilling mud measurement. As shown in Figure 78, for a given stroke ΔD of the plug member 46, the corresponding force difference ΔF increases with increasing drilling mud density. Using the force difference instead of individual force measurements eliminates the smaller contribution of resistance acting on other parts of the valve assembly (such as the collar 52 or the outer surface of the actuator 48) from the force data. These force contributions create background forces that affect each force measurement in the same way. Alternatively, the drilling mud density can be determined based on a single force and a single set distance using the same equipment and methods described herein. In this case, the background force is ignored or otherwise corrected, such as through mathematical correction.

[0030] In one example, valve assembly 22 ( Figure 2 Physical testing of the implementation scheme is conducted in a controlled environment, such as in a test bench, in a wellbore, or at another location where different drilling mud DM flows are guided through valve assembly 22; and where the different flows are at substantially the same flow rate, but the drilling mud has known different densities. Furthermore, in this alternative, when the plug member 46 is located at a first set distance D1 and a second set distance D2, sensor 62 ( Figure 2A suitable device, or another suitable apparatus, is used to measure the value of force F, which selectively produces a force difference ΔF. Optionally, the flow of drilling mud is mathematically modeled, simulated, or calculated, also referred to herein as calculation using a mathematical algorithm. The values ​​of forces F1 and F2 (and the force difference ΔF) are obtained using a mathematical algorithm based on known hydrodynamic evaluation methods, which is within the skill and capability of those skilled in the art and requires no excessive experimentation. Furthermore, in this example, example graphs identical or substantially identical to those in graphs 64 and 72 are created based on results obtained through physical testing and / or mathematical algorithms.

[0031] In one example, physical tests and / or mathematical algorithms (as described above) are performed and / or generated across a range of drilling mud with different flow rates and / or densities. Using the mathematical algorithms, additional measured and / or calculated values ​​of forces F1 and F2 (where the plug member 46 is at a first set distance D1 and a second set distance D2) are obtained from the additional physical tests and / or mathematical algorithms. In this example, physical tests and / or mathematical algorithms are performed to generate historical data, which contains values ​​conveying information describing the characteristics of the drilling mud flow through valve assembly 22. For the purposes of this discussion, drilling mud flow refers to the volume of drilling mud flowing through valve assembly 22 at a specific flow rate and having a specific density; for each share of drilling mud flow, forces F1 and F2 are measured / calculated when the valve plug member 46 is at a specific set distance D1 and at a specific given stroke ΔD from the set distance D1 (D2). The implementation of historical data includes a dataset representing the following values: (1) a specific drilling mud flow rate q, (2) a specific drilling mud density ρ, (3) a first set distance D1, (4) a given stroke ΔD, (5) a force F1 exerted on the valve assembly 22 by the drilling mud flow of the specific flow rate q and specific density ρ1 when the plug member 46 is at the first set distance D1, and (6) a force F2 exerted on the valve assembly 22 by the drilling mud flow of the specific flow rate q and specific density ρ1 when the plug member 46 is at a given stroke ΔD away from the first set distance D1, for example, when the plug member is at a second set distance D2. The values ​​or data constituting the dataset of a specific drilling mud flow are referred to as relevant data. Tests / calculations may optionally include a flow rate range (typically 100 gpm to 1500 gpm) from below to above the expected flow rate in the operation of a wellbore where the valve assembly 22 has been or is expected to be installed. In another example, the set distance D1 has a minimum value of zero (i.e., the plug member 46 contacts the opening 44 or the valve seat 49), and the given stroke ΔD has a maximum value limited by the position of the collar 52 or the length of the valve stem 50. In this example, the set distance D1 and / or the given stroke ΔD vary according to the flow rate and / or density of the drilling mud flow.

[0032] For the purposes of this discussion, the term "real-time" refers to the substances, conditions, characteristics, etc., within and / or during the operation of wellbore 12. In a non-limiting example, the real-time density of the drilling mud flow passing through valve assembly 22 is estimated by comparing real-time information or data (e.g., drilling mud flow in wellbore 12) with historical data, identifying a dataset of historical data that most closely approximates the real-time data, and selecting the drilling mud density from the historical dataset as the density of the real-time drilling mud. In this example, the drilling mud DM flow is guided through valve assembly 22 ( Figure 2 The flow rate (volume flow rate) of the drilling mud DM flow is sensed by flow meter 60. A plug member 46 is positioned at a first position and a second position (a first predetermined distance D1 and a second predetermined distance D2) spaced apart from the opening 44. When the plug member 46 is in the first position, the value of a first force F1 is sensed by sensor 62, and when the plug member 46 is in the second position, the value of a second force F2 is sensed by sensor 62. Alternatively, the first position is a predetermined distance D from the opening 44, and the second position is a given stroke ΔD from distance D, and vice versa. In this example, the force difference is obtained by finding the difference between the values ​​of the first force F1 and the second force F2, and the flow rate is the real-time flow rate q. r The force difference is the real-time force difference ΔF. r Setting distance D1 is the real-time setting distance D. r And the given journey is a real-time given journey ΔD. Then, historical data is consulted, and a dataset of relevant data within the historical data (historical dataset) is identified, which has a correlation with the real-time flow rate q. r Real-time force difference ΔF r Real-time setting distance D r and real-time given route ΔD r (Real-time data) The same or nearly the same historical flow rate q h Historical force difference ΔF h Historical setting distance D h and the historical given itinerary ΔD h The density of the drilling mud flowing through the valve assembly in real time is estimated to be the same as the density of the drilling mud in a historical dataset, which is correlated with the real-time data. Optionally, and as described above, the historical data is represented in a graph that is the same as or substantially similar to curves 64 and 72, and is consulted, and the real-time density of the drilling mud is estimated based on a graph that is the same as or similar to curve 78 and based on the historical data relationship between the force difference at a specific flow rate and the drilling mud density. In an alternative embodiment, the historical data is represented in a lookup table stored in memory and is accessible by a processor (e.g., a downhole processor) used in the real-time application. In yet another embodiment, the historical data is calculated using a processor and mathematical algorithms based on parameters used in the real-time measurement (set distance, given stroke, flow rate).

[0033] Return to reference Figure 1 and Figure 2 Valve assembly 22 includes a downhole processor or controller 80 ( Figure 2 The downhole processor or controller communicates with flow meter 60 and sensor 62 and is configured to estimate the real-time density of drilling mud based on the correlation between real-time and historical data, as outlined herein. Processor / controller 80 optionally communicates with processor / controller 82 shown on surface 16; examples exist where processors / controllers 80 and 82 are of the same type or are part of the same device. Processors / controllers 80 and 82 are each further configured to monitor and / or provide command signals for wellbore operations. Processors / controllers 80 and 82 optionally include memory 83, examples of which include a non-transitory computer-readable storage medium on which one or more of executable code, operating instructions, control information, data, and database records are stored. Examples of executable code include a set of instructions that cause processors / controllers 80 and 82 to perform operations such as receiving signals, generating and sending signals, wherein signals include commands for operating components (including those disclosed herein), and performing mathematical calculations. In an alternative, memory 83 is separate from and connected to processors / controllers 80 and 82 for communication or integration with them, and includes one or more of computer disks, magnetic tapes, conventional hard disk drives, electronic read-only memory, optical storage devices, any suitable data storage devices storing non-transitory computer-readable storage media thereon, and servers. Communication between processors / controllers 80 and 82 may optionally be performed via communication device 84, examples of which include the aforementioned hardwired, wireless, fiber optic, telemetry, etc. In the example, historical data is stored in processors / controllers 80 and / or processors / controllers 82 and / or other digital storage media (not shown). In the example, decisions for operating drill string 18 are based on real-time information about the drilling mud, such as drilling rate, drilling direction, direction of the drilling trajectory (azimuth, inclination), drill string revolutions per minute, drilling mud flow rate, drilling mud density, pressure on bit, drill bit changes, etc. Figure 1 The diagram further illustrates an optional pressure transducer 85, which is installed within the wellhead assembly 38 and selectively communicates with the wellbore 12.

[0034] In another alternative, valve assembly 22 operates as a mud pulse generator, and plug member 46 reciprocates axially relative to opening 44 to generate pressure pulses in the drilling mud DM flow circulating through wellbore 12. In this example, communication from wellbore 12 to surface 16 is performed telemetry via the operation of valve assembly 22. Valve assembly 22 generates pressure pulses in the flowing drilling mud within the borehole of drill string 18. The pressure pulses propagate from the location of the mud pulse generator within drill string 18 to the surface. The pressure pulses are detected by pressure transducer 85 at or near the surface location. To ensure reliable communication of the pressure pulses between valve assembly 22 and pressure transducer 85 at the surface, sufficient pressure drop needs to be generated by valve assembly 22. The pressure drop limits the pressure variation of the pressure pulses caused by the reciprocating plug member 46. The pressure pulse comprises a minimum pressure (valve assembly open position (D2), where flow is not blocked by plug member 46) and a maximum pressure (valve assembly closed position (D1), where flow is blocked by plug member 46), the difference being the pressure pulse height. A larger pressure pulse height corresponds to a larger pressure drop in the valve open position. The valve assembly closed position refers to the minimum distance from the plug member to the valve seat 49 in the orifice 42 during reciprocating motion along the axis Ax of plug member 46. The valve assembly open position refers to the maximum distance from the plug member to the valve seat in the orifice 42 during reciprocating motion along the axis Ax of plug member 46. Real-time estimation of the pressure drop becomes possible by using force measurements in the valve assembly to perform real-time estimation of the drilling mud density as described above. The pressure drop ΔP depends on the drilling mud density. Real-time determination of the drilling mud density allows for real-time estimation of the pressure drop. Force measurements are performed simultaneously with the reciprocating motion of the plug member 46 of valve assembly 22 to generate pressure pulses. In other words, when the plug member switches between positions V1 and V2 to generate pressure pulses, the force sensor 62 measures the forces experienced by the orifice 42 and the plug member 46 at different set distances D1 and D2 on the plug member 46. The density of the drilling mud is determined, and the pressure drop is calculated or determined based on historical data. Based on the determined pressure drop, the pressure drop is adjusted to the desired value.

[0035] In the alternative, the pressure drop ΔP across the valve assembly or the pressure drop across the orifice is estimated based on the force F measured by sensor 62. The pressure drop can be estimated using the equation P=F / A, where P is the pressure, F is the force, and A is the pressure-affected area. The pressure-affected area A is the upstream surface region 86 of the orifice 42 and the upstream surface region 87 (axially projected surface region) of the plug member 46 facing the well (the upstream surface region of the plug member). Furthermore, in this alternative, using the estimated pressure drop ΔP and the known flow velocity q of the drilling mud DM, the density ρ of the drilling mud DM can be calculated using the following equation 1:

[0036] Formula 1

[0037] For a specific set distance (D1 or D2) from the plug member to the valve seat, the flow restriction region a and the valve coefficient Cv are unique to valve assembly 22, and measuring or calculating these values ​​is within the capabilities of those skilled in the art. The flow restriction region a is defined by the area left by the plug member 46 for drilling mud to flow out through the opening 44 and along the plug member 46. The flow restriction region a changes as the set distance varies. The pressure drop ΔP of the drilling mud DM flow through valve assembly 22 depends on the flow velocity q, the density ρ of the drilling mud, and the position (or set distance D) of the plug member 46. Figure 5 The curve in Figure 88 is shown graphically (similar to...). Figure 3 (Figure 64 in the figure), which has a curve representing the passage through valve assembly 22 ( Figure 2 The vertical axis 90 represents the pressure drop of the drilling mud DM, the horizontal axis 92 represents the position of the plug component 46, and the family of curves 94. 1-3 Curve 94 1-3 Each of the figures represents the flow rate of the drilling mud DM and how the position of the plug component 46 affects the pressure drop of the mud flow. The flow rate represented by curve 942 exceeds that represented by curve 941, and the flow rate represented by curve 943 exceeds that represented by curve 942. (The last two lines appear to be incomplete and possibly refer to curve 941 and 942.) 1-3 Each of the values ​​in the table represents the same density of the drilling mud. Figure 6 The image shows something similar to Figure 5 The curves 88 and 96, with the vertical axis 98 representing the pressure drop of drilling mud DM on valve assembly 22 and the horizontal axis 100 representing the position of plug component 46, and curve family 102 1-3 .exist Figure 6 In the middle, by curve 102 1-3 The flow rates of drilling mud DM are the same, but the density of drilling mud DM is shown in curve 102. 1-3 The density varies among the various values; specifically, the density represented by curve 1022 exceeds the density of drilling mud DM represented by curve 1021, and the density represented by curve 1023 exceeds the density of drilling mud DM represented by curve 1022. Curves 88 and 96 are selectively created showing the relationship between the pressure drop ΔP across valve assembly 22 and a set distance, allowing for the estimation of real-time drilling mud density based on historical data, which includes historical force difference data ΔF. h Estimated historical pressure drop data ΔP h In the example, the flow restriction area a is quantified by converting the values ​​of the aforementioned set distances D1 and D2. Figure 2 ). Figure 5The diagram illustrates the correlation between pressure drop and mud density ρ, flow velocity q, and a set distance. Determining the density of the drilling mud DM using force measurements as described above allows for the determination of the pressure drop at a specific plug component location (set distance). In one example, the flow velocity is known from flow rate measurements (e.g., obtained from a flow meter). The pressure drop ΔP is determined in real time. r This provides an opportunity to detect inefficient real-time pressure drops (too small or too large) used in communication between the downhole location and the surface. After detecting an insufficient pressure drop, adjustments can be made to a set distance (D1 and / or D2) to optimize the pressure drop to the desired level, such as, for example, 20 bar or any other suitable pressure drop value. Figure 5 and Figure 6 The curves 88 and 96 in the diagram also allow identification of how to adjust set distances D1 and D2 and / or a given stroke ΔD to achieve the desired pressure drop. Examples of adjustment include changing D1 or D2 or both, or changing the given stroke ΔD. Optionally, pressure drop adjustment to the desired pressure drop is performed by correlating or comparing the real-time measured force difference with historical data and determining how to adjust valve assembly operating parameters to achieve an optimized pressure drop, based on historical data. In one example, the measured force difference is transmitted to the surface, such as to controller 82, to determine the mud density and pressure drop at the surface, and may be instructed via telemetry (downlink) to valve assembly 22 in wellbore 12 to adjust valve assembly operating parameters (e.g., set distance, data rate (plug member reciprocating motion or oscillation frequency)). Alternatively, the pressure drop is calculated downhole by downhole controller 80, and valve assembly operating parameters are automatically adjusted downhole without human intervention. Controller 82 or 80 may optionally determine the pressure drop directly from the force difference without outputting the drilling mud density during the determination. Furthermore, in this example, a method using… Figures 3-6 The system uses one or more charts to represent historical data to perform the determination of pressure drop based on (one or more) force differences.

[0038] In the example in use, the pressure drop across valve assembly 22 is controlled, and the density of the drilling mud is not directly calculated. In this example, when the plug member 46 is at a set distance (D1 or D2) and / or a given stroke ΔD, the force F is measured by sensor 62 and controlled by controller 80. Figure 2 ) and / or controller 82 ( Figure 1 The pressure drop through valve assembly 22 is calculated, and the pressure drop calculation is based on the real-time flow rate of drilling mud flow DM, valve characteristic chart, set distance and given stroke, and the value of force F measured by sensor 62. Figure 3This is an example of a valve characteristic graph, which, in an alternative, graphically represents the relationship between pressure and a set distance or given stroke. Controller 80 and / or controller 82 calculate the new set distance and given stroke to adjust the pressure drop to a target value. In another alternative, the measured force F is used for condition monitoring of valve assembly 22, such as when operating as a mud pulse system, to detect blockages in the circulation of the drilling mud DM flow or corrosion in the hardware handling the drilling mud DM flow. Optionally, the pressure drop is calculated multiple times over a period of time and compared with a reference signal or historical data stored in a lookup table; or alternatively, it is calculated or modeled mathematically. Examples of time periods include 1 hour, 5 hours, 10 hours, 50 hours, 100 hours, and any value between 1 and 100 hours. In alternative applications, the measured force F is used to detect pressure events in the drill string 18 unrelated to valve assembly 22, such pressure drops being generated by the axial movement of rotors in a mud motor (not shown), a shredder (not shown), or other tools that produce changes in axial load. In a non-limiting example of operation, an alarm may optionally be generated by the processor 82 at the surface 16 when force measurements indicate a pressure event in wellbore 12 (e.g., a deviation from expected pressure), or when the pressure drop generated by the mud pulse generator 22 is insufficient for reliable data communication. The alarm instructs the operator to take mitigation actions. Examples of mitigation actions include changes in operating parameters as described above (e.g., changes in permeability). Those skilled in the art will recognize pressure drops insufficient for reliable data communication.

[0039] Figure 7 The partial sectional side view in the figure shows a second exemplary embodiment of the valve assembly 22A, wherein the orifice or flow restrictor 42A and the baffle 54A are integrally formed within the housing 40A. In this embodiment, there is no sidewall extending axially from the downstream end of the orifice 42A. Figure 7 The valve assembly 22A also includes a force sensor or force measuring device 104A, shown as being disposed in the sidewall of the housing 40A or mounted on the housing. A collar 52A is movable relative to the housing 40A, the orifice 42A, and the partition 54A. A force F is applied to the upstream surface region 86A of the orifice 42A. O and the force F applied to the upstream surface region 87A of the plug member 46A P Detected by force sensor 104A. Figure 7 In an alternative embodiment, a force F is applied to the upstream surface region 87A of the plug member 46A. P The force is measured by sensor 62A mounted on actuator 48A. The force (F=F) is measured by force sensor 104A. O +F P The force is greater than the force measured by sensor 62A (F=F). PTherefore, it is easier to detect. However, the reading at force sensor 104A is affected by loads acting on housing 40A in other ways (e.g., changes in WOB, bending of BHA, etc.). In one embodiment, force sensors 62A and / or 104A communicate with a processor (not shown) that optionally includes memory. A flow meter (not shown) is optionally mounted in a bore in housing 40A and communicates with the processor, and measures the flow rate of drilling mud DM flow. Figure 2 The force F is measured at two different set distances (D1 and D2) on the plug member 46A to improve force measurement and eliminate background forces. In an alternative embodiment, the force may be measured at force sensor 104A and force sensor 62A to determine the resultant force and improve the measurement.

[0040] Figure 8 A partial sectional side view shows a third alternative embodiment of valve assembly 22B, which includes a rotary shear valve. In this example, actuator 48B rotatably drives drive shaft 110B (shown in dashed view). Drive shaft 110B extends from the interior of actuator 48B through stator 111B and is connected to rotor disk 112B downstream of stator 111B. In this embodiment, stator 111B operates as a flow restrictor, and rotor disk 112B operates as a plug member. Drive shaft 110B is rotated by actuator 48B to be rotatable relative to stator 111B and is axially fixed to actuator 48B such that drive shaft 110B is substantially axially stationary relative to stator 111B. Stator 111B includes a plurality of fluid passages or openings 56B extending axially therethrough. Rotor disk 112B includes a plurality of blades 106B that rotate about axis A as rotor disk 112B rotates. X The rotor disk 112B operates to selectively block fluid flow through the opening 56B of the stator 111B. In the example, the rotor disk 112B rotates in the same direction, rotates in alternating directions, rotates at a constant rotational speed, rotates at a varying rotational speed, rotates in an oscillating manner, or a combination thereof. A baffle 54B is disposed on the wellhead (upstream) of the shear valve assembly 22B and is fixedly connected to the actuator 48B to the housing 40B. Drilling mud DM flows through the passage 58B in the baffle 54B and along the actuator 48B before reaching the opening 56B in the stator 111B and impacting the upstream-facing surface of the blade 106B. The drilling mud DM follows a path within the housing 40B (part of the tool collar and BHA 35) that extends axially through the annular gap 51B and through the opening 56B of the stator 111B; after exiting the opening 56B, the drilling mud DM flows into the downstream end of the valve assembly 22B. The blades 106B of the rotor disk 112B are generally planar components that are substantially perpendicular to axis A. XOrientation. The radially inward end of blade 106B is mounted to the outer periphery of hub 108B, which is configured adjacent to the downstream-facing surface of stator 111B and connected to the other end of drive shaft 110B opposite to the end connected to actuator 48B. Hub 108B and blade 106B form rotor disk 112B. An axial clearance 107B is present between stator 111B and rotor disk 112B, allowing rotor disk 112B to rotate freely relative to stator 111B. In a non-limiting example of operation, drive shaft 110B is actuated, for example, by a motor (not shown) in actuator 48B as shown by arrow A. R The rotation angle α is shown. The rotation or oscillation of the drive shaft 110B and the attached rotor disk 112B causes the blade 106B to selectively rotate or oscillate to a position that is fully, partially, or completely away from the flow path of the drilling mud DM at the downstream end of the opening 56B. When fully or partially in the drilling mud flow path, the blade 106B interferes with the drilling mud DM flowing through the opening 56B, which generates an axial force F on the blade 106B. B The force on blade 106B is applied to the upstream surface region 109B of blade 106B and is related to the size of the surface region exposed to the drilling mud flow. The force on blade 106B increases with the portion of opening 56B blocked by blade 106B. That is, the more the rotor disk 112B and blade 106B rotate toward a position that fully overlaps with opening 56B (fully in, valve fully closed), the greater the force F on blade 106B. BThe larger the flow restriction area a (Equation 1), the more the blade 106B rotates to a position where it fully overlaps with the opening 56B, the more the flow restriction area a decreases. The flow restriction area a (Equation 1) is defined by a portion of the opening 56B that remains open to allow drilling mud flow through the stator 111B. The flow restriction area a is at its maximum when the opening 56B is not blocked by the rotor disk 112B and the blade 106B does not overlap with the opening 56B (fully extended, valve fully open). As described in the previous embodiment, at least one force measurement is required to determine the density of the drilling mud DM. However, performing two force measurements at two different flow restriction areas a or at two different rotational positions of the stator 111B and the rotor disk 112B relative to each other can eliminate background forces. The different rotational positions of the rotor disk 112B relative to the stator 111B are represented by different rotation angles α of the rotor disk 112B. In one example, force measurements are performed at rotation angles α1 and α2. In position α1 of rotor disk 112B, the maximum angular width of blade 106B is set between the rearward and forward angular ends of opening 56B. In position α2 of rotor disk 112B, the area of ​​blade 106B directly downstream of opening 56B is smaller than that in position α1. Therefore, in position α2, blade 106B obstructs drilling mud flow through opening 56B more than in position α2. Rotational positions α1 and α2 correspond to two different confinement regions. The upstream surface area of ​​a single blade is the total upstream surface area 109B of all blades, and the force F B This is the force applied to the total upstream surface area. The stator 111B, rotor disk 112B, and drive shaft 110B are axially movable relative to the housing 40B, while the diaphragm 54B and actuator 48B are fixedly connected to the housing 40B. The force F applied to the blade 106B by the drilling mud DM flow is... B The actuator 48B is pulled via the drive shaft 110B. This is in addition to the force F acting on the blade 106B. B In addition, the drilling mud DM flow applies a force F to the upstream surface 113B of the stator 111B. S Force F = Force F S +force F B This force is transmitted to actuator 48B and sensed by sensor or measuring device 62B. In the example shown, stator 111B is fixedly connected to actuator 48B, and rotor disk 112B is fixedly connected to actuator 48B via drive shaft 110B. Stator 111B and rotor disk 112B cannot move axially relative to each other. That is, when stator 111B moves axially, rotor disk 112B moves accordingly. Blade 106B is also axially fixedly connected to actuator 48B via rotor disk 112B. In other words, due to force F... S and F BThe axial movement of the stator 111B and / or rotor disk 112B or blade 106B causes the actuator 48B to extend. The extension is detected by a force sensor 62B. The stator 111B optionally includes a sealing extension 114B on its upstream side. In the example shown, the sealing extension 114B is an annular member having an outer surface abutting the inner surface of the housing 40B. In this example, the inner diameter of the sealing extension 114B radially exceeds the outer diameter of the opening 56B. A seal 45B is disposed in a recess formed along the outer periphery of the sealing extension. The sealing extension 114B is integrally or fixedly connected to the stator 111B. The sealing extension 114B is movable relative to the housing 40B together with the stator 111B. The seal 45B in the sealing extension 114B prevents fluid leakage between the outer peripheral surface of the stator 111B and the inner surface of the housing 40B. In an alternative embodiment, when the size of the stator 111B allows sufficient space for the seal integrated within the stator 111B, the seal 45B is placed in the circumferential surface of the stator 111B facing the inner surface of the housing 40B. In this case, the seal extension 114B is not required. The force sensor 62B communicates with a processor (not shown) that optionally includes a memory. A flow meter (not shown), mounted in a bore in the housing 40B and communicating with the processor, measures the flow rate of the drilling mud DM flow. As previously described, the measured force is converted into the density or pressure drop of the drilling mud using historical data, such as a lookup table (e.g., in memory). Optionally, the density or pressure drop can be calculated based on the measured force data. An example of a valve assembly includes a shear valve mud pulse generator that generates pressure changes in the drilling mud for telemetry purposes. Rotational positions α1 and α2 of the valve assembly are optionally used to generate a pulse sequence (α1 corresponds to an increase in pressure in the drilling mud (pressure pulse), α2 corresponds to a base pressure (no pressure pulse)). Force measurement can be performed while the mud pulse generator is running and transmitting pressure-encoded telemetry data. In an alternative embodiment, the shear valve assembly 22B (stator 111B and rotor disk 112B) can be located upstream of the actuator 48B. In yet another embodiment, the rotor 112B includes only one blade 106B, and the stator 111B includes only one fluid passage 56B. In yet another embodiment, the force sensor can be positioned within the housing 40B, similar to the previously described embodiments.

[0041] Figure 9 The side sectional view schematically illustrates a fourth exemplary embodiment of valve assembly 22C, which includes an orifice or flow restrictor 42C at the upstream end of valve assembly 22C. This valve assembly is referred to herein as a force-balanced reciprocating valve assembly (“FBR valve assembly”). A first opening 44C is located on axis A. X The radially offset location extends axially through the orifice 42C. The drilling mud DM extends along axis A. XThe flow is essentially parallel and passes through the first opening 44C. Figure 9 The plug member 46C is an elongated member oriented longitudinally within the housing 40C (part of the tool collar and BHA 35) and aligned with the downstream end of the first opening 44C to be in the path of the drilling mud DM exiting the first opening 44C. The orifice 42C optionally includes a valve seat 81C at the downstream end of the first opening 44C, and the plug member 46C includes a resting area 79C configured to engage with the valve seat 81C when in the fully closed position. The end of the plug member 46C opposite the resting area 79C abuts against a rocker arm 115C, shown relative to axis A. X A slender, tilted member. The middle portion of rocker arm 115C pivots at fulcrum 116B. The side of fulcrum 116C opposite to rocker arm 115C is supported by actuator 48C via a support member, such as plate 117C, which is shown transverse to axis A. X A directional planar member. Plate 117C is connected to the upstream side of actuator 48C and includes a fluid passage 120C for drilling mud to pass through. The end of actuator 48C opposite to the end of actuator connected to plate 177C is fixedly connected to housing 40C via partition 54C. Partition 54C includes opening 58C for drilling mud to flow through. A sensor or measuring device 62C is mounted on or in actuator 48C. Rocker 115C, fulcrum 116C, and support plate 117C are simplified representations of more complex equivalent mechanical structures, such as, for example, bevel gears operatively coupled to actuator 48C. The downstream end of piston 118C abuts the upstream-facing surface of rocker 115C, away from its contact with plug member 46C. Piston 118C is an elongated member shown as substantially parallel to and radially offset from plug member 46C. The upstream end of piston 118C protrudes through a second opening 119C, which is formed axially through orifice 42C and from axis A. X The opening 44C is radially offset. The force exerted on the piston 118C by the drilling mud flow DM is transmitted to the plug member 46C via the motor connection of the rocker arm 115C and the fulcrum 116C, and in the opposite direction to the force exerted on the plug member 46C by the drilling mud flow DM. The force transmitted from the piston 118C to the plug member 46C reduces the actuator force F required by the actuator 48C to drive the plug member 46C into the opening 44C. AThis reduces the energy consumption of the actuator 48C (e.g., an electric motor). A seal 122C is provided along the outer periphery of the orifice 42C, forming a fluid flow barrier between the orifice 42C and the inner surface of the housing 40C. A support sidewall 124C is shown extending axially along the inner surface of the housing 40C between the orifice 42C and the plate 117C. The orifice 42C, the support sidewall 124C, the plate 117C, and the actuator 48C are fixedly connected to each other such that when the orifice 42C, the support sidewall 124C, and the plate 117C are subjected to a force F applied to the plug member 46C, the force F is applied to the plug member 46C. P The force F applied to piston 118C M and the force F applied to orifice 42C O When moving axially, these components move together and apply a force F to actuator 48C, causing compression of actuator 48C (or a portion thereof). Actuator 48C is configured to drive rocker arm 115C (F A This causes the plug member 46C to move reciprocally, thereby generating pressure pulses in the drilling mud DM. Force F O and F P and F M The force F is generated by drilling mud DM impacting the upstream surface region 86C of the orifice 42C, the upstream surface region 87C (axial projection surface) of the plug member 46C, and the upstream surface region 89C of the piston 118C. O Extending axially along the support sidewall 124C and via plate 117C to the actuator 48C. Force F P The force is transmitted axially along the plug element 46C, through the fulcrum 116C and plate 117C, to the rocker arm 115C. And the force F... M The force is transmitted axially along piston 118C to rocker arm 115C, and then through fulcrum 116C and plate 117C to actuator 48C. Sensor 62C detects the force F=F O +F P +F MWhen the plug member 46C is positioned such that a set distance D exists between the plug member 46C and the valve seat 81C in the opening 44C, a force F is measured. The set distance D represents the restricted area of ​​the valve assembly 22C. As previously explained, the force F may optionally be measured at two different set distances D1 and D2, and a force difference ΔF is determined to eliminate any background force. A force sensor 62C communicates with a processor (not shown) that optionally includes memory. A flow meter (not shown), mounted in a bore in the housing 40C and communicating with the processor, measures the flow velocity of the drilling mud DM. The memory, communicating with the processor, optionally stores a lookup table including historical data used to determine the density of the drilling mud based on the measured force F or the determined force difference ΔF and the flow velocity. In an alternative embodiment, the density is calculated using the measured force (or force difference) and the flow velocity of the drilling mud DM at the set distance D (or set distance). In an alternative embodiment, force sensor 62C is located in or on plug member 46C instead of in or on actuator 48C, or is located in or on actuator 48C in combination with another force sensor (not shown). In the latter embodiment, two force sensors improve measurement quality. Figure 9 An example of the operation of valve assembly 22C can be found in Peters' U.S. Patent No. 11,892,093 (“Peters'093”), which has been assigned to the assignee of this application and is incorporated herein by reference in its entirety for all purposes. In the embodiments, Figure 9 The embodiments shown and described herein operate in substantially the same manner as those described in Peters' 093 and use substantially the same components.

[0042] Figure 10 What is shown is Figure 9 An alternative example of the operation of the embodiment shown is presented. In this embodiment, the resistance applied to the valve assembly 22C due to the flow of drilling mud DM is detected by observing the motor current of the motor (not shown) in the actuator 48C of the plug member 46C driving the valve assembly 22C. Return to Reference Figure 9The FBR valve assembly includes an electric motor (not shown) in actuator 48C. In the FBR valve assembly, the plug member 46C in valve assembly 22C is driven by applying a force (actuator force) provided by actuator 48C to a motorized connection (represented by fulcrum 116C and rocker arm 115C). The electric motor in the actuator optionally generates rotational motion or torque (torque motor, such as a synchronous spindle rotation motor), which is converted into a linear force (actuator force) via the motorized connection. The motorized connection may optionally be a bevel gear as described in Peters' 093. The actuator force drives the plug member 46C toward an opening 44C in orifice 42C, which is fixedly connected to housing 40C. A force F applied to the plug member 46C by the drilling mud DM flow... P The force F acting in the opposite direction to the actuator force and at least partially exerted on the piston 118C by the drilling mud DM flow. M Balance. When force F is transmitted to the plug member 46C via the motor connector, the force is balanced. M Along with force F P The direction is opposite to the direction. When the plug component 46C is held at the set distance D, the resultant force F R =F P -F M The force F acts on the motorized connector and will be compensated by the actuator force. To hold the plug member in a specific position V or a corresponding set distance D from the opening 44C in the orifice 42C, the motor needs to generate sufficiently large torque to compensate for the force F. R This leads to a current demand on the motor. In other words, the magnitude of the motor current depends on the force F. R The magnitude of the force is proportional to the magnitude of the force. In the example, an increase in the magnitude of the force will, in turn, increase the magnitude of the motor current, and the force F... R A decrease in the magnitude of [the quantity] will cause a decrease in the magnitude of the motor current. The motor current can optionally be controlled by the processor / controller 82 ( Figure 1 The current is monitored or measured by a motor current measuring device (not shown). In this example, the processor is configured to control the motor and thus monitor the motor current during operation. A positioning sensor (not shown) communicating with the processor provides information about the position of the plug member 46C by detecting the angle or number of revolutions of the motor's spindle rotation. Implementations of the positioning sensor include a rotary transformer that provides a measurement of the motor spindle rotation angle, and alternative position detection systems such as capacitive, magnetic, or optical sensors. The positioning sensor enables the processor to control the motor to position the upstream surface region 87C of the plug member 46C at position V. A flow meter (not shown) is located at valve assembly 22C or BHA 35 (…). Figure 1The flow velocity of the drilling mud DM is measured upstream or downstream of the source. Historical data generated in a laboratory, in a probing well, or determined by calculation may optionally be used to determine the density of the drilling mud DM based on the measured motor current and the measured flow velocity of the drilling mud DM. Examples of historical data include lookup tables. In an alternative embodiment, the motor current is converted into the density of the drilling mud DM using mathematical algorithms, measured flow velocity, measurements of a flow restriction zone defined by a set distance D, a valve coefficient, and optionally a transmission ratio, which is within the capabilities of those skilled in the art. The motor current measurement is affected by frictional forces acting on the motor's spindle, for example, by a sealing element that seals the inside and outside of the motor and the drilling mud. The frictional forces may optionally be removed from the motor current measurement by superimposed oscillations of the plug member 46C around position V. The oscillations have a small amplitude and may optionally be only one millimeter or a few millimeters, such as 0.5 mm to 5 mm. Determining the average motor current during oscillation eliminates the contribution of friction-induced motor current measurements, ensuring that the measured motor current value represents only the resistance F applied to the plug member 46C. P Due to the oscillations, inertial forces begin to take effect, which can optionally be eliminated by averaging the motor current over multiple oscillations (e.g., 5, 10, 20, or 100). The oscillations optionally occur at one or more frequencies from 1 Hz to 10 Hz for a duration of several seconds, such as about 1 to 5 seconds, or about 1 to 10 seconds. Optionally, the motor current of a single phase of the power supply is measured (typically three-phase). The phase used for measuring the motor current is optionally the electrical phase with the highest current. The oscillations are optionally sinusoidal oscillations or any other type of oscillation that allows for the determination of an average value and the elimination of the contribution of frictional forces. In an alternative embodiment, instead of measuring the motor current, the electrical power consumption of the motor is measured.

[0043] Figure 11The diagram shows a graph 100 with a vertical axis 102, representing the current I measured by the processor. Graph 100 includes an horizontal axis 104, representing the value of a set distance D. Graph 100 includes two curves 106 and 108, graphically representing the corresponding values ​​of motor current I and a set distance (i.e., the distance from the upstream surface region 87C to the valve seat 81C) for drilling mud of different densities flowing at the same flow rate; in the example shown, the flow rate is 1000 liters / minute. In the example shown, curve 106 represents drilling mud with a first density greater than the second density represented by curve 108. Comparing the measured motor current with historical data allows for the determination of mud density. To improve the accuracy of density determination, when the motor current I and set distance D data used to create curves 106 and 108 are obtained, motor current measurements can optionally be performed at multiple set distances D, which improves accuracy in identifying historical data representing the density of the drilling mud. Optionally, motor current measurement is performed during a separate density measurement operation or during routine valve operation, such as pulse generation during mud pulse generator operation when the plug member 46C selectively moves from the valve closed position to the valve open position. Alternatively, when in the valve closed position, the plug member 46C is spaced apart from the valve seat 81C in the orifice 42C to reduce wear. In a non-limiting example, the determined drilling mud density is used to adjust valve assembly operating parameters, such as the set distance or data rate (plug member reciprocating motion or oscillation frequency) during pulse generation, or to adjust operating parameters of the drilling assembly 10, such as flow rate, mud properties, or perforation rate. In an alternative example, instead of measuring motor current, the force F applied to the plug member 46C is detected by directly sensing the torque of the motor spindle in the actuator 48C by a torque meter (not shown). P Torque meters, such as strain gauges, torque measuring shafts, or force sensors, are used. In yet another exemplary embodiment, the motor current measurement is combined with a force measurement obtained using a force sensor and / or a torque measurement obtained using a torque meter.

[0044] Therefore, the invention described herein is well-suited to achieving these objectives and realizing the mentioned objectives and advantages, as well as other objectives and advantages inherent therein. While only the presently preferred embodiments of the invention are given for purposes of disclosure, many changes exist in the details of the steps for achieving the desired results. These and other similar modifications will be apparent to those skilled in the art and are intended to be covered within the spirit of the invention disclosed herein and the scope of the appended claims.

Claims

1. A downhole valve assembly for determining fluid density in a wellbore, the valve assembly comprising: case; A current limiter, the current limiter including an opening; Fluid, the fluid flowing through the valve assembly and through the opening of the flow restrictor; A plug member configured to at least partially plug the opening of the current limiter; An actuator configured to drive the plug member relative to the flow restrictor to select a flow restriction region; A flow meter for measuring the flow rate of fluid flowing through the valve assembly; A measuring device located in or on the valve assembly, the measuring device being configured to measure parameters relating to the forces acting on at least one of the flow restrictor and the plug member due to the fluid flowing through the valve assembly; The processor is configured to: The actuator is used to position the plug member at a selected location corresponding to the selected flow restriction area. When the plug member is positioned corresponding to the selected flow restriction area, measurement data is obtained from the measuring device, and The fluid density is determined using the obtained measurement data and the measured flow rate.

2. The system of claim 1, wherein the measuring device is a force sensor configured to measure the force acting on at least one of the current limiter and the plug member, and the measurement data is force data.

3. The system according to claim 1, wherein, The actuator includes an electric motor, and the measuring device is configured to measure parameters related to the electrical power consumption of the electric motor, the electrical power consumption of which is required by the electric motor to hold the plug member in a position corresponding to a selected flow restriction area, and the measured data is one of electrical power consumption data and electric motor current data.

4. The system according to claim 3, wherein, The processor is configured to cause the plug member to oscillate around a position corresponding to a selected flow restriction region, and to determine the fluid density by calculating the average of one of the electrical power consumption data and the motor current data.

5. The system according to claim 1, wherein, The valve assembly includes a piston and a motor-driven connection.

6. The system according to claim 1, wherein, The valve assembly is a shear valve, the flow restrictor is a stator including at least one opening, and the plug member is a rotor disk including at least one blade.

7. The system according to claim 1, wherein, The selected location includes a first selected location corresponding to a first selected flow restriction area and a second selected location corresponding to a second selected flow restriction area, and the measurement data includes first measurement data and second measurement data. The processor is configured to position the plug member at the first selected location and the plug member at the second selected location, and to obtain the first measurement data from the measuring device when the plug member is at the first selected location, and to obtain the second measurement data from the measuring device when the plug member is at the second selected location, and to use the first measurement data and the second measurement data to determine the fluid density.

8. The system according to claim 1, wherein, The actuator includes a spindle, and the measuring device is a torque meter configured to measure the torque acting on the spindle, and the measurement data is torque data.

9. The system of claim 1, wherein the valve assembly is part of a downhole telemetry system, and the fluid is drilling mud, the valve assembly generates pressure pulses in the drilling mud in the wellbore, and the downhole telemetry system includes a pressure transducer at a surface location configured to detect the pressure pulses.

10. The system of claim 1, wherein the measuring device is located in or on the actuator.

11. A method for measuring fluid density in a wellbore, the method comprising: A valve assembly is used to guide fluid flow through the wellbore. The valve assembly includes a housing, an actuator, a plug component, a processor, a measuring device, a flow meter, and a flow restrictor, the flow restrictor including an opening. The processor and the actuator are used to position the plug member relative to the opening of the flow restrictor, thereby defining a selected flow restriction area; The flow rate of the fluid is detected using the flow meter. The measuring device is used to measure measurement data related to the force exerted by the fluid flow on at least one of the flow restrictor and the plug member; The processor is used to obtain the measurement data from the measuring device; The processor is used to determine the fluid density based on the measurement data and the detected flow rate; and The operating parameters are adjusted based on the determined fluid density.

12. The method of claim 11, wherein the measuring device is a force sensor and the measuring data is force data.

13. The method of claim 11, wherein the actuator comprises an electric motor, and measuring the measurement data comprises measuring current data or power consumption data using the measuring device.

14. The method of claim 13, further comprising using the processor and the actuator to oscillate the plug member around a position corresponding to a selected flow restriction region, wherein determining the fluid density includes calculating an average of at least one of the current data and the electrical power consumption data.

15. The method according to claim 11, wherein, The valve assembly includes a piston and a motor-driven connection.

16. The method according to claim 11, wherein, The valve assembly is a shear valve, the flow limiter is a stator, and the plug member is a rotor disc.

17. The method according to claim 11, wherein, The selected position includes a first selected position corresponding to a first selected flow restriction area and a second selected position corresponding to a second selected flow restriction area, and the measurement data includes first measurement data and second measurement data. The plug member is positioned at the first selected position and the plug member is positioned at the second selected position. The first measurement data is obtained from the measuring device when the plug member is at the first selected position, and the second measurement data is obtained from the measuring device when the plug member is at the second selected position. The fluid density is determined using the first measurement data and the second measurement data.

18. The method according to claim 11, wherein, The actuator includes a spindle, and the measuring device is a torque meter, which is used to measure the torque acting on the spindle.

19. The method according to claim 11, wherein, Determining the fluid density includes using historical data, which is obtained in a laboratory, in a probing well, or through calculation.

20. The method according to claim 11, wherein, The determination of the fluid density is performed when the processor is in the wellbore and during downhole operations, wherein adjusting the operating parameters includes adjusting one or more of the operating parameters of the valve assembly and the operating parameters of the drilling system.

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