ROTARY PULSER WITH FLOW BYPASS ELEMENTS

Description

TECHNICAL FIELD

The present disclosure relates to a rotary pulser with flow bypass elements, including related drilling systems and methods.

BACKGROUND

Drilling systems are designed to drill a bore into the earth to target hydrocarbon sources. Drilling operators rely on accurate operational information to manage the drilling system and reach the target hydrocarbon source as efficiently as possible. The downhole end of the drill string in a drilling system, referred to as a bottomhole assembly, can include specialized tools designed to obtain operational information for the drill string and drill bit, and in some cases characteristics of the formation. In measurement-while-drilling (MWD) applications, sensing modules in the bottomhole assembly provide information concerning the direction of the drilling. This information can be used, for example, to control the direction in which the drill bit advances in a rotary steerable drill string.

In “logging while drilling” (LWD) applications, characteristics of the formation being drilled through is obtained. For example, resistivity sensors may be used to transmit, and then receive, high frequency wavelength signals (e.g., electromagnetic waves) that travel through the formation surrounding the sensor. Other sensors are used in conjunction with magnetic resonance imaging (MRI). Still other sensors include gamma scintillators, which are used to determine the natural radioactivity of the formation, and nuclear detectors, which are used to determine the porosity and density of the formation. In both LWD and MWD applications, the information collected by the sensors can be transmitted to the surface for analysis. One technique for transmitting date between surface and downhole location is “mud pulse telemetry.” In a mud pulse telemetry system, signals from the sensor modules are received and encoded in a module housed in the bottomhole assembly. A controller actuates a pulser, also incorporated into the bottomhole assembly, which generates pressure pulses in the drilling fluid flowing through the drill string and out of the drill bit. The pressure pulses contain the encoded information. The pressure pulses travel up the column of drilling fluid to the surface, where they are detected by a pressure transducer. The data from the pressure transducers are then decoded and analyzed as needed. Such pulsers have relatively low data rates and consume large amounts of power.

The foregoing background discussion is intended solely to aid the reader. It is not intended to limit the innovations described herein. Thus, the foregoing discussion should not be taken to indicate that any particular element of a prior system is unsuitable for use with the innovations described herein, nor is it intended to indicate that any element is essential in implementing the innovations described herein. The implementations and application of the innovations described herein are defined by the appended claims.

SUMMARY

An embodiment is a rotary pulser configured to be positioned along a drill string through which a fluid flows. The rotary pulser includes a shroud assembly configured to be supported in an internal passage of the drill string. The rotary pulser includes a stator supported by the shroud assembly. The stator has an uphole end, a downhole end spaced from the uphole end, and at least one passage that extends from the uphole end to the downhole end. The rotary pulser also includes a rotatable element adjacent to the downhole end of the stator and rotatable to selectively obstruct the at least one passage to generate a pressure pulse in the fluid when the fluid passes through the rotary pulser. The rotary pulser also includes one or more bypass elements located along an outer region of the shroud assembly. The one or more fluid bypass elements are configured to permit fluid to bypass the stator and the rotatable element when a fluid passes through the drill string and the rotary pulser.

This summary is provided to introduce a selection of concepts in a simplified form that are further described below in the Description of the Invention section. This Summary is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used to limit the scope of the claimed subject matter. Furthermore, the claimed subject matter is not constrained to limitations that solve any or all disadvantages noted in any part of this disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

A more detailed understanding may be had from the following description, given by way of example in conjunction with the accompanying drawings, wherein:

FIG. 1 illustrates a side schematic view of a drilling system according to an embodiment of this disclosure;

FIG. 2 is schematic block diagram of a mud-pulse telemetry system used in the drilling system shown in FIG. 1;

FIG. 3 is a perspective view of a pulser assembly included in the drilling system shown in FIG. 1;

FIG. 4 is an end view of the pulser assembly shown in FIG. 3;

FIG. 5 is another end view of the pulser assembly shown in FIG. 3;

FIG. 6 is a cross sectional view a pulser assembly taken along line I-I in FIG. 3;

FIG. 7 is a top perspective view of a stator of the pulser assembly shown in FIG. 3; and

FIG. 8 is a bottom perspective view of a rotor of the pulser assembly shown in FIG. 3.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

Referring to FIG. 1, an embodiment of the present disclosure is a mud-pulse telemetry system 10 for operation in a drilling system 1. The drilling system 1 includes a rig or derrick (not shown) that supports a drill string 6, a bottomhole assembly (BHA) 7 forming a portion of the drill string 6, and a drill bit 2 coupled to the bottomhole assembly 7. The drill bit 2 is configured to drill a borehole 4 into the earthen formation 5 according to known methods of drilling. The mud-pulse telemetry system 10 is configured to transmit drilling information obtained in the bore 4 to the surface 3 during a drilling operation.

The mud-pulse telemetry system 10 includes a pulser 12, such as a rotary pulser, position at downhole end of 6, a measurement-while-drilling (MWD) tool 20 attached to or suspended within the drill string 6 and configured to obtain drilling information, and one or more components to all of the surface system 200. The mud-pulse telemetry system 10 transmits drilling information obtained by the MWD tool 20 to the surface 3, via the pulser 12, for processing and analysis by the surface system 200.

Continuing with FIG. 1, the drilling system 1 can include a surface motor (not shown) located at the surface 3 that applies torque to the drill string 6 via a rotary table or top drive (not shown) and a downhole motor (not shown), or “mud motor,” disposed along the drill string 6 and operably coupled to the drill bit 2. Operation of the surface and downhole motors causes the drill string 6 and drill bit 2 to rotate and drill into the formation 5. Further, during the drilling operation, a pump 16 pumps drilling fluid 18 downhole through an internal passage of the drill string 6 to the drill bit 2. The drilling fluid 18 exits the bit 2 and flows upward to the surface 3 through the annular passage between wall 11 of the bore 4 and the drill string 6, where, after cleaning, it is circulated back down the drill string 6 by the mud pump 16.

The drilling system 1 is configured to drill the borehole or well 4 into the earthen formation 5 along a vertical direction V and an offset direction O that is offset from or deviated from the vertical direction V. Although a vertical bore 4 is illustrated, the drilling system 1 and components thereof as described herein can be used for a directional drilling operations whereby a portion of the bore 4 is offset from the vertical direction V along the offset direction O. The drill string 6 is typically formed of sections of drill pipe joined end to end along a longitudinal central axis 13. The drill sting 6 is supported at its uphole end 19 by the Kelly or top drive and extends toward the drill bit 2 along a downhole direction D. The downhole direction D is the direction from the surface 3 toward the drill bit 2 while an uphole direction U is opposite to the downhole direction D. Accordingly, “downhole,” “downstream,” or similar words used in this description refers to a location that is closer toward the drill bit 2 than the surface 3, relative to a point of reference. “Uphole,” “upstream,” and similar words refers to a location that is closer to the surface 3 than the drill bit 2, relative to a point of reference.

Continuing with FIG. 1, the mud-pulse telemetry system 10 can include all or a portion of the MWD tool 20. The MWD tool 20 includes a plurality of sensors 8, an encoder 24, a power source 14, and a transmitter (or transceiver) for communication with the pulser 12. The MWD tool 20 can also include a controller having a processor and memory. The MWD tool 20 obtains drilling information via the sensors 8. Exemplary drilling information may include data indicative of the drilling direction of the drill bit 2, such as azimuth, inclination, and tool face angle. While MWD tool 20 is illustrated, a logging-while-drilling (LWD) tool may be used in combination with or in lieu of the MWD tool 20. The power source 14 can be a battery, a turbine alternator-generator, or a combination of both.

Continuing with FIG. 1, the mud-pulse telemetry system 10 can include one or more up to all of the components of the surface system 200. The surface system 200 includes one or more computing devices 210, a pressure sensor 212, and a pulser device 224. The pressure sensor 212 may be a transducer that senses pressure pulses in the drilling fluid 18. The pulser device 224, which may be a valve, is located at the surface 3 and is capable of generating pressure pulses in the drilling fluid 18. The surface system 200 can include any suitable computing device 210 configured to host software applications that process drilling data encoded in the pressure pulses and further monitor and analyze drilling operations based on the decoded drilling operation. The computing device includes a processing portion, a memory portion, an input/output portion, and a user interface (UI) portion. The input/output portions can include receivers and transceivers for detecting signals from the pressure sensor. Demodulators can be used to process received signals and are configured to demodulate received signals into drilling data that is stored in the memory portion for access by the processing portion as needed. It will be understood that the computing device 210 can include any appropriate device, examples of which include a desktop computing device, a server computing device, or a portable computing device, such as a laptop, tablet or smart phone.

Turning now to FIGS. 1 and 2, the pulser 12 is configured to transmit information obtained downhole to a location toward or at the surface. The pulser 12 may be carried in a flow sub (not shown) that itself forms part of the bottomhole assembly (BHA) or even the drill string. The flow sub includes typical threaded uphole and downhole connectors, such as pin box connecters, and an internal passage define by an inner surface of the sub body. The pulser assembly 22 may be coupled to and mounted in the internal passage of the sub body.

The pulser 12 the pulser assembly 22 and one or more bypass elements 412 (FIGS. 3-5) are arranged along and within a shroud assembly 300 (FIG. 3). The pulser assembly 22 itself includes a rotor 36 and a stator 38 contained with the shroud assembly 300. The pulser 12 also includes a controller 26, and a motor assembly 35 operably coupled to the pulser assembly 22. The pulser 12 is configured to cause the rotor 36 to rotate relative to the stator 38 between various rotational positions as drilling fluid 18 passes through pulser 12. Transition of rotor 36 through the different rotational positions generates pressure pulses 112 in the drilling fluid 18 which contain encoded drilling information.

Continuing with FIGS. 1 and 2, the motor assembly 35 includes a motor driver 30, a motor 32, switching device 40, and a reduction gear 46 coupled to a shaft 34. The shroud assembly 300 is supported by the inner surface of the drill string 6. The rotor 36 is coupled to shaft 34 and is further disposed adjacent to the stator 38 within the shroud assembly 300. The motor driver 30 receives power from the power supply 14 and directs power to the motor 32 using pulse width modulation or other signal processing techniques. In response to power supplied by the motor driver 30, the motor 32 drives the reduction gear 46 causing rotation of the shaft 34. Although only one reduction gear 46 is shown, two or more reduction gears could be used.

The pulser 12 may also include an orientation encoder 47 coupled to the motor 32. The orientation encoder 47 can monitor or determine angular orientation of the rotor 36. In response to determining the angular orientation of the rotor 36, the orientation encoder 47 directs a signal 114 (FIG. 2) to the controller 26 containing information concerning the angular orientation of the rotor 36. The controller 26 may use angular orientation information of the rotor 36 during operation of the pulser 12 to generate the motor control signals 106, which cause the rotational position of the rotor 36 to change as needed. Further, information from the orientation encoder 47 can be used to monitor the position of the rotor 36 during periods when the pulser 12 is not in operation. The orientation encoder 47 is of the type employing a magnet coupled to the motor shaft that rotates within a stationary housing in which Hall effect sensors are mounted that detect rotation of the magnetic poles of the magnet. The orientation encoder 47 should be suitable for high temperature operations typical in a downhole environment.

Operation of the pulser 12 to transmit drilling information to the surface 3 initiates with sensors 8 in the MWD tool 20 obtaining drilling information 100 useful in connection with the drilling operation. The MWD tool 20 provides output signals 102 to the data encoder 24. The data encoder 24 transforms the output signals 102 from the sensors 8 into digital signals 104 and transmits the signals 104 to the controller 26. In response to receiving the digital signals 104, the controller 26 directs operation of the motor assembly 35. For instance, the controller 26 directs signals 106 to the motor driver 30. The motor driver 30 receives power 107 from the power source 14 and directs power 108 to the switching device 40. The switching device 40 transmits power 111 to motor 32 so as to effect rotation of the rotor 36 in either a first rotational direction (e.g., clockwise) or a second rotational direction (e.g., counterclockwise) through a rotation cycle in order to generate pressure pulses 112 that are transmitted through the drilling fluid 18. The pressure pulses 112 are sensed by the sensor 212 at the surface 3 and the information is decoded by the surface computing device 210.

Referring to FIGS. 1 and 2, the mud-pulse telemetry system 10 can also include one or more downhole pressure sensors. For instance, the drill string 6 can include dynamic downhole pressure sensor 28 and a static downhole pressure sensor 29. The downhole pressure sensors 28 and 29 are configured to measure the pressure of the drilling fluid 18 in the vicinity of the pulser 12 as described in U.S. Pat. No. 6,714,138 (Turner et al.). The pressure pulses sensed by the dynamic pressure sensor 28 may be the pressure pulses 112 generated by the pulser 12 or the pressure pulses 116 generated by the surface pulser 224. In either case, the down hole dynamic pressure sensor 28 transmits a signal 115 to the controller 26 containing the pressure pulse information, which may be used by the controller 26 in generating the motor control signals 106 which cause or control operation of the motor assembly 35. The static pressure sensor 29, which may be a strain gage type transducer, transmits a signal 105 to the controller 26 containing information on the static pressure.

Turning to FIGS. 6-7, the pulser assembly 22 includes a stator 38 and rotatable element 36 as discussed above. The stator 38 has a stator body 70 that includes an uphole end 72, a downhole end 74 spaced from the uphole end 72 in the downhole direction D along a central axis 71, and at least one passage 76 that extends through the stator body 70 in the downhole direction D. The stator 38 may preferably include a plurality of passages 76. In accordance with the illustrated embodiment, the stator 38 includes eight passages 76 referred to in the art as an 8-port design. It should be appreciated that the stator 38 can include more or less than eight passages 76. For instance, the stator 38 can include four passages, referred to in the art as a 4-port design, or even fewer than four passages.

Continuing with FIGS. 6-7, the stator body 70 includes a hub 79a disposed along the central axis 71 and one or more vanes 79b that extend from the hub 79a to an outer radial rim 77a. The vanes 79b partially define each respective passage 76. In addition, the stator body 70 also defines an uphole surface 73 disposed at the uphole end 72, a downhole surface disposed at the downhole end 74, and an outer radial surface 77b spaced from the central axis 71 along the radial direction R. The radial surface 77b extends from the uphole surface 73 to the downhole surface 75. Each passage 76 extends from an uphole opening 82c aligned with uphole surface 73 to a downhole opening aligned with the downhole surface. Only one passage 76 will be described below for ease of illustration. While the passages are shown having a constricting cross-sectional shape, the passages can have a cross-sectional shape that does not vary significantly between the upstream side and downstream side, similar to the passages of the stator illustrated in U.S. Pat. No. 7,327,634 to Perry et al, incorporated herein by reference.

Turning now to FIG. 8, the pulser includes a rotatable element 36 shown in the form of a rotor 36. The rotor 36 includes a rotor body 88 having a central hub 89 and at least one blade (or a plurality of blades 90) that extend outwardly in the radial direction R. The number of blades 90 can correspond to the number of passages in the stator 38. The rotor 36 is configured to rotate relative to the stator 38 to generate pressure pulses as described herein.

Continuing with FIG. 8, each blade 90 includes a base 92 that extends from the central hub 89 in the radial direction R, and a rib 94 that extends from the base 92 along the longitudinal direction. The base 92 has an inner end disposed on the central hub 89 and an outer end spaced from the inner end 93i in along a radial axis 101 that is aligned with the radial direction R. The base 92 also defines a first lateral side 96a, a second lateral side 96b opposed to the first lateral side 96a, a downhole face portion 97 that extends between the first and second lateral sides 96a and 96b toward the rib 94, and an upstream surface 91 that is opposite the downhole face portion 97. The upstream surface faces downhole surface of stator 38. As illustrated, the rib 94 projects from the face portion 97.

Referring back to FIGS. 3-6, the shroud assembly 300 is configured to carry the pulser assembly 22 and permit drilling fluid to bypass the pulser assembly 22 during operation via one or more bypass elements 340. The bypass elements 340 are configured to permit fluid, such as drilling fluid, to bypass the rotary pulser, thereby allowing for a clean and crisp pressure pulses to be transmitted to the surface. The transition from when the pulser closes the fluid bypasses to ports 340 rather than flowing through the inlet plate ports 320 happens naturally and smoothly with very little turbulence, relative to a standard valve where all the flow goes through flow channel 320. Because of the lack of turbulence and resistive torque on the rotor by the fluid, the valve moves faster and smoother resulting in faster rise and fall of the pulse's edges. When closed the bulk of the flow goes through the bypass ports in a straight shot, rather than flowing around the gaps in the rotor. Since there is much less turbulence and the flow area is more consistent (no valve flutter, and most of the flow is not affected by the movement of the rotor) there is less variation, or noise in the created pulse. This creates a squarer pulse shape (sharper/crisper) with less noise when closed (cleaner) which is much easier to decode at the surface.

The bypass elements 340 may be fluid channels formed in the shroud assembly. In other examples the bypass elements 340 may be grooves formed in the shroud assembly and the inner surface of the flow sub. The bypass elements 340 may be any structure that can permit fluid to pass through it.

The shroud assembly 300 has a first housing 324 configured to support the stator 38 and a second housing 328 coupled to the first housing 324 along a longitudinal axis 71. The shroud assembly 300 itself includes an uphole end 312, a downhole end 316, and an internal passage 320 that extends from the uphole end 312 to the downhole end 316. The first housing 324 and a second housing 328 are coupled or fixed together. The first housing 324 has an internal dimension sized to receive the stator 38, the shaft 34, and other components of the pulser assembly. The second housing 328 partially envelopes a lower part of the first housing 324 and includes a housing body defining an outer wall 332. As shown, the outer wall 332 defines one or more fluid bypass elements 340 that extend in a generally longitudinal direction (uphole-downhole direction). This positions the fluid bypass elements 340, or fluid channels, generally in an outer region of the shroud assembly 300. In other words, the channels 340 are positioned around the central axis 71 of the assembly 300 and closer to the outer surface than to the internal central axis 71. In the example shown in the drawings, multiple fluid channels are positioned circumferentially around the shroud assembly 300.

The fluid channels 340 are sized and shaped to permit drilling fluid to pass therethrough. Each fluid channel has an uphole end 342 and a downhole end 344 spaced from the uphole end along a passage axis (not shown). In the example shown, the uphole end 342 of the one or more fluid channels 340 is positioned downhole from the downhole 78 end of the stator 38. Each of the fluid channels 340 may include a nozzle 348 located the downhole end 344. The nozzle 348 may be formed from carbide, which is highly resistant to wash via the drilling fluid. The nozzles 348 form the more restrictive section of the chancel and helps limit the amount of fluid erosion in the channel. The nozzles 348 may come in many different sizes to permit the user or installer to adjust the bypass flow area to optimize for flow rate pass and through the pulser 12. The fluid channels 340 are used to aid in allowing the drilling fluid to bypass the pulser assembly 22 during use.

During a drilling operation, the user can direct a drilling fluid through an elongated passage of the drill string in a downhole direction toward a rotary pulser. While a first portion of the drilling fluid passes through the rotary pulser, rotating the rotatable element from a first position, where the rotatable element permits the drilling fluid to pass through the at least one passage, to a second position, where the rotatable obstructs the drilling fluid through the at least one passage, thereby generating a pressure pulse in drilling fluid. The method also includes causing a portion of the drilling fluid to bypass the rotary pulser through one or more fluid channels located externally relative to the rotary pulser.

In use, the additional flow passages will allow for a smaller pulser valve to be used in very high flow rate situations. This significantly reduces the loads on the rotor, specifically the flow induced oscillations of the valve, often referred to as valve chatter, and greatly enhances the operational reliability. Without these passages, the need for adequate flow area to prevent the tool from experiencing severe erosion damage, would require larger valve ports 320. This in turn requires a larger rotor to cover that area to generate the pulse. A larger rotor experiences higher flow induced torque, both input torque to transition the rotor between open and closed, as well as the instabilities (i.e. signal chatter). And the increased diameter of the rotor also increased the mass moment of inertia, creating higher dynamic loads, the higher inertia resists acceleration of the valve (increasing the power needed to actuate the valve), and the higher mass creates higher shock loads (axial shock loads to the bearings, and torsional shocks from the chatter). Thus, a smaller rotor is desirable, especially at higher flow rates. By using a smaller rotor the ratio of open to closed area is lower, and therefore the pulse height generated is lower. By breaking the flow area into many smaller openings, we can take advantage of certain flow effects that cause the effective flow area to decrease when the speed through the nozzle increases. To get the lower operating stresses, a certain amount of pulse height may be sacrificed, but this is offset by the pulse generated being cleaner when using the pulser assembly as described herein.

While the disclosure is described herein using a limited number of embodiments, these specific embodiments are for illustrative purposes and are not intended to limit the scope of the disclosure as otherwise described and claimed herein. Modification and variations from the described embodiments exist. The scope of the invention is defined by the appended claims.