Rotary Pulser with Flow Bypass Elements

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

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.

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.

Referring to, an embodiment of the present disclosure is a mud-pulse telemetry systemfor operation in a drilling system. The drilling systemincludes a rig or derrick (not shown) that supports a drill string, a bottomhole assembly (BHA)forming a portion of the drill string, and a drill bitcoupled to the bottomhole assembly. The drill bitis configured to drill a boreholeinto the earthen formationaccording to known methods of drilling. The mud-pulse telemetry systemis configured to transmit drilling information obtained in the boreto the surfaceduring a drilling operation.

The mud-pulse telemetry systemincludes a pulser, such as a rotary pulser, position at downhole end of, a measurement-while-drilling (MWD) toolattached to or suspended within the drill stringand configured to obtain drilling information, and one or more components to all of the surface system. The mud-pulse telemetry systemtransmits drilling information obtained by the MWD toolto the surface, via the pulser, for processing and analysis by the surface system.

Continuing with, the drilling systemcan include a surface motor (not shown) located at the surfacethat applies torque to the drill stringvia a rotary table or top drive (not shown) and a downhole motor (not shown), or “mud motor,” disposed along the drill stringand operably coupled to the drill bit. Operation of the surface and downhole motors causes the drill stringand drill bitto rotate and drill into the formation. Further, during the drilling operation, a pumppumps drilling fluiddownhole through an internal passage of the drill stringto the drill bit. The drilling fluidexits the bitand flows upward to the surfacethrough the annular passage between wallof the boreand the drill string, where, after cleaning, it is circulated back down the drill stringby the mud pump.

The drilling systemis configured to drill the borehole or wellinto the earthen formationalong a vertical direction V and an offset direction O that is offset from or deviated from the vertical direction V. Although a vertical boreis illustrated, the drilling systemand components thereof as described herein can be used for a directional drilling operations whereby a portion of the boreis offset from the vertical direction V along the offset direction O. The drill stringis typically formed of sections of drill pipe joined end to end along a longitudinal central axis. The drill stingis supported at its uphole endby the Kelly or top drive and extends toward the drill bitalong a downhole direction D. The downhole direction D is the direction from the surfacetoward the drill bitwhile 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 bitthan the surface, relative to a point of reference. “Uphole,” “upstream,” and similar words refers to a location that is closer to the surfacethan the drill bit, relative to a point of reference.

Continuing with, the mud-pulse telemetry systemcan include all or a portion of the MWD tool. The MWD toolincludes a plurality of sensors, an encoder, a power source, and a transmitter (or transceiver) for communication with the pulser. The MWD toolcan also include a controller having a processor and memory. The MWD toolobtains drilling information via the sensors. Exemplary drilling information may include data indicative of the drilling direction of the drill bit, such as azimuth, inclination, and tool face angle. While MWD toolis illustrated, a logging-while-drilling (LWD) tool may be used in combination with or in lieu of the MWD tool. The power sourcecan be a battery, a turbine alternator-generator, or a combination of both.

Continuing with, the mud-pulse telemetry systemcan include one or more up to all of the components of the surface system. The surface systemincludes one or more computing devices, a pressure sensor, and a pulser device. The pressure sensormay be a transducer that senses pressure pulses in the drilling fluid. The pulser device, which may be a valve, is located at the surfaceand is capable of generating pressure pulses in the drilling fluid. The surface systemcan include any suitable computing deviceconfigured 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 devicecan 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, the pulseris configured to transmit information obtained downhole to a location toward or at the surface. The pulsermay 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 assemblymay be coupled to and mounted in the internal passage of the sub body.

The pulserthe pulser assemblyand one or more bypass elements() are arranged along and within a shroud assembly(). The pulser assemblyitself includes a rotorand a statorcontained with the shroud assembly. The pulseralso includes a controller, and a motor assemblyoperably coupled to the pulser assembly. The pulseris configured to cause the rotorto rotate relative to the statorbetween various rotational positions as drilling fluidpasses through pulser. Transition of rotorthrough the different rotational positions generates pressure pulsesin the drilling fluidwhich contain encoded drilling information.

Continuing with, the motor assemblyincludes a motor driver, a motor, switching device, and a reduction gearcoupled to a shaft. The shroud assemblyis supported by the inner surface of the drill string. The rotoris coupled to shaftand is further disposed adjacent to the statorwithin the shroud assembly. The motor driverreceives power from the power supplyand directs power to the motorusing pulse width modulation or other signal processing techniques. In response to power supplied by the motor driver, the motordrives the reduction gearcausing rotation of the shaft. Although only one reduction gearis shown, two or more reduction gears could be used.

The pulsermay also include an orientation encodercoupled to the motor. The orientation encodercan monitor or determine angular orientation of the rotor. In response to determining the angular orientation of the rotor, the orientation encoderdirects a signal() to the controllercontaining information concerning the angular orientation of the rotor. The controllermay use angular orientation information of the rotorduring operation of the pulserto generate the motor control signals, which cause the rotational position of the rotorto change as needed. Further, information from the orientation encodercan be used to monitor the position of the rotorduring periods when the pulseris not in operation. The orientation encoderis 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 encodershould be suitable for high temperature operations typical in a downhole environment.

Operation of the pulserto transmit drilling information to the surfaceinitiates with sensorsin the MWD toolobtaining drilling informationuseful in connection with the drilling operation. The MWD toolprovides output signalsto the data encoder. The data encodertransforms the output signalsfrom the sensorsinto digital signalsand transmits the signalsto the controller. In response to receiving the digital signals, the controllerdirects operation of the motor assembly. For instance, the controllerdirects signalsto the motor driver. The motor driverreceives powerfrom the power sourceand directs powerto the switching device. The switching devicetransmits powerto motorso as to effect rotation of the rotorin 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 pulsesthat are transmitted through the drilling fluid. The pressure pulsesare sensed by the sensorat the surfaceand the information is decoded by the surface computing device.

Referring to, the mud-pulse telemetry systemcan also include one or more downhole pressure sensors. For instance, the drill stringcan include dynamic downhole pressure sensorand a static downhole pressure sensor. The downhole pressure sensorsandare configured to measure the pressure of the drilling fluidin the vicinity of the pulseras described in U.S. Pat. No. 6,714,138 (Turner et al.). The pressure pulses sensed by the dynamic pressure sensormay be the pressure pulsesgenerated by the pulseror the pressure pulsesgenerated by the surface pulser. In either case, the down hole dynamic pressure sensortransmits a signalto the controllercontaining the pressure pulse information, which may be used by the controllerin generating the motor control signalswhich cause or control operation of the motor assembly. The static pressure sensor, which may be a strain gage type transducer, transmits a signalto the controllercontaining information on the static pressure.

Turning to, the pulser assemblyincludes a statorand rotatable elementas discussed above. The statorhas a stator bodythat includes an uphole end, a downhole endspaced from the uphole endin the downhole direction D along a central axis, and at least one passagethat extends through the stator bodyin the downhole direction D. The statormay preferably include a plurality of passages. In accordance with the illustrated embodiment, the statorincludes eight passagesreferred to in the art as an 8-port design. It should be appreciated that the statorcan include more or less than eight passages. For instance, the statorcan include four passages, referred to in the art as a 4-port design, or even fewer than four passages.

Continuing with, the stator bodyincludes a hubdisposed along the central axisand one or more vanesthat extend from the hubto an outer radial rimThe vanespartially define each respective passage. In addition, the stator bodyalso defines an uphole surfacedisposed at the uphole end, a downhole surface disposed at the downhole end, and an outer radial surfacespaced from the central axisalong the radial direction R. The radial surfaceextends from the uphole surfaceto the downhole surface. Each passageextends from an uphole openingaligned with uphole surfaceto a downhole opening aligned with the downhole surface. Only one passagewill 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, the pulser includes a rotatable elementshown in the form of a rotor. The rotorincludes a rotor bodyhaving a central huband at least one blade (or a plurality of blades) that extend outwardly in the radial direction R. The number of bladescan correspond to the number of passages in the stator. The rotoris configured to rotate relative to the statorto generate pressure pulses as described herein.

Continuing with, each bladeincludes a basethat extends from the central hubin the radial direction R, and a ribthat extends from the basealong the longitudinal direction. The basehas an inner end disposed on the central huband an outer end spaced from the inner endin along a radial axisthat is aligned with the radial direction R. The basealso defines a first lateral sidea second lateral sideopposed to the first lateral sidea downhole face portionthat extends between the first and second lateral sidesandtoward the rib, and an upstream surfacethat is opposite the downhole face portion. The upstream surface faces downhole surface of stator. As illustrated, the ribprojects from the face portion.

Referring back to, the shroud assemblyis configured to carry the pulser assemblyand permit drilling fluid to bypass the pulser assemblyduring operation via one or more bypass elements. The bypass elementsare 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 portsrather than flowing through the inlet plate portshappens naturally and smoothly with very little turbulence, relative to a standard valve where all the flow goes through flow channel. 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 elementsmay be fluid channels formed in the shroud assembly. In other examples the bypass elementsmay be grooves formed in the shroud assembly and the inner surface of the flow sub. The bypass elementsmay be any structure that can permit fluid to pass through it.

The shroud assemblyhas a first housingconfigured to support the statorand a second housingcoupled to the first housingalong a longitudinal axis. The shroud assemblyitself includes an uphole end, a downhole end, and an internal passagethat extends from the uphole endto the downhole end. The first housingand a second housingare coupled or fixed together. The first housinghas an internal dimension sized to receive the stator, the shaft, and other components of the pulser assembly. The second housingpartially envelopes a lower part of the first housingand includes a housing body defining an outer wall. As shown, the outer walldefines one or more fluid bypass elementsthat extend in a generally longitudinal direction (uphole-downhole direction). This positions the fluid bypass elements, or fluid channels, generally in an outer region of the shroud assembly. In other words, the channelsare positioned around the central axisof the assemblyand closer to the outer surface than to the internal central axis. In the example shown in the drawings, multiple fluid channels are positioned circumferentially around the shroud assembly.

The fluid channelsare sized and shaped to permit drilling fluid to pass therethrough. Each fluid channel has an uphole endand a downhole endspaced from the uphole end along a passage axis (not shown). In the example shown, the uphole endof the one or more fluid channelsis positioned downhole from the downholeend of the stator. Each of the fluid channelsmay include a nozzlelocated the downhole end. The nozzlemay be formed from carbide, which is highly resistant to wash via the drilling fluid. The nozzlesform the more restrictive section of the chancel and helps limit the amount of fluid erosion in the channel. The nozzlesmay 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. The fluid channelsare used to aid in allowing the drilling fluid to bypass the pulser assemblyduring 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. 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.