Patent Publication Number: US-9416592-B2

Title: Generating fluid telemetry

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application is a continuation of, and claims priority under 35 U.S.C. §120 to, U.S. National Phase application Ser. No. 13/386,072 filed on Jan. 20, 2012, which is set to issue on Aug. 20, 2013 as U.S. Pat. No. 8,514,657, which in turn claims priority from International Application Serial No. PCT/US2009/051516, filed on Jul. 23, 2009. The International Application was published on Jan. 27, 2011 as International Publication No. WO 2011/011005 A1 under PCT Article 21(2). The contents of the above applications are incorporated herein by reference in their entirety. 
    
    
     TECHNICAL BACKGROUND 
     This disclosure relates to mud pulse telemetry for transmitting data from within a wellbore. 
     BACKGROUND 
     Drilling operations often rely on measured data indicative of wellbore conditions to adjust or modify an ongoing or current operation. For example, wellbore data, such as data indicative of a drilling fluid (i.e., a drilling “mud”), one or more subterranean zones, one or more components of a downhole drilling apparatus, or other information, may be used in determining drilling direction, drilling speed, or operation characteristics, to name but a few examples. For instance, one technique for obtaining wellbore data measured in a drilled borehole is the use of a measurement-while-drilling (“MWD”) telemetry system. As another example, measured data from logging-while-drilling (“LWD”) systems is often transmitted to the surface by a fluid, or mud, telemetry system. In such systems, data measured in the borehole, such as data measured by sensors or transducers positioned within a downhole drilling apparatus, may be transmitted to a surface detector while drilling is in progress by varying one or more characteristics of the drilling fluid used in the drilling operation. In short, such systems may include one or more components that relay the measured information to the surface through a column of drilling fluid within the borehole which extends from the bottom of the borehole to the surface during drilling. 
    
    
     
       DESCRIPTION OF DRAWINGS 
         FIG. 1  illustrates a drilling assembly including one embodiment of a mud pulser in accordance with the present disclosure; 
         FIG. 2  illustrates a sectional view of one embodiment of a mud pulser in accordance with the present disclosure; 
         FIG. 3A  illustrates a sectional view of one embodiment of a mud pulser utilizing a turbine arrangement in accordance with the present disclosure; and 
         FIG. 3B  illustrates a sectional view of another embodiment of a mud pulser utilizing a progressive cavity, or Moineau, arrangement in accordance with the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     In one general embodiment, a downhole tool includes a tool body, a stator, and a rotor. The tool body is aligned longitudinally along a centerline of the tool, where the tool body includes at least one aperture therethrough that is operable to pass a fluid to an exterior of the body. The stator is fixed relative to the tool body and includes at least one fluid flow restriction that is operable to pass at least a portion of the fluid from an interior of the stator to the exterior of the body at an adjustable flow rate. The rotor is disposed within the tool body and rotatable relative to the stator, where the rotor includes at least one exhaust port selectively aligned with at least one aperture through the tool body by rotation of the rotor relative to the stator. The exhaust port is operable to pass at least a portion of the fluid from an interior of the rotor to the aperture and to the exterior of the body when aligned with the aperture. 
     In more specific embodiments, the restriction may include at least one valve disposed at an outlet of the stator, where the valve may receive the fluid passing through the stator. The valve may include one of a knife valve, a needle valve, or a gate valve. Further, at least a portion of the stator may be disposed in the interior of the rotor. The rotor may include an inner surface and the stator may include an outer surface. The inner surface may be adjacent and substantially parallel to the outer surface, where the inner and outer surfaces include a fluid interface between the rotor and the stator. The fluid interface may include a turbine, where the turbine receives fluid therethrough and rotates the rotor relative to the stator. In some aspects, the fluid interface may include a lobed interface, where the lobed interface receives fluid therethrough and rotates the rotor relative to the stator. In addition, the fluid interface may receive the fluid therethrough to rotate the rotor relative to the stator at an adjustable angular speed. The angular speed may be adjusted by throttling the restriction to vary a flow rate of fluid. 
     In certain embodiments, the tool body may further include a clutch, where the clutch adjusts an angular speed of the rotor relative to the stator based on a received signal indicative of a measured drilling value. The clutch may adjust the rotor between a first angular speed and a second angular speed, where the first angular speed may be substantially equal to zero revolutions per minute and the second angular speed is greater than the first angular speed. In some aspects, the tool may receive the fluid from a terranean surface, where the fluid passes to the exterior of the tool body from at least one of the restriction and the aperture and returned to the terranean surface in an annulus between the downhole tool and a wellbore. Further, at least one of selective alignment of the exhaust port with the aperture and adjustment of the flow rate may generate varying amplitudes of a pressure of the fluid. The at least one restriction may further include a first valve and the adjustable flow rate may be a first adjustable flow rate, where the stator may include a second valve allowing the fluid to pass to the exterior of the body at a second adjustable flow rate. 
     In another general embodiment, a method for generating mud pulse telemetry includes: receiving a fluid from a terranean surface at a downhole tool including a tool body; directing the fluid through an interior of the tool body and between a rotor and stator disposed within the tool body; adjusting a rotation of the rotor to align at least one exhaust port through the rotor with a corresponding aperture through the tool body to direct at least a portion of the fluid from the interior of the tool body to an exterior of the tool body; directing the fluid through the stator to an outlet of the stator, the outlet includes an adjustable restriction; and adjusting the restriction to vary passage of at least a portion of the fluid from the interior of the tool body to the exterior of the tool body from the outlet. 
     In some specific embodiments, the method may further include passing at least a portion of the fluid between the rotor and stator to generate rotation of the rotor relative to the stator. Further, at least one of adjusting rotation of the rotor to align at least one exhaust port through the rotor with a corresponding aperture through the tool body to direct at least a portion of the fluid to an exterior of the tool body from the interior of the tool body and adjusting the restriction to allow at least a portion of the fluid to pass to the exterior of the tool body from the outlet may include adjusting an amplitude of pressure of the fluid received from the terranean surface. At least one of adjusting rotation of the rotor to align at least one exhaust port through the rotor with a corresponding aperture through the tool body to direct at least a portion of the fluid to an exterior of the tool body from the interior of the tool body and adjusting the restriction to allow at least a portion of the fluid to pass to the exterior of the tool body from the outlet may include adjusting a frequency of pressure of the fluid received from the terranean surface. 
     In certain embodiments, the method may further include receiving at least one signal indicative of a measured drilling value; and adjusting, based on the at least one signal, at least one of rotation of the rotor and the restriction. Adjusting, based on the at least one signal, at least one of rotation of the rotor and the restriction may include adjusting a pressure of the fluid received from the terranean surface. The method may further include measuring, adjacent the terranean surface, the adjusted pressure of the fluid; and determining the measured drilling value based on the adjusted pressure. Adjusting, based on the at least one signal, at least one of rotation of the rotor and the restriction may also include adjusting a frequency of a fluid pressure of the fluid received from the terranean surface. The method may further include measuring, adjacent the terranean surface, the adjusted frequency of the fluid pressure of the fluid; and determining the measured drilling value based on the adjusted frequency. 
     In specific embodiments, receiving a fluid from a terranean surface may include receiving a fluid from a terranean surface at a first flow rate and the method may further include receiving the fluid from the terranean surface at a second flow rate distinct from the first flow rate; and adjusting the restriction based on a difference between the first flow rate and the second flow rate. In addition, adjusting a rotation of the rotor may include holding the rotor at a first fixed position, where the exhaust port may be misaligned with the corresponding aperture at the first fixed position; based on the rotor at the first fixed position, directing the fluid through a standpipe disposed through at least a portion of the stator; adjusting the rotor from the first fixed position to a second fixed position, where the exhaust port may be at least partially aligned with the corresponding aperture at the second fixed position; and based on the rotor at the second fixed position, directing at least a portion of the fluid to the exterior of the tool body from the interior of the tool body. 
     In another general embodiment, a system includes a drill string and a mud pulser. The drill string includes a drill bit; a sensor section; and a downhole measurement tool. The mud pulser is coupled to the drill string and includes a housing including a plurality of apertures therethrough; a first element disposed within the housing and fixed relative to the housing, where the first element is operable to direct a variable portion of the drilling fluid through the first element to an exterior of the housing; and a second element disposed within the housing and rotatable relative to the housing based on a flow of drilling fluid received between the first and second elements. The second element includes a plurality of exhaust ports operable to be selectively aligned with the plurality of apertures by rotation of the second element to direct a portion of the drilling fluid from an interior of the second element to the exterior of the housing. In specific embodiments, the mud pulser may receive the drilling fluid at a first pressure, where the drilling fluid may be adjusted to a second pressure based on at least one of directing a varying portion of the drilling fluid through the first element to an exterior of the housing and alignment of the plurality of exhaust ports with the plurality of apertures by rotation of the second element to direct a portion of the drilling fluid from an interior of the second element to the exterior of the housing. The system may further include a speed adjustment module coupled to at least one of the housing and the second element, where the speed adjustment module may control an angular speed of the second element relative to the housing. 
     In certain embodiments of the system, the downhole measurement tool may be communicatively coupled to the speed adjustment module and may detect a plurality of drilling values. The speed adjustment module may control the angular speed of the second element relative to the housing based on the plurality of drilling values. The plurality of drilling values may include at least two of a well bore pressure; a resistivity of the drilling fluid; a conductivity of the drilling fluid; a temperature of the drilling fluid; a resistivity of a subterranean formation; a conductivity of the subterranean formation; a density of the subterranean formation; and a porosity of the subterranean formation. 
     Various embodiments of a mud pulser according to the present disclosure may include one or more of the following features. For example, in some embodiments, the mud pulser may generate a negative mud pulse pressure signal to transmit measured borehole data to a surface or sub-surface location. Further, the mud pulser may be powered predominantly by a drilling mud pumped downhole into the wellbore. The mud pulser may provide for variable pressure amplitude for mud pulse telemetry. The mud pulser may also provide for variable pressure frequency for mud pulse telemetry. The mud pulser may also provide an inverted mud motor or turbine design thereby allowing for easier flow of the drilling mud through the pulser as well as control of the rotating element therein. In addition, the mud pulser may include multiple exhaust ports allowing drilling mud to be selectively exhausted from the pulser, thereby allowing for an increased data rate of mud pulse telemetry. In some embodiments, the mud pulser may allow for downhole adjustment for varying drilling mud flow rates by one or more adjustable restrictions, or valves, as well as the multiple exhaust ports. 
     Various embodiments of a mud pulser according to the present disclosure may also include one or more of the following features. For example, the mud pulser may allow for a less complex construction and assembly as compared to traditional mud pulse telemetry techniques and devices. For example, in some embodiments, one or more signal-carrying media (e.g., wires) may be coupled to a non-rotating component of the mud pulser, thereby decreasing electrical failures. Further, the mud pulser may include a multi-step control regime, such that multiple pressure amplitudes of the drilling fluid may be generated. For example, the multiple exhaust ports and/or restrictions may be controlled in parallel or in series to fluctuate the fluid pressure of the drilling fluid, thereby increasing telemetry rates. Other advantages and features of the mud pulser in accordance with the present disclosure will be apparent from the figures and the description. 
       FIG. 1  illustrates a drilling assembly  10  including one embodiment of a mud pulser  100  in accordance with the present disclosure. The illustrated drilling assembly  10  includes a drilling rig  15  located at a terranean surface  12  and supporting a drill string (or pipe)  35 . The drill string  35  is generally disposed through a rotary table  25  and into a wellbore  30  that is being drilled through a subterranean zone  45 . An annulus  40  is defined between the drill string  35  and the wellbore  30 . In some embodiments, at least a portion of the wellbore  30  may be cased. For example, drilling assembly  10  may include a casing  32  cemented in place within the wellbore  30 . The casing  32  (e.g., steel, fiberglass, or other material, as appropriate) may extend through all or a portion of the subterranean zone  45 . 
     Generally, subterranean zone  45  may include a hydrocarbon (e.g., oil, gas) bearing formation, such as shale, sandstone, or coal, to name but a few examples. In some embodiments, the subterranean zone  45  may include a portion or all of one or multiple geological formations beneath the terranean surface  12 . For example, the drill string  35  may be disposed through multiple subterranean zones and at multiple angles. Although  FIG. 1  illustrates a directional wellbore  30 , the present disclosure contemplates and includes a vertically-drilled wellbore and multiple types of directionally-drilled wellbores, such as high angle wellbores, horizontal wellbores, articulated wellbores, or curved wellbores (e.g., a short or long radius wellbore). In short, the wellbore  30  may be a vertical borehole or deviated borehole or may include varying sections of vertical and deviated boreholes. 
     In some embodiments, the drill string  35  may include a kelly  20  at an upper end, as illustrated in  FIG. 1 . The drill string  35  may be coupled to the kelly  20 , and a bottom hole assembly (“BHA”)  50  may be coupled to a downhole end of the drill string  35 . The BHA  50  typically includes one or more drill collars  55 , a downhole measurement tool  60  (e.g., MWD or LWD), and a drill bit  70  for penetrating through earth formations to create the wellbore  30 . In one embodiment, the kelly  20 , the drill string  35  and the BHA  50  may be rotated by the rotary table  25 . Alternatively, rotation may be imparted to one or more of the components of the drilling assembly  10  by a top direct drive system. 
       FIG. 1  shows one configuration including the BHA  50 , which may be rotated by a downhole motor driven by, for example, electrical power or a flow of drilling fluid. In some embodiments, the BHA  50  may include the downhole mud motor used to provide rotational power to the BHA  50 . Drill collars  55  may be used to add weight on the drill bit  70  and to stiffen the BHA  50 , thereby allowing the BHA  50  to transmit weight to the drill bit  70  without buckling or experiencing a structural failure. The weight applied through the drill collars  55  to the bit  70  may allow the drill bit  70  to cut material in the subterranean zone  45 , thereby creating the wellbore  30  in the zone  45 . 
     As the drill bit  70  operates, drilling fluid or “mud” is pumped from the terranean surface  12  through a conduit coupled to a mud pump  80  to the kelly  20 . The drilling fluid is then transmitted into the drill string  35 , through the BHA  50  and eventually to the drill bit  70 . The drilling fluid is discharged from the drill bit  70  and, typically, cools and lubricates the drill bit  70  and transports at least a portion of rock or earth cuttings made by the bit  70  to the terranean surface  12  via the annulus  40 . The drilling fluid is then often filtered and reused by pumping it back through the drill string  35 . 
     In general, this recirculating column of drilling fluid flowing through the drill string  35  may also provide a medium for transmitting pressure pulse acoustic wave signals, carrying information from the BHA  50  to the surface  12 . In certain embodiments, such signals may be representative of one or more wellbore characteristics or measured values that may be gathered by a sensor section  65  (or other measurement devices) located in the BHA  50 . The sensor section  65  may include one or multiple sensors or transducers mounted in the section  65  that measure a variety of downhole conditions and generate electrical signals representative of such conditions. Generally, such sensors and transducers may be specific to the drilling operation and/or the downhole measurement tool  60  and may measure such conditions as: location of the drill bit  70 ; rotational speed of the drill bit  70 ; a downhole pressure; a temperature, resistivity or conductivity of the drilling fluid; a temperature, resistivity, density, porosity, or conductivity of one or more subterranean zones, as well as various other downhole conditions. 
     The downhole measurement tool  60  may be located as close to the drill bit  70  as practical. Signals representing information from the sensor section  65 , as described above, may be generated and stored in the downhole measurement tool  60 . For example, the signals representative of data may be stored in the downhole measurement tool  60  and retrieved at the surface  12  when drilling operations are completed. Alternatively, or additionally, some or all of the signals may be transmitted in the form of mud pulses (e.g., varying pressures of the drilling fluid) upward through the drill string  35 . Further, some or all of the signals may be transmitted as mud pulses upward through the annulus  40 . A pressure pulse traveling in the column of drilling fluid within the drill string  35  (or annulus  40 ) may be detected at the surface  12  by a telemetry detector  75 . Such signals received by the telemetry detector  75  may be decoded at the detector  75  and/or at a remote processing system (not shown). 
     The BHA  50  also includes a mud pulser  100  to selectively interrupt or obstruct the flow of drilling fluid through the drill string  35 , and thereby produce pressure pulses at varying amplitudes and/or frequencies. In illustrated embodiments, as shown and described with reference to  FIGS. 2 and 3A -B, the mud pulser  100  may include an inverted mud motor or turbine design with a stationary stator disposed within a rotor that is selectively rotated relative to the stator and pulser body to interrupt or obstruct, or conversely exhaust, the flow of drilling fluid through the pulser  100 . The rotor and stator of the mud pulser  100  are distinct from, for example, a rotor/stator combination that may be included within a downhole mud motor included in the drilling assembly  10 . In the illustrated embodiments, the pulser  100  may also include one or more restrictions therethrough to throttle (e.g., obstruct or interrupt) the drilling fluid as it flows through the stator portion of the pulser  100 . Thus, the combination or selective operation of the rotor and restrictions may allow for multiple levels of control to achieve various pressure adjustments (e.g., amplitude, frequency) in the pressure of the drilling fluid as measured by the telemetry detector  75 . 
       FIG. 2  illustrates a sectional view of one embodiment of a mud pulser  200  in accordance with the present disclosure. In some embodiments, the mud pulser  200  may be used as the mud pulser  100  described with reference to the drilling assembly  10  of  FIG. 1 . As illustrated, the mud pulser  200  includes a body  120 , a rotor  110  disposed within an interior cavity defined by the body  120 , and a stator  130  disposed within the interior cavity of the body  120 . As shown, the rotor  110  is disposed between the stator  130  and the body  120 . The mud pulser  200  also includes one or more bearings  150  disposed between the rotor  110  and the body  120 . As shown, the mud pulser  200  is inserted into a wellbore, such as the wellbore  30 , and receives a drilling fluid  105  from an uphole portion of the wellbore  30 . 
     The illustrated mud pulser body  120  may be constructed of an appropriate material able to operate in a downhole environment. For example, the body  120  is generally rigid and able to withstand the corrosive effects of, for instance, the drilling fluid  105  as it flows in contact with the body  120 . As illustrated, the body  120  includes one or more apertures  125  disposed through the body  120  and allowing fluid communication between the interior of the mud pulser  200  and the annulus  40 . Generally, such apertures  125  allow the drilling fluid  105  to be selectively and controllably exhausted from the mud pulser  200  into the annulus  40 , thereby adjusting, at least in part, the drilling fluid pressure. Although two apertures  125  are illustrated, more or less apertures may be formed through the body  120  as appropriate. In addition, the body  120  is coupled (threadingly or otherwise) to other components of the drill string and may be fixed against rotation relative to the drill string. 
     The rotor  110  is disposed within the body  120  and, generally, may freely rotate relative to the body  120  and the stator  130  as the drilling fluid  105  is pumped through the mud pulser  200 . While rotating or stationary, the rotor  110  may be supported by one or more bearings  150  situated between the body  120  and the rotor  110 . The bearings  150  may, in some embodiments, be sealed bearings. Alternatively, the bearings  150  may be unsealed or compensated bearings, or may also be radial bearings that may withstand thrust loads placed on the rotor  110 , the body  120 , or other components of the mud pulser  200 . In any event, the bearings  150  typically are resistant to any corrosive effects of the drilling fluid  105  and allow the rotor  110  to achieve rotation without directly contacting the body  120  or the stator  130 . 
     The rotor  110 , as shown, includes one or more exhaust ports  115  disposed though an upper portion of the rotor  110 . Such exhaust ports  115  may be selectively aligned with the apertures  125  in the mud pulser  200 . For example, the exhaust ports  115  and apertures  125  may be identical or substantially similar in shape and area. Alternatively, the exhaust ports  115  may be larger or smaller than the apertures  125 . In any event, the exhaust ports  115  of the rotor  110  may allow for fluid communication through the apertures  125  and to the annulus  40  upon rotational alignment of the ports  115  with corresponding apertures  125 . Thus, at least a portion of the drilling fluid  105  may be directed to the annulus  40  rather than, for example, through a standpipe  135  disposed through the stator  130 . 
     In some embodiments, an interface between the rotor  110  and the body  120  may include one or more “shear” valve characteristics. For instance, adjacent surfaces of the rotor  110  and the body  120  may be highly polished metal surfaces, thereby fitting tightly together. Thus, a pressure differential across the gap between such surfaces may be very high (e.g., 2500 psi), thereby substantially preventing the drilling fluid  105  from entering the gap between the rotor  110  and body  120  from the exhaust ports  115  or apertures  125 . 
     The stator  130  is disposed within at least a portion of the rotor  110  and in the interior cavity defined by the body  120 . As illustrated, the stator  130  is affixed to the body  120  and is stationary relative to the body  120 . Thus, as shown, the mud pulser  200  includes an inverted mud motor design such that an interior element (e.g., the stator  130 ) is fixed and an exterior element (e.g., the rotor  110 ) rotates upon the pumping of drilling fluid  105  through the mud pulser  200 . 
     As shown, the stator  130  includes a flared portion affixed to the body  120 , thereby creating a rigid connection to the body  120 . A reduced diameter portion of the stator  130  adjacent the rotor  110  is coupled to the flared portion and includes the standpipe  135  disposed therethrough. In some embodiments, the reduced-diameter portion is coupled to the flared portion by a flex shaft  155 . For instance, as described below with reference to  FIGS. 3A-B , the mud pulser  200  may include a turbine arrangement or, alternatively, a progressive cavity (e.g., Moineau) arrangement. In a progressive cavity arrangement, the flex shaft  155  may allow for the reduced-diameter portion of the stator  130  to move radially around its longitudinal axis or, in other words, “wobble,” without rotating about its axis. Such movement may allow for proper operation of the stator/rotor combination as the drilling fluid  105  is pumped through the mud pulser  200 . In a mud motor, or turbine, arrangement, the flex shaft  155  may be substantially rigid and, thus, the stator  130  may not wobble as the drilling fluid  105  is pumped through the mud pulser  200 . Further, in some embodiments including a mud motor, or turbine, arrangement, the rotor  110  and stator  130  may include reverse-pitch blades on one or both of the rotor and stator in order to, for instance, improve turbine performance. 
     In some embodiments, as shown in  FIG. 2 , the stator  130  includes an outer surface  140  and the rotor  110  contains an inner surface  145  adjacent the outer surface  140  that cooperate to cause the rotor  110  to rotate about its longitudinal axis with respect to the stator  130  in response to fluid flow between the rotor  110  and stator  130 . The interface between the inner surface  140  and the outer surface  145  may depend, for example, on the arrangement of mud pulser  200  as a turbine design or a progressive cavity (or Moineau) design. For instance, turning to  FIG. 3A , a sectional view of one embodiment of a mud pulser  300  utilizing a turbine arrangement is illustrated. The mud pulser  300  includes a body  320 , a rotor  310 , a stator  330 , and one or more bearings  350  disposed between the body  320  and the rotor  310 . Generally, the components of the mud pulser  300  may be substantially similar to those described above with respect to the mud pulser  200 . As illustrated in  FIG. 3A , in a turbine arrangement, the rotor  310  and the stator  330  may include a contoured inner surface  312  and a contoured outer surface  332 , respectively. Such contoured surfaces  312  and  332  may include channels disposed longitudinally on the rotor  310  and stator  330 , thereby allowing the drilling fluid  105  to flow therein. As the drilling fluid  105  flows across the contoured surfaces  312  and  332 , the rotor  310  rotates about the stator  330  and relative to the body  320 . In such fashion, the rotor  310  may be rotated such that exhaust ports (not shown) may be aligned with corresponding apertures of the body  320 . 
     Turning to  FIG. 3B , a sectional view of another embodiment of a mud pulser  400  utilizing a progressive cavity, or Moineau, arrangement is illustrated. The mud pulser  400  includes a body  420 , a rotor  410 , a stator  430 , and one or more bearings  450  disposed between the body  420  and the rotor  410 . Generally, the components of the mud pulser  400  may be substantially similar to those described above with respect to the mud pulser  200  and/or mud pulser  300 . As illustrated in  FIG. 3B , in a progressive cavity, or Moineau, arrangement, the rotor  410  and the stator  430  may include a lobed inner surface  412  and a lobed outer surface  432 , respectively. Such lobed surfaces  412  and  432  may provide an interface through which the drilling fluid  105  may flow between the rotor  410  and stator  430 . As the drilling fluid  105  flows between the lobed surfaces  412  and  432 , the rotor  410  rotates about the stator  430  and relative to the body  420 . In such fashion, the rotor  410  may be rotated such that exhaust ports (not shown) may be aligned with corresponding apertures of the body  420 . 
     Returning to  FIG. 2 , the mud pulser  200  may also include a standpipe valve  165  arranged at an outlet of the standpipe  135  disposed through the stator  130 . In some embodiments, the standpipe valve  165  may be attached to or coupled with the stator  130  (or another non-rotating portion of the pulser  200 ) and removable, such as when servicing the mud pulser  200 . Alternatively, the standpipe valve  165  may be formed integral with the stator  130  in a one-piece arrangement. Generally, the standpipe valve  165  provides a variable restriction to flow of the drilling fluid  105  through the standpipe  135  and restrict at least a portion of the drilling fluid  105  as it flows to one or more tools downhole of the mud pulser  200 , such as the drill bit  70 . In certain instances, the standpipe valve  165  may be adjusted to provide a greater or less restriction on the standpipe  135  based on, for example, measured downhole values detected by one or more sensors, or the sensor section  65  for instance. By adjusting the restriction of the standpipe valve  165 , more or less drilling fluid  105  may be restricted, thereby adjusting the pressure of the drilling fluid  105  at or near the terranean surface  12 . In some embodiments, adjustments of the pressure of the drilling fluid  105  may be monitored at the terranean surface  12  and decoded to determine one or more drilling variables, downhole data (e.g., pressure, temperature), drilling measurement data, or other types of information. As adjustments are made in the pressure of the drilling fluid  105  by the mud pulser  200  at faster rates, more data may be transmitted to, and thus monitored at, the terranean surface  12 . Additionally, while the mud pulser  200  may transmit negative mud pulse signals through the drilling fluid  105  in some embodiments, other embodiments may allow for positive mud pulse signals to be transmitted through the drilling fluid  105 . 
     In some implementations, the standpipe valve  165  may be a knife or gate valve, operable to close or open based on a signal received from the sensor section  65 . In some embodiments, the standpipe valve  165  may fully shut-off drilling fluid from reaching the drill bit  70 . In some embodiments, the standpipe valve  165  may be a needle valve. In some embodiments, the standpipe valve  165  may not provide a full shut-off position. Further, in some embodiments, the standpipe valve  165  may include multiple restrictions or valves. Accordingly, reference to a single standpipe valve  165  is also intended to encompass configurations with multiple standpipe valves  165 . 
     The flared portion of the stator  130  may also include one or more stator exhausts  160  disposed through the flared portion parallel to the direction of flow of the drilling fluid  105  through the stator  130 . Each stator exhaust  160  (or none of the stator exhausts  160 ) may include an exhaust valve  170 . The exhaust valve  170  may also provide another variable restriction to flow of the drilling fluid  105  as it passes between the rotor  110  and the stator  130 . Thus, as the drilling fluid  105  is restricted from flowing to one or more downhole tools, the fluid pressure of the drilling fluid  105  may be increased. As illustrated, the exhaust valve  170  may be communicably coupled and/or controlled by the sensor section  65 . Thus, the sensor section  65  may control one or more exhaust valves  170  to open and/or close, thus restricting the drilling fluid  105  from passing to one or more downhole components. The mud pulser  200  may therefore provide up to 4 or more (or less as appropriate) steps of pressure control by which the fluid pressure of the drilling fluid  105  may be controllably increased and/or decreased. 
     As illustrated, the mud pulser  200  may also include a clutch  175  affixed to or integral with the body  120  and a clutch arm  180  affixed to the rotor  110 . Generally, the clutch  175  and clutch arm  180  work in conjunction as a brake to slow and/or stop rotation of the rotor  110  as the drilling fluid  105  flows between the rotor  110  and the stator  130 . For example, the clutch  175  may stop rotation of the rotor  110  through frictional contact with the clutch arm  180  such that the exhaust ports  115  are selectively aligned or misaligned with corresponding apertures  125 . In short, the clutch  175  may controllably hold and/or release the rotor  110  to release the drilling fluid  105  through the aligned ports  115  and apertures  125 , thereby increasing and/or decreasing the fluid pressure of the drilling fluid  105  uphole of the mud pulser  200 . 
     In some embodiments, the clutch  175  may be controlled by a telemetry, or control portion, such as the sensor section  65 . As illustrated, for example, the clutch  175  may be communicably coupled to the sensor section  65 . Further, the clutch  175  and/or the sensor section  65  may receive positional feedback indicating a position of the rotor  110  (e.g., “open” where the ports  115  are fully or partly aligned with the apertures  125 ). In some embodiments, the clutch  175  may include a solenoid or a cylinder with a magnet coil in the body  120  that may start and stop the clutch  175 . In some aspects, the clutch  175  may be a disc type clutch; an electrical clutch; and or an electro-mechanical clutch. Further, the clutch  175  may include more than one clutches, or brakes, as well as multiple corresponding clutch arms. 
     With references to  FIGS. 1-2 , one example operation of the mud pulser  200  in accordance with the present disclosure is described. As drilling fluid  105  is pumped down the drill string  35  during drilling, MWD, and/or LWD operations, fluid  105  is transmitted to the mud pulser  200  (or  100 ) in the BHA  50 . Simultaneously, the sensor section  65  may be measuring one or more downhole values to be transmitted to the terranean surface  12 . Through a combination of hardware (e.g., processors, ASICs, analog or digital circuitry) and/or software (e.g., middleware, source code, one or more child and/or parent applications or modules) contained in, for example, the sensor section  65  or other component of the BHA  50  or drilling assembly  10 , one or more signals are transmitted to at least one of the clutch  175 , the standpipe valve  165 , and one or more exhaust valves  170 . Such signals (e.g., PWM, 0-5 VDC, 0-20 mA) may, for example, selectively operate the clutch  175  to start and/or stop rotation of the rotor  110  to release the drilling fluid  105  through the exhaust ports  115  and aligned apertures  125  or direct the drilling fluid  105  through the standpipe  135  and/or between the rotor  110  and stator  130 . The signals may also cause the standpipe valve  165  to increase or decrease the restriction to flow of the drilling fluid  105  through the standpipe  136  to one or more tools downhole from the mud pulser  200 . Further, the signals may also cause one or more exhaust valves  170  to selectively release drilling fluid  105  downhole of the mud pulser  200  or hold the drilling fluid  105  in the mud pulser  200 . 
     By selectively operating one or more of the clutch  175 , the standpipe valve  165  and one or more exhaust valves  170 , the fluid pressure of the drilling fluid  105  in the drill string  35  may be controllably increased and decreased based on the measured downhole data. Thus, mud pulse telemetry may be generated and measured at the terranean surface  12  by, for example, the telemetry detector  75 . In such fashion, the measured data may be transmitted through the column of drilling fluid  105  by varying one or both of the amplitude of the fluid pressure of the drilling fluid  105  or the frequency of changes in the fluid pressure of the drilling fluid  105 . Other operations of the mud pulser  200  described in the present disclosure may also be implemented. As one example, the mud pulser  200  may be operated (e.g., the standpipe valve  170  adjusted) based on an increase or decrease of a flow rate of the drilling fluid  105  pumped through the drill string  35 . Further, in some embodiments, a mud pulser according to the present disclosure may be implemented with wired pipe or a wireline arrangement rather than a drill string or drill pipe. 
     A number of embodiments have been described. Nevertheless, it will be understood that various modifications may be made. Accordingly, other embodiments are within the scope of the following claims.