Telemetry module with push only gate valve action

An telemetry module includes a valve assembly having a gate defining gate valve flow ports and a valve seat defining valve seat flow ports. A first solenoid assembly is arranged on a first side of the valve assembly and includes a first valve train engageable with the gate and a first push solenoid operatively coupled to the first valve train to move the gate in a first direction. A second solenoid assembly is arranged on a second side of the valve assembly and includes a second valve train engageable with the gate and a second push solenoid operatively coupled to the second valve train to move the gate in a second direction opposite the first direction. Moving the gate in the first direction with the first solenoid increases flow through the gate and alternately moving the gate in the second direction with the second solenoid decreases flow through the gate.

BACKGROUND

Hydrocarbon drilling and production operations demand a great quantity of information relating to parameters and conditions downhole. Such information may include characteristics of the earth formations traversed by the borehole, along with data relating to the size and configuration of the borehole itself. The collection of information relating to conditions downhole is commonly termed “logging.”

Drillers often simultaneously log a borehole while drilling, and thereby eliminate the need of removing or “tripping” the drilling assembly to insert a wireline logging tool to collect the required data. Data collection during drilling also enables the driller to make accurate modifications or corrections as needed to steer the well or optimize drilling performance while minimizing down time. Designs for measuring conditions downhole including the movement and location of the drilling assembly contemporaneously with the drilling of the well have come to be known as “measurement-while-drilling” techniques, or “MWD.” Similar techniques that concentrate more on the measurement of formation parameters are commonly referred to as “logging-while-drilling” techniques, or “LWD.” While distinctions between MWD and LWD may exist, the terms MWD and LWD are often used interchangeably.

In MWD and LWD tools, sensors in the drill string measure the desired drilling parameters and formation characteristics and continuously or intermittently transmit the information obtained to a surface detector by some form of telemetry. Most MWD and LWD tools use the drilling fluid (or mud) circulating through the drill string as the information carrier, and are thus referred to as mud pulse telemetry systems. In positive-pulse systems, a valve or other form of flow restrictor creates pressure pulses in the fluid flow by adjusting the size of a constriction inside the drill string. In negative-pulse systems, a valve creates pressure pulses by releasing fluid from the interior of the drill string into the annulus surrounding the drill string. In both system types, the pressure pulses propagate at the speed of sound through the drilling fluid to the surface, where they are detected by various types of surface transducers.

Drilling operations have become more complicated and customers are requiring more downhole sensors. This means that more data is required to be transmitted uphole in the same period of time, and thus higher data rates are now needed. At the same time, wells are getting deeper and directional wells are getting longer, which leads to the MWD and LWD tools being required to operate reliably for longer periods of time. Increasing the usable life of the MWD and LWD tools is a useful aspect in providing a competitive advantage in the marketplace.

DETAILED DESCRIPTION

The present disclosure is related to downhole tools and, more particularly, to valve assemblies for mud pulse telemetry modules.

Embodiments of the present disclosure provide telemetry modules that substantially mitigate or eliminate abrasion or erosion between moving parts. This may be accomplished by substituting a T-slot joint commonly used in conventional telemetry modules to couple a gate to a valve stem with opposing valve stems positioned on either side of the gate. Corresponding push solenoids cooperatively push the opposing valve stems in opposite directions and thereby are able to repeatedly move the gate between open and closed positions. The opposing valve stems need not be coupled to the gate, but may instead be engageable therewith as pushed by its corresponding push solenoid. As a result, any impact that does occur during engagement between the gate and the opposing valve stems may result in substantially less stress and abrasion as compared to prior telemetry modules, and thus the parts may exhibit a longer fatigue life.

Referring toFIG. 1, illustrated is an exemplary drilling system100that may employ one or more principles of the present disclosure. Boreholes may be created by drilling into the earth102using the drilling system100. The drilling system100may be configured to drive a bottom hole assembly (BHA)104positioned or otherwise arranged at the bottom of a drill string106extended into the earth102from a derrick108arranged at the surface110. The derrick108includes a kelly112used to lower and raise the drill string106.

The BHA104may include a drill bit114operatively coupled to a tool string116which may be moved axially within a drilled wellbore118as attached to the drill string106. During operation, the drill bit114penetrates the earth102and thereby creates the wellbore118. The BHA104provides directional control of the drill bit114as it advances into the earth102. The tool string116can be semi-permanently mounted with various measurement tools (not shown) such as, but not limited to, measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools, which may be configured to obtain downhole measurements of drilling conditions. In other embodiments, the measurement tools may be self-contained within the tool string116, as shown inFIG. 1.

Fluid or “mud” from a mud tank120may be pumped downhole using a mud pump122powered by an adjacent power source, such as a prime mover or motor124. The mud may be pumped from the mud tank120, through a stand pipe126, which feeds the mud into the drill string106and conveys the same to the drill bit114. The mud exits one or more nozzles arranged in the drill bit114and in the process cools the drill bit114. After exiting the drill bit114, the mud circulates back to the surface110via the annulus defined between the wellbore118and the drill string106, and in the process returns drill cuttings and debris to the surface110. The cuttings and mud mixture are passed through a flow line128and are processed such that a cleaned mud is returned down hole through the stand pipe126once again.

The tool string116may include a telemetry module130that may be operatively coupled to the MWD and/or LWD tools of the tool string116. The telemetry module130may be configured to communicate with the MWD and/or LWD tools and transmit any measured data to the surface110. To accomplish this, the telemetry module130may be configured to modulate a resistance to the flow of drilling fluid and thereby generate pressure pulses that propagate at the speed of sound to the surface. Various transducers located at the surface110may be configured to convert the pressure signals into electrical signals readable by a signal digitizer (not shown), such as an analog to digital converter. The signal digitizer supplies a digital form of the pressure signals to a computer (not shown) or some other form of a data processing device, and the computer operates in accordance with software (which may be stored on a computer-readable storage medium) to process and decode the received signals. The resulting telemetry data may be further analyzed and processed by the computer to generate a display of useful information. For example, a driller could employ the computer to obtain and monitor the position of the BHA104, orientation information, drilling parameters, and formation properties.

Although the drilling system100is shown and described with respect to a rotary drill system inFIG. 1, those skilled in the art will readily appreciate that many types of drilling systems can be employed in carrying out embodiments of the disclosure. For instance, drills and drill rigs used in embodiments of the disclosure may be used onshore (as depicted inFIG. 1) or offshore (not shown). Offshore oil rigs that may be used in accordance with embodiments of the disclosure include, for example, floaters, fixed platforms, gravity-based structures, drill ships, semi-submersible platforms, jack-up drilling rigs, tension-leg platforms, and the like. It will be appreciated that embodiments of the disclosure can be applied to rigs ranging anywhere from small in size and portable, to bulky and permanent.

Further, although described herein with respect to oil drilling, various embodiments of the disclosure may be used in many other applications. For example, disclosed methods can be used in drilling for mineral exploration, environmental investigation, natural gas extraction, underground installation, mining operations, water wells, geothermal wells, and the like. Further, embodiments of the disclosure may be used in weight-on-packers assemblies, in running liner hangers, in running completion strings, etc., without departing from the scope of the disclosure.

Referring now toFIG. 2, illustrated is a cross-sectional side view of a telemetry module200that may be used to communicate with a surface location. The telemetry module200may be similar in some respects to the telemetry module130ofFIG. 1and, therefore, may be able to communicate with the surface110(FIG. 1). As illustrated, the telemetry module200may be positioned within an interior202of a tubular member204arranged within a wellbore206. In some embodiments, the tubular member204may form part of the drill string106(FIG. 1), such as forming part of the tool string116(FIG. 1) and otherwise extendable into the wellbore206from the surface110. Accordingly, the tubular member204may be drill pipe or a drill collar included in a string of drill pipe. In other embodiments, however, the tubular member204may be any other pipe or tubing used in the oil and gas industry such as casing or production tubing, without departing from the scope of the disclosure.

As illustrated, the telemetry module200may generally include a solenoid assembly208and a valve assembly210. As illustrated, the solenoid assembly208may include a casing212that houses a valve train214, a first or push solenoid216a,and a second or pull solenoid216b.The valve train214may include a valve stem218, a push rod220, and a pull rod224. The push rod220may be operatively coupled to the valve stem218at a first coupling222a,and the pull rod224may be operatively coupled to the push rod220at a second coupling222b.The first and second couplings222a,boperate to couple each of the valve stem218, the push rod220, and the pull rod224such that the valve train214is able to move as a single or unitary component of the solenoid assembly208.

The push solenoid216amay be operatively coupled to and otherwise configured to act on the push rod220to urge the push rod220toward the valve assembly210(i.e., in an uphole direction) when activated. Conversely, the pull solenoid216bmay be operatively coupled to and otherwise configured to act on the pull rod222such that it is pulled or urged away from the valve assembly210(i.e., in a downhole direction) when activated. Accordingly, alternating operation of the push and pull solenoids216a,bmay be configured to axially translate the entire valve train214toward and away from the valve assembly210.

The valve assembly210and its various component parts may be housed within a valve housing226. The valve housing226may be operatively coupled to the casing212using, for example, a threaded collar228or the like. As illustrated, the valve assembly210may generally include a screen230, an inlet port232, a gate234, a valve seat236, a lock nut238, and an outlet port240. The screen230may provide or otherwise define a plurality of slots242that allow fluid within the interior202of the tubular member204to pass through the screen230and into the inlet port232while simultaneously filtering out particulate matter of a predetermined size and greater.

The gate234may be generally arranged within and otherwise in fluid communication with the inlet port232. As described in more detail below, the gate234may be operatively coupled to the valve stem218. The valve stem218extends out of the casing212and partially into the valve housing226to be operatively coupled to the gate234such that axial translation or movement of the valve stem218correspondingly moves the gate234axially within the valve housing226.

The valve seat236may be secured within the valve housing226with the lock nut238and may be in fluid communication with the outlet port240. The outlet port240may be aligned with and otherwise in fluid communication with an annulus port244defined through the tubular member204. The annulus port244may place the outlet port240in fluid communication with an annulus246defined between the tubular member204and the wall of the wellbore206.

Each of the gate234and the valve seat236may provide and otherwise define one or more flow ports248, shown as flow ports248adefined in the gate234and flow ports248bdefined in the valve seat236. When the flow ports248aof the gate234are at least partially axially aligned with the flow ports248bof the valve seat236, fluids may be able to communicate through the gate234and the valve seat236and otherwise between the inlet and outlet ports232,240. Conversely, however, when the flow ports248a,bare axially misaligned, a metal-to-metal seal is generated across the interface between the gate234and the valve seat236such that fluids are prevented from communicating between the inlet and outlet ports232,240. As operatively coupled to the valve stem218, and, therefore, the valve train214, the gate234may be moved between an open position, where the flow ports248a,bare axially aligned, and a closed position, where the flow ports248a,bare axially misaligned.

Exemplary operation of the telemetry module200is now provided. A fluid250may be introduced into the interior202of the tubular member204, such as from a surface location (e.g., the surface110ofFIG. 1). The fluid250may be a drilling fluid or “mud” that is conveyed to and circulated past the telemetry module200within the interior202until reaching a drill bit (e.g., the drill bit114ofFIG. 1). The fluid250may exit the drill bit via one or more nozzles arranged in the drill bit and circulate back to the surface location via the annulus246. The pressure of the fluid250in the interior202may be greater than the pressure of the fluid in the annulus246. As a result, a pressure differential may be generated across the telemetry module200and, more particularly, the valve assembly210.

Until prompted, the telemetry module200may remain inactive with the gate234maintained in the closed position, as shown inFIG. 2. The telemetry module200may be in communication with one or more sensors, such as the MWD and/or LWD tools of the tool string116(FIG. 1). When it is desired to communicate sensor measurement information to a surface location (e.g., the surface110ofFIG. 1), a command signal may be sent to the push and pull solenoids216a,bto cooperatively translate the valve train214within the casing212and thereby selectively move the gate234axially between the open and closed positions. When the gate234moves to the open position and the flow ports248a,bare thereby aligned, a portion252of the fluid250may be able flow through the valve assembly210seeking pressure equilibrium. More particularly, the portion252may be able to pass through the screen230and traverse the gate234and the valve seat236via the fluidly communicating inlet and outlet ports232,240and thereafter be introduced into the annulus246via the annulus port244. Injecting the portion252of the fluid250into the annulus246may generate a pressure pulse that may propagate to the surface location via the annulus246. At the surface location, the generated pressure pulse may be detected and decoded, as generally described above.

Referring now toFIG. 3, with continued reference toFIG. 2, illustrated is an enlarged cross-sectional top view of the gate234as taken along the lines (FIG. 3-FIG. 3) shown inFIG. 2. The flow ports248adefined through the gate234are depicted inFIG. 3, and portions of the screen230may be seen below through the flow ports248a.Moreover, the valve stem218is depicted as being operatively coupled to the gate234at a T-slot joint302formed in the gate234. More particularly, the valve stem318may have an end304that provides a neck306and a head308that extends axially from the neck306. The neck306may exhibit a diameter that is smaller than the diameter of the head308and, therefore, the head308may be configured to be received within the T-slot joint302and engage the inner surfaces310of the T-slot joint302to effectively couple the valve stem218to the gate234. As operatively coupled to the gate234at the T-slot joint302, axial movement of the valve stem218back and forth in the direction A as acted upon by the push and pull solenoids216a,b(FIG. 2) will correspondingly move the gate234in the direction A.

The gate234and the valve stem218may each be made of a hardened material. For instance, in some embodiments, the gate234and, therefore, the T-slot joint302, may be made of tungsten carbide, and the valve stem318may be made of stainless steel. During operation, moving the gate234back and forth in the axial direction A in the presence of abrasive fluids (e.g., the fluid250and the portion252of the fluid250ofFIG. 2) may cause wear and erosion to occur on the gate234and, more particularly, on the T-slot joint302at the inner surfaces310. As the push and pull solenoids216a,bcooperatively push and pull the valve train214(FIG. 2) in the direction A to repeatedly open and close the gate234, abrasion caused by the relative movement between the gate234and the valve stem218in a drilling fluid environment may wear the head308of the valve stem218to the point where movement of the gate234becomes severely limited. Over time, such wear and erosion at the inner surfaces310may render the connection between the T-slot joint302and the valve stem218essentially ineffectual.

According to embodiments of the present disclosure, the adverse effects of wear and erosion on the T-slot joint302at the inner surfaces310between the gate234and the valve stem218may be resolved by entirely omitting the T-slot joint302from a telemetry module. As described below, embodiments of an exemplary telemetry module may include solenoids positioned on either side of the gate234. In such embodiments, the solenoids may cooperatively push the gate234back and forth in the axial direction A, without the gate234being pulled by the valve stem218. As will be appreciated, with the gate234is no longer being pulled by the valve stem218for movement in the axial direction A, the T-slot joint302may no longer be required.

Referring now toFIG. 4, illustrated is a cross-sectional side view of an exemplary telemetry module400that may employ the principles of the present disclosure, according to one or more embodiments. The telemetry module400may be similar in some respects to the telemetry module200ofFIG. 2and therefore may be best understood with reference thereto, where like numerals refer to like components or elements not described again in detail. For instance, similar to the telemetry module200ofFIG. 2, the telemetry module400may be positioned within the interior202of the tubular member204, which may be extended into and otherwise arranged within the wellbore206. The annulus port244may be defined in the tubular member204to provide fluid communication to the annulus246. Moreover, the telemetry module400may further include the valve assembly210, which may include the valve housing226, the screen230, the inlet port232, the gate234, the valve seat236, and the outlet port240.

Unlike the telemetry module200ofFIG. 2, however, the telemetry module400may include a first or upper solenoid assembly402aand a second or lower solenoid assembly402b.As illustrated, the upper and lower solenoid assemblies402a,bmay be generally aligned with a longitudinal axis402of the tubular member204. More particularly, the upper solenoid assembly402amay be positioned on a first or uphole side of the valve assembly210, and the lower solenoid assembly402bmay be positioned on a second or downhole side of the valve assembly210. It should be noted that, although the upper and lower solenoid assemblies402a,bare depicted as being generally arranged along the longitudinal axis403of the tubular member204(i.e., uphole and downhole from the valve assembly210), embodiments are contemplated herein where the upper and lower solenoid assemblies402a,bare arranged orthogonal to the longitudinal axis403and otherwise arranged at generally the same axial position along the tubular member204. Accordingly, having the upper and lower solenoid assemblies402a,bpositioned on opposing sides of the valve assembly210may refer to axially aligning the upper and lower solenoid assemblies402a,balong the longitudinal axis403of the tubular member204, but also aligning the upper and lower solenoid assemblies402a,borthogonal to the longitudinal axis403of the tubular member204. Moreover, having the upper and lower solenoid assemblies402a,bpositioned on opposing sides of the valve assembly210may further refer to aligning the upper and lower solenoid assemblies402a,bon either side of the valve assembly anywhere between the longitudinal axis403of the tubular member204and orthogonal thereto, without departing from the scope of the disclosure.

Each of the upper and lower solenoid assemblies402a,bmay be similar in some respects to the solenoid assembly208ofFIG. 2. For instance, each of the upper and lower solenoid assemblies402a,bmay include a casing404, shown as casings404aand404b,respectively that houses a valve train406, shown as valve trains406aand406b,respectively. Each casing404a,bmay be operatively coupled the valve housing226on either side using, for example, a threaded collar228or the like. Each valve train406a,bmay further include a valve stem408, shown as valve stems408aand408b,respectively, and a push rod410, shown as push rods410aand410b,respectively. Each valve stem408a,bmay be operatively coupled its corresponding push rod410a,b, respectively, at a coupling412, shown as couplings412aand412b,respectively.

The couplings412a,bmay operate to couple the valve stems408a,bto the push rods410a,b, respectively, such that movement of the push rod410a,bcorrespondingly moves the corresponding valve stem408a,bduring operation. In some embodiments, the first and second couplings412a,bmay be adjustable and thereby able to adjust a stroke length for each valve train406a,b. This may prove advantageous in optimizing operation of each valve train406a,bsuch that the flow ports248a,bof the gate234and the valve seat236, respectively, may align and misalign as desired for operation. It will be appreciated, however, that the couplings412a,bmay be omitted in at least one embodiment. In such embodiments, each valve stem408a,bmay be directly attached to or otherwise form an integral part of the corresponding push rods410a,b, without departing from the scope of the disclosure.

The upper and lower solenoid assemblies402a,bmay each include a push solenoid414, shown as a first or upper push solenoid414aand a second or lower push solenoid414b.The upper push solenoid414amay be operatively coupled to and otherwise configured to act on the upper push rod410asuch that it is pushed or urged toward the valve assembly210in a first direction416awhen activated. Conversely, the lower push solenoid414bmay be operatively coupled to and otherwise configured to act on the lower push rod410bsuch that it is pushed or urged toward the valve assembly210in a second direction416b.As illustrated, the second direction416bis opposite the first direction416aand, therefore, the upper and lower push solenoids414a,bmay be configured to cooperatively operate to move the upper and lower push rods410a,bin opposing directions.202

The upper valve stem408amay be configured to engage a first side surface418aof the gate234, and the lower valve stem408bmay be configured to engage a second side surface418bof the gate234, where the first side surface418ais opposite the second side surface418bon the gate234. In some embodiments, one or both of the upper and lower valve stems408a,bmay be coupled to the gate234at the first and second side surfaces418a,b, respectively, such as via a mechanical attachment (e.g., a weld, a brazed interface, a mechanical fastener, etc.). In other embodiments, however, the upper and lower valve stems408a,bonly engage or contact the first and second side surfaces418a,b, respectively, of the gate234but no coupling engagement is involved. In such embodiments, the gate234may, therefore, float between the upper and lower valve stems408a,b. Any clearance or “slop” between the upper and lower valve stems408a,band the first and second side surfaces418a,b, respectively, may be eliminated by adjusting the couplings412a,b.

Exemplary operation of the telemetry module400is now provided. The fluid250may be introduced into the interior202of the tubular member204, such as from a surface location (e.g., the surface110ofFIG. 1) and circulated past the telemetry module400until reaching a drill bit (e.g., the drill bit114ofFIG. 1). The fluid250may then exit the drill bit via one or more nozzles arranged in the drill bit and circulate back to the surface location via the annulus246. The pressure of the fluid250in the interior202may be greater than the pressure of the fluid in the annulus246and, as a result, a pressure differential may be generated across the telemetry module400and, more particularly, across the valve assembly210.

Until prompted, the telemetry module400may remain inactive with the gate234maintained in the closed position, where the flow ports248a,bare axially misaligned and a metal-to-metal seal is generated at the interface between the gate234and the valve seat236. As will be appreciated, such a metal-to-metal seal may remain at least partially intact as the gate234is moved between the closed and open positions. The telemetry module400may be in communication with one or more sensors, such as the MWD and/or LWD tools of the tool string116(FIG. 1). When it is desired to communicate sensor measurement information to a surface location, a command signal may be sent to the upper and lower solenoid assemblies402a,b, which cooperatively operate to move the gate234axially between the open and closed positions. More particularly, to move the gate234between the open and closed positions, the lower push solenoid414bmay remain inactive while the upper push solenoid414amay be activated to push or urge the upper valve train406ain the first direction416a.Pushing the upper valve train406ain the first direction416amay engage the upper valve stem408aon the gate234at the first side surface418aand thereby correspondingly move the gate234in the first direction416a.In some embodiments, while the lower push solenoid414bremains inactive, the lower valve train406bmay freely move and, therefore, may also be moved in the first direction416aas the gate234engages the lower valve stem408bat the second side surface418b.

The upper push solenoid414amay be configured to push the gate234in the first direction416auntil the flow ports248a,bin the gate234and the valve seat236, respectively, become generally aligned. Once the flow ports248a,bare aligned, a portion252of the fluid250may be able flow through the valve assembly210seeking pressure equilibrium and be introduced into the annulus246via the annulus port244. More particularly, the portion252may be able to pass through the screen230and the inlet port232and thereafter traverse the gate234and the valve seat236via the aligned flow ports248a,b. The portion252may then pass through the outlet port240and the annulus port244to be injected into the annulus246. As discussed above, injecting the portion252of the fluid250into the annulus246may generate a pressure pulse in the annulus246that may propagate to the surface location within the annulus246.

The lower push solenoid414bmay then be operated to move the gate234back to the closed position, where the valve ports248a,bonce again become misaligned. To accomplish this, the upper push solenoid414amay be inactive while the lower push solenoid414bis activated to push or urge the lower valve train406bin the second direction416b.Pushing the lower valve train406bin the second direction416bmay engage the lower valve stem408bon the gate234at the second side surface418band correspondingly move the gate234in the second direction416b.While the upper push solenoid414ais inactive, the upper valve train406amay be able to freely move and, therefore, may also be moved in the second direction as the gate234engages the upper valve stem408aat the first side surface418a.

As will be appreciated, while the above description describes the upper push solenoid414aas opening the gate234and the lower push solenoid414bas closing the gate234, an opposite configuration may equally be configured, without departing from the scope of the disclosure. For example, in other embodiments, operation of the lower push solenoid414bmay be configured to open the gate234, while operation of the upper push solenoid414amay be configured to close the gate234. In either case, alternating operation or activation of the upper and lower push solenoids414a,bmay result in the gate234being repeatedly moved between the open and closed positions, and thereby selectively introducing pressure pulses into the annulus246that may propagate to the surface to be detected and decoded.

Drilling operations are becoming increasingly more complicated and well operators are requiring more downhole sensors. As a result, more data is required to be transmitted uphole in the same time period, and thus higher data rates are needed. At the same time, wells are getting deeper and directional wells are getting longer, which means that downhole tools, such as telemetry modules, may be required to operate downhole for longer periods of time. This means that telemetry modules must operate reliably for longer periods of time and at faster rates. As will be appreciated, the telemetry module400described herein may prove advantageous over the telemetry module200ofFIG. 2since there is no relative movement between the gate234and the upper and lower valve stems408a,bin the telemetry module400. As a result, material removal at the upper and lower valve stems408a,bdue to abrasion or erosion may be substantially mitigated, if not eliminated altogether. Moreover, since the telemetry module400does not include the high-stress features of the T-slot joint302(FIG. 3) of the telemetry module200, any impact that does occur during engagement between the gate234and the upper and lower valve stems408a,bmay result in substantially less stress and thus the parts will have a longer fatigue life.

A telemetry module that includes a valve assembly positionable within an interior of a tubular member and including a gate defining one or more gate valve flow ports and a valve seat defining one or more valve seat flow ports, a first solenoid assembly arranged on a first side of the valve assembly and including a first valve train engageable with the gate and a first push solenoid operatively coupled to the first valve train to move the gate in a first direction, and a second solenoid assembly arranged on a second side of the valve assembly and including a second valve train engageable with the gate and a second push solenoid operatively coupled to the second valve train to move the gate in a second direction opposite the first direction, and wherein moving the gate in the first direction with the first solenoid increases flow through the gate and alternately moving the gate in the second direction with the second solenoid decreases flow through the gate.

B. A well system that includes a tubular member extendable within a wellbore, the tubular member defining an annulus port that provides fluid communication between an interior of the tubular member and an annulus defined between the tubular member and the wellbore, a telemetry module positioned within the tubular member and including a valve assembly that provides a gate defining one or more gate valve flow ports and a valve seat defining one or more valve seat flow ports, a first solenoid assembly arranged on a first side of the valve assembly and including a first push solenoid that operates to move the gate in a first direction, and a second solenoid assembly arranged on a second side of the valve assembly and including a second push solenoid that operates to move the gate in a second direction opposite the first direction, wherein moving the gate in the first direction with the first solenoid increases flow through the gate and alternately moving the gate in the second direction with the second solenoid decreases flow through the gate.

A method that includes introducing a telemetry module into a wellbore, the telemetry module being positioned within an interior of a tubular member and providing a valve assembly that includes a gate movable with respect to a valve seat, the telemetry module further including a first solenoid assembly arranged on a first side of the valve assembly and having a first push solenoid, and a second solenoid assembly arranged on a second side of the valve assembly and having a second push solenoid, wherein the first side is opposite the second side, circulating a fluid through the interior of the tubular member, the tubular member defining an annulus port that provides fluid communication between an annulus defined between the tubular member and the wellbore and the interior via the valve assembly, activating the first push solenoid to move the gate in a first direction and increase flow through the gate, thereby injecting a portion of the fluid into the annulus via the valve assembly and thereby generating a pressure pulse within the annulus, activating the second push solenoid to move the gate in a second direction opposite the first direction to decrease flow through the gate, and alternatingly activating the first and second push solenoids to selectively move the gate in the first and second directions and thereby injecting portions of the fluid into the annulus that generate a plurality of pressure pulses within the annulus.

Each of embodiments A, B, and C may have one or more of the following additional elements in any combination: Element1: wherein the first and second solenoid assemblies are aligned with a longitudinal axis of the tubular member. Element2: wherein the first and second solenoid assemblies are misaligned with a longitudinal axis of the tubular member. Element3: wherein the first and second valve stems are operatively coupled to the first and second push rods, respectively, with corresponding first and second couplings. Element4: wherein the first and second couplings are each adjustable to adjust a stroke length for the first and second push rods, respectively. Element5: wherein, when the first push solenoid is operated to move the first push rod in the first direction, the second push solenoid is inactive and the second valve stem and the second push rod are able to move in the first direction, and wherein, when the second push solenoid is operated to move the second push rod in the second direction, the first push solenoid is inactive and the first valve stem and the first push rod are able to move in the second direction. Element6: wherein the gate floats between the first and second valve stems. Element7: wherein the gate is operatively coupled to one or both of the first and second valve stems.

Element8: wherein the tubular member is selected from the group consisting of drill pipe, a drill collar, casing, production tubing, and any combination thereof. Element9: wherein the valve assembly further comprises a screen in fluid communication with the interior of the tubular member, an inlet port in fluid communication with the interior via the screen, and an outlet port in fluid communication with the annulus port, wherein, when the gate is in the open position, a fluid in the interior is able to traverse the valve assembly and be introduced into the annulus. Element10: wherein the first push solenoid is operatively coupled to a first push rod, which is operatively coupled to a first valve stem engageable with a first side surface of the gate, and the second push solenoid is operatively coupled to a second push rod, which is operatively coupled to a second valve stem engageable with a second side surface of the gate, the second side surface being opposite the first side surface. Element11: wherein the first and second valve stems are operatively coupled to the first and second push rods, respectively, with corresponding first and second couplings. Element12: wherein the first and second couplings are each adjustable to adjust a stroke length for the first and second push rods, respectively. Element13: wherein, when the first push solenoid is operated to move the first push rod in the first direction, the second push solenoid is inactive and the second valve stem and the second push rod are able to move in the first direction, and wherein, when the second push solenoid is operated to move the second push rod in the second direction, the first push solenoid is inactive and the first valve stem and the first push rod are able to move in the second direction. Element14: wherein the gate floats between the first and second valve stems.

Element15: wherein the valve assembly further comprises, a screen in fluid communication with the interior of the tubular member, an inlet port in fluid communication with the interior via the screen, and an outlet port in fluid communication with the annulus port, and wherein injecting the portion of the fluid into the annulus via the valve assembly comprises flowing the portion of the fluid into the inlet port via the screen, flowing the portion of the fluid from the inlet port and into the outlet port via the one or more gate valve flow ports aligned with the one or more valve seat flow ports, and flowing the portion of the fluid from the outlet port into the annulus via the annulus port. Element16: wherein the first push solenoid is operatively coupled to a first push rod, which is operatively coupled to a first valve stem engageable with a first side surface of the gate, and wherein activating the first push solenoid and thereby moving the gate in the first direction comprises pushing the first push rod and the first valve stem with the first push solenoid to engage the first side surface of the gate. Element17: wherein the second push solenoid is operatively coupled to a second push rod, which is operatively coupled to a second valve stem engageable with a second side surface of the gate, the second side surface being opposite the first side surface, and wherein activating the second push solenoid to move the gate in the second direction comprises pushing the second push rod and the second valve stem with the second push solenoid to engage the second side surface of the gate. Element18: further comprising deactivating the second push solenoid when the first push solenoid is activated, and deactivating the first push solenoid when the second push solenoid is activated. Element19: wherein the first and second couplings are each adjustable to adjust a stroke length for the first and second push rods, respectively. Element20: wherein the telemetry module is communicably coupled to one or more sensors, the method further comprising communicating measurements obtained by the one or more sensors by generating the plurality of pressure pulses within the annulus. Element21: wherein the first valve train includes a first valve stem operatively coupled to a first push rod engageable with a first side surface of the gate, and wherein the second valve train includes a second valve stem operatively coupled to a second push rod engageable with a second side surface of the gate.

The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.