Patent Description:
These and other situations require operators to extend a capillary line from the wellhead and to communicate control fluids, chemicals, or the like into the capillary line. Doing this for a live well in an effective way can be challenging. To that end, the subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.

<CIT> discloses a tubular support system with a bowl and a hanger, the bowl for supporting at least one tubular member and including a body with at least one access port for accessing a fluid channel opening of the hanger positioned within the bowl; the hanger for connection to a tubular member and having at least one fluid channel through it from a bottom surface to an outer surface so that one or more control lines attached to a supported tubular (pipe, casing, riser, tubing) can be placed in fluid communication with the at least one fluid channel, and, via the at least one access port, the at least one fluid channel can be placed in fluid communication with other apparatus, e.g., a surface control unit.

In one aspect of the present disclosure there is provided an assembly according to claim <NUM> and a method according to claim <NUM>. An assembly disclosed herein is for communicating a media through a wellhead to a media line in a well. The wellhead has at least one gate valve mounted above the wellhead. The assembly comprises a module, a housing, and a mandrel. The module configured to install in the wellhead and is configured to support the media line extending therefrom. The housing is configured to mount above the at least one gate valve and has an insertion port for the media. The mandrel is disposed in the housing and has a proximal end and a distal end. The mandrel defines a bore therethrough from the proximal end to the distal end for the media. The mandrel is movable between a retracted condition and an extended condition. The mandrel in the retracted condition has the distal end retracted from the at least one gate valve. The mandrel in the extended condition is extended through the at least one gate valve, has the distal end engaged with the module, and is configured to communicate the media with the media line.

The module can comprise a hanger configured to support the media line, and the hanger can have an external thread profile configured to install in the wellhead.

The module can comprises a valve being actuatable at least from a closed condition to an opened condition. The valve in the closed condition can be configured to prevent fluid communication through the valve module, while the valve in the opened condition can be configured to allow fluid communication through the valve. The distal end of the mandrel in the extended condition can be configured to actuate the valve from the closed condition to the open condition.

The valve can comprise: a seat affixed in an internal passage of the hanger; a poppet movable in the internal passage between seated and unseated conditions relative to the seat, a tip of the poppet being engageable by the distal end of the mandrel; and a biasing element in the internal passage biasing the poppet to the seated condition.

The mandrel can comprise a valve disposed in the bore, the valve being movable between a closed condition and an opened condition in response to a pressure differential thereacross, the valve in the closed condition being configured to prevent fluid communication through the valve, the valve in the opened condition being configured to allow fluid communication through the valve.

The assembly can comprise a biasing element disposed in the housing and biasing the mandrel to the retracted condition.

The assembly can comprise a mechanism being configured to move the mandrel relative to the housing. For example, the mechanism can comprise: a first gear associated with the housing and being movable; and a second gear associated with the mandrel and being engaged with the first gear. In another example, the mechanism can comprise a hydraulic actuator being configured to move the mandrel with hydraulic pressure communicated to a portion of the housing.

The assembly can be operated by hydraulic pressure. The housing can comprise: a first chamber having the insertion port for the media, and a second chamber having a hydraulic port for the hydraulic pressure. The mandrel can be movable between the retracted condition and the extended condition in response to the hydraulic pressure in the second chamber.

The mandrel can comprise a piston portion sealed in the housing so the mandrel can be movable in the housing in response to the hydraulic pressure in the housing applied against the piston portion. In this example, the housing can comprise a first annular seal disposed in the housing and sealing an annulus between the housing and the mandrel. The first annular seal can separate the housing into the first and second chambers. The second chamber has a first variable volume defined between the first annular seal and the piston portion. In this example, the housing can also comprise a second annular seal disposed in the housing and sealing the annulus between the housing and the mandrel. The distal end of the mandrel in the retracted and extended conditions can be disposed beyond the second annular seal.

In the assembly, the bore of the mandrel in the extended condition can be configured to communicate: hydraulics for the media from the insertion port to a capillary line for the media line supported by the module; an eclectic cable for the media from the insertion port to another electric cable for the media line supported by the module; or an optical cable for the media from the insertion port to another optical cable for the media line supported by the module.

An assembly disclosed herein is operated by hydraulic pressure for fluid injection through a wellhead to a capillary line. The wellhead has at least one gate valve mounted above the wellhead. The assembly comprises: a valve module, a housing, and a mandrel.

The valve module is configured to install in the wellhead and is configured to support the capillary line extending therefrom. The valve module is actuatable from a closed condition to an opened condition. The valve module in the closed condition is configured to prevent fluid communication through the valve module, while the valve module in the opened condition is configured to allow fluid communication through the valve module;.

The housing is configured to mount above the at least one gate valve. The housing comprises: a first chamber having an injection port for the fluid injection, and a second chamber having a hydraulic port for the hydraulic pressure. The mandrel is disposed in the housing and defines a bore therethrough from a proximal end to a distal end. The proximal end is exposed in the first chamber. The mandrel is movable between a retracted condition and an extended condition in response to the hydraulic pressure in the second chamber. The mandrel in the retracted condition has the distal end retracted from the gate valve. The distal end of the mandrel in the extended condition is extended through the at least one gate valve and is configured to actuate the valve module from the closed condition to the open condition.

A method is disclosed herein for communicating a media through a wellhead to a communication line in a well. The wellhead has at least one gate valve mounted thereabove. The method comprises: supporting the communication line with a module; installing the communication line and the module through a top of the wellhead; mounting a housing above the at least one gate valve of the wellhead; moving a mandrel disposed in the housing from a retracted condition and an extended condition, a distal end of the mandrel in the retraced condition being retracted from the at least one gate valve; engaging the distal end of the mandrel in the extended condition through the at least one gate valve to the module; and communicating the media from an insertion port in the housing, through a bore of the mandrel, and to the communication line supported by the module.

For example, the method can be used for fluid injection through a wellhead to a capillary line in a well. This method can comprise supporting the capillary line with a capillary hanger; installing the capillary hanger in the wellhead; mounting a housing above the at least one gate valve; moving a mandrel disposed in the housing from a retracted condition and an extended condition, a distal end of the mandrel in the retraced condition being retracted from the at least one gate valve; opening a first valve in the capillary hanger with the distal end of the mandrel in the extended condition being extended through the at least one gate valve to the first valve; and communicating the fluid injection from an injection port in the housing, through a bore of the mandrel, through the open first valve, and into the capillary line.

The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.

<FIG> illustrates a schematic view of a wellhead <NUM> for a well <NUM>. The wellhead <NUM> includes a casing head <NUM> having a tubing hanger <NUM> supported therein. As shown, the tubing hanger <NUM> can support a tubing string <NUM> in the well <NUM> and may support some existing capillary lines <NUM>.

Typically, above the casing head <NUM>, the wellhead <NUM> has one or more master valves <NUM>, which can be gate valves, to open and close fluid communication of the well <NUM> for the wellhead <NUM>. Above these, the wellhead <NUM> may have a flow tee (not shown) with a flow line gate valve (not shown) and a kill line gate valve (not shown) connected to piping and additional components.

During operations, a media line, such as a capillary line, cable, or the like for the well <NUM> may need to be run downhole in the well <NUM>. For example, an existing capillary line <NUM> may become clogged, broken, or otherwise become inoperable and may require replacement. In this case, operators may need to run a new capillary line <NUM> in the well. Alternatively, a new media line <NUM> may need to be deployed from surface for a particular purpose, such as to connect to downhole equipment or to inject chemicals. In such circumstances, operators will need to run the new media line <NUM> downhole though the wellhead <NUM> that is already assembled.

The present example shows several lines run downhole in the well. These lines can be used for a number of purposes. Some of the lines <NUM> may be existing capillary lines run in the well <NUM>. The existing lines <NUM> would typically be suspended from an existing tubing hanger <NUM> inside the wellhead <NUM>. For example, one or more capillary lines <NUM> can be used as a control line for surface-controlled subsurface equipment <NUM>, such as a hydraulically-actuated downhole tool, a surface-controlled subsurface safety valve (SCSSV), or the like, disposed downhole in the well <NUM>.

Some of the media lines <NUM>, <NUM>' may be newly installed media lines run in the well <NUM>, which are run through the existing master valve <NUM> and other components of the wellhead <NUM>. If an existing capillary line <NUM> becomes inoperable, for example, a new media line <NUM>' in the form of a hydraulic control line may need to be run downhole from the wellhead <NUM>. In another example, a new media line <NUM> can be used as an injection line for injecting chemicals to downhole into the well <NUM>. Chemicals from a chemical injection manifold <NUM> are injected down the capillary line <NUM> to a chemical injection valve <NUM> in the well. The chemical injection can be used to reduce corrosion in the well, to reduce buildup of wax and scale in the well, to enhance production, and the like. The media lines <NUM>, <NUM>, <NUM>' for the wellhead <NUM> can be used for these and other purposes known in the art.

Simply running a media line from a top cap of the wellhead <NUM> through the gate valve(s) <NUM> and other components of the wellhead <NUM> is not suitable in most cases. To run a media line on the existing wellhead <NUM>, operators would typically need to add a new tubing spool to the wellhead <NUM>, may need to modify or change out the lower master gate valve <NUM> on the wellhead <NUM>, may need to perform a hot-tap in the wellhead <NUM>, or may need to conduct some other remedial action, which can be cumbersome and complicated. Put simply, disassembling, moving, or changing parts of the existing wellhead <NUM> may not be desired in many instances.

In contrast to the typical remedial actions, a well connect assembly <NUM> of the present disclosure is instead used on the wellhead <NUM>. The well connect assembly <NUM> installs on the wellhead <NUM> so the assembly <NUM> can support a media line <NUM> or <NUM>' and can allow operators to perform fluid injection, communicate hydraulics, make electrical or optical connections, or perform other appropriate operation. The media line <NUM> or <NUM>' may be newly deployed in the well or may be already installed. For example, the well connect assembly <NUM> can support a capillary line for the media line <NUM> so operators can perform chemical injection. In another example, the well connect assembly <NUM> can support a hydraulic control line for the media line <NUM>' so hydraulic communication can be made to subsurface equipment <NUM>. In yet another example, the well connect assembly <NUM> can support an electric or optical cable for the media line <NUM>' so electric or optical communication can be made to subsurface equipment <NUM>. Examples that follow will primarily describe an arrangement in which the well connect assembly <NUM> supports a capillary line for the media line <NUM> so operators can perform chemical injection.

As briefly shown in <FIG>, the well connect assembly <NUM> includes an injection module <NUM> and a valve module <NUM>. The valve module <NUM> supports the capillary line <NUM> and is installed in the wellhead <NUM> below the gate valve(s) <NUM>. For example, the valve module <NUM> can install in the tubing hanger <NUM> of the wellhead <NUM> in an operation similar to that used to install a backpressure valve in a tubing hanger <NUM>. Suitable equipment, such as a running tool, polished rod, and the like can be used to install the valve module <NUM>.

As shown in <FIG>, the wellhead <NUM> has a lower master gate valve <NUM> installed on the casing head <NUM>, and the injection module <NUM> mounts above the master gate valve <NUM> on the wellhead <NUM>. If an upper master valve (not shown), a flow tee (not shown), and the like are present, these components can remain on the wellhead <NUM>, and the injection module <NUM> is mounted on top of the wellhead <NUM> at the top cap.

With the assembly <NUM> installed, an actuation device <NUM> actuates the assembly <NUM>. For example, the actuation device <NUM> can be a hydraulic (or pneumatic manifold that communicates hydraulics (or pneumatics) to a hydraulic port 114b on the injection module <NUM> to actuate the assembly <NUM>. While the assembly <NUM> is actuated, an injection manifold <NUM> injects chemicals, hydraulics, or other intended fluid into an injection port 114a of the injection module <NUM>, which can communicate down the assembly <NUM>, through the gate valve <NUM>, and to the valve module <NUM> installed in the tubing hanger <NUM>. The valve module <NUM> can then communication the fluid injection further through the supported capillary line <NUM> in the well <NUM>.

As can generally be seen, the well connect assembly <NUM> allows for a fluid connection to be made at surface to downhole in a well <NUM> without the need to add a tubing spool to the wellhead <NUM>, without the need to convert the master gate valve <NUM>, and without the need to perform other cumbersome or time-consuming operations. All the while, the wellhead <NUM> is protected from surface backpressure from the well <NUM>, and the well connect assembly <NUM> can be deactivated to maintain well integrity.

Having a general understanding of the well connect assembly <NUM>, discussion turns to <FIG>, which illustrate cross-sectional views of a well connect assembly <NUM> of the present disclosure that is hydraulically-actuated.

<FIG> shows a majority of an injection module <NUM> of a well connect assembly <NUM>, while <FIG> shows a remaining portion of the injection module <NUM> and shows a valve module <NUM> in the wellhead <NUM>. As shown in <FIG>, the injection module <NUM> includes a housing <NUM> and an internal mandrel <NUM>, which is movable in the housing <NUM>.

As shown in <FIG>, the housing <NUM> of the injection module <NUM> couples atop the wellhead <NUM>, which can have a number of different components. These components may be existing on the wellhead <NUM> and would depend on the existing implementation. Here, the wellhead <NUM> includes a casing hanger <NUM>, a tubing hanger <NUM>, a spool adapter <NUM>, and a lower master gate valve <NUM>. Other implementations may have different components for the wellhead <NUM> than shown here.

The casing head <NUM> has the tubing hanger <NUM> landed in a landing bowl <NUM> of the head bore <NUM>. Lock screws <NUM> can retain the tubing hanger <NUM> in place. For its part, the tubing hanger <NUM> can support a tubing string (not shown) in the well and may support capillary control lines 18b.

The adapter <NUM> is attached to the casing hanger <NUM> and has an adapter bore <NUM> that communicates with the hanger bore <NUM>. In this example, hot-tap modules <NUM> are attached to the adapter <NUM> to provide access to connector lines 18a that run from the adapter <NUM> to the tubing hanger <NUM>. These lines 18a can communicate through passages in the tubing hanger <NUM> to the existing control lines 18b supported by the tubing hanger <NUM>. Other implementations are possible.

The lower gate valve <NUM> is attached to the adapter <NUM>. As is typical, the gate valve <NUM> includes a bonnet actuator <NUM> that can move a gate <NUM> inside the valve <NUM> relative to gate seals <NUM> to open or close fluid communication through the valve <NUM>. As shown in <FIG>, the lower end of the injection housing <NUM> of the well connect assembly <NUM> is attached above the gate valve <NUM> in this example.

Returning to <FIG>, the injection housing <NUM> can include an upper spool 111a that connects to a lower spool 111b and can include a top cap <NUM> to enclose the inside of the housing <NUM>. The modular configuration facilitates assembly, but other configurations for the housing <NUM> can be used.

The housing <NUM> includes an injection chamber 112a separated from a hydraulic chamber 112b by an annular seal 124a, which seals against the internal mandrel <NUM>. (<FIG> discussed below shows details of the annular seal 124a. ) The internal mandrel <NUM> is movably disposed in the housing <NUM> against the bias of a return spring <NUM> or other biasing element. For example, the spring <NUM> is a compression spring disposed in the housing <NUM>. An upper end of the spring <NUM> fit against a shoulder of a piston portion <NUM> of the mandrel <NUM>, and a lower end of the spring <NUM> as shown in <FIG> fits against a shoulder in the housing <NUM>. Other biasing arrangements can be used.

As best shown in <FIG>, the mandrel <NUM> defines a flow bore <NUM> therethrough from a proximal end to a distal end. Additionally, the mandrel <NUM> includes a first (upper) flow tube portion 121a at the proximal end and includes a second (lower) flow tube portion 121b at the opposite distal end. The piston portion <NUM> is disposed between the flow tube portions 121a-b and has an annular seal <NUM> that slideably seals in the housing <NUM>.

The housing <NUM> includes an insertion or injection port 114a for insertion or injection of media, chemicals, hydraulics, or the like into the injection chamber 112a. Likewise, the housing <NUM> includes a hydraulic port 114b for introducing hydraulic fluid into the hydraulic chamber 112b. Meanwhile, the annular seal 124a keeps the injection fluid in the injections chamber 112a separate from the hydraulic fluid in the hydraulic chamber 112b.

The hydraulic chamber 112b is a variable volume defined between the annular seal 124a and the piston portion <NUM> with its seals <NUM>. Increasing hydraulic pressure in the hydraulic chamber 112b applies force on the piston portion <NUM> to move the mandrel <NUM> down in the housing <NUM> against the bias of the spring <NUM>. Reduction in the hydraulic pressure in the hydraulic chamber 112b and the return bias of the spring <NUM> can move the mandrel <NUM> to its retracted position up in the housing <NUM>.

As shown in <FIG>, the distal end of the mandrel <NUM> includes a stinger <NUM>, which can have a check valve <NUM>. As also shown in <FIG>, the valve module <NUM> of the well connect assembly <NUM> includes a capillary hanger <NUM> and a valve <NUM>. The capillary hanger <NUM> is installed in a backpressure valve (BPV) profile <NUM> of the tubing hanger <NUM>. For example, an external thread profile <NUM> on the capillary hanger <NUM> can thread into the threaded BPV profile <NUM> of the tubing hanger <NUM>. A seal ring <NUM> on the capillary hanger <NUM> can seal against the inner bore <NUM> of the hanger <NUM>.

The capillary hanger <NUM> supports a capillary line <NUM> using a connector <NUM>. The valve <NUM> is disposed in the capillary hanger <NUM> and controls fluid communication with the capillary line <NUM>. In particular, the valve <NUM> is a no-return valve, a check valve, a poppet valve, or the like that prevents fluid communication from downhole to uphole (i.e., prevents backpressure from the well) and that allows fluid communication from uphole to downhole (i.e., allows the fluid injection to pass to the capillary line <NUM>). (<FIG> and <FIG> discussed below shows details of the capillary hanger <NUM> and the check valve <NUM>.

In <FIG>, the well connect assembly <NUM> is shown in an initial operational stage on the wellhead <NUM> before injection is performed. The gate valve <NUM> is closed, and the mandrel <NUM> is retracted to a retracted position in the housing <NUM>. In this position, the stinger <NUM> on the distal end of the mandrel <NUM> is retracted from the gate <NUM> and seals <NUM> of the gate valve <NUM> so the gate valve <NUM> can function as normal. In contrast, the well connect assembly <NUM> in <FIG> is shown in a subsequent operational stage on the wellhead <NUM> for injection to be performed.

To initiate injection operations, the gate valve <NUM> is opened so that the opening in the gate <NUM> aligns with the gate seals <NUM>, as shown in <FIG>. The check valve <NUM> on the stinger <NUM> can prevent well fluids from entering the bore <NUM> of the mandrel <NUM>. Additionally, the check valve <NUM> on the capillary hanger <NUM> can prevent well fluids from entering above the tubing hanger <NUM>.

As shown in <FIG>, hydraulic pressure at the hydraulic port 114b pumps the retractable mandrel <NUM> down in the housing <NUM>, through the open gate valve <NUM>, and into the tubing hanger <NUM>. The stinger <NUM> on the end of the mandrel <NUM> stings into the capillary hanger <NUM> and opens the check valve <NUM>. Injection fluid (e.g., chemicals, hydraulics, or the like) for the fluid injection are pumped into the injection chamber 112a from the injection port 114a. The injected fluid can now pass through the mandrel's bore <NUM>, through the open check valve <NUM>, and through the capillary hanger <NUM> to be conveyed via the capillary line <NUM> further downhole.

For the injection operation, the mandrel <NUM> is moved so the mandrel's bore <NUM> is connected in fluid communication to the capillary line <NUM> supported in the wellhead <NUM>. In the current examples, hydraulics drive down the mandrel <NUM> to make the connection. Other forms of actuation can drive the mandrel <NUM> down to make the connection. For example, pneumatic actuation as briefly mentioned above can drive the mandrel <NUM> to make the connection. In other example, a mechanical form of actuation having a motor, screw rod, gears, etc. using electricity, hydraulics, pneumatics, or the like for power can be used to drive the mandrel <NUM>.

Hydraulic actuation may be preferred for most implementations because the well connect assembly <NUM> can operate similar to a safety valve. If hydraulic pressure is lost (e.g., the hydraulic manifold fails, power is lost, etc.), the return spring <NUM> can retract the mandrel <NUM> in a fail-safe to stop injection when the hydraulic pressure drops in the hydraulic chamber 112b. The hydraulic manifold (<NUM>) connected to the hydraulic port 114b can be tied into or can be part of other systems at the wellsite, such as a shut-down system, which is used to shut in the well by closing the gate valve <NUM>. Should the shut-down system detect the need for shut in due to pressure measurements or the like, then the hydraulic manifold (<NUM>) can release hydraulic pressure in the chamber 112b so the manifold <NUM> retracts by operation of the spring <NUM>, allowing the gate valve <NUM> to be shut.

As further shown in <FIG>, a lower annular seal 124b seals the annulus between the housing <NUM> and the lower flow tube portion 121b of the mandrel <NUM>. This seal 124b can prevent well fluids from entering the second variable volume on the other side of the piston portion <NUM> where the spring <NUM> is located. Well pressure in this volume would act against the operation of the piston <NUM>. A vent port <NUM> can allow this volume to be evacuated. Also, if feasible, the port <NUM> could be used to hydraulically raise the mandrel <NUM> by having hydraulic fluid injected into the second variable volume between the piston portion <NUM> and the lower annular seal 124b while venting the first variable volume from the hydraulic port 114b.

<FIG> illustrates a detailed cross-sectional view of the stinger <NUM> and the capillary hanger <NUM>. The stinger <NUM> is shown disposed on the distal end of the mandrel <NUM> and includes a mandrel check valve <NUM> for controlling fluid communication with the mandrel's bore <NUM>. The capillary hanger <NUM> is installed in the BPV profile <NUM> of the tubing hanger <NUM> and includes a hanger check valve <NUM>. The stinger <NUM> is stung into a receptacle 152a of the capillary hanger <NUM>, and a distal tip <NUM> of the stinger <NUM> engages the check valve <NUM> of the capillary hanger <NUM>. Injected fluid from the mandrel's bore <NUM> can open the mandrel check valve <NUM>, can pass into the stinger passage <NUM>, can pass through the opened hanger check valve <NUM>, and can pass into the hanger passage 152b so the injected fluid can pass into the connector <NUM> of the capillary line (not shown).

Should the injection pressure in the mandrel's bore <NUM> fall below a predetermined level, the mandrel's check valve <NUM> will close, preventing back flow of fluids. Should the stinger <NUM> be unstung from the hanger's check valve <NUM> due to a reduction in hydraulic pressure against the mandrel <NUM>, the hanger's check valve <NUM> will close, preventing back flow of fluids.

<FIG> illustrates a detailed cross-sectional view of the annular seal 124a separating the chambers 112a-b of the injection housing <NUM> and sealing against the outer surface of the mandrel <NUM>. The annular seal 124a can be a gland seal thread into the mandrel's housing <NUM>, and the annular seal 124a can have inner and outer annular seal elements for sealably engaging between the housing <NUM> and the mandrel <NUM>. The inner seal elements of the annular seal 124a preferably allow for sliding sealing with the surface of the mandrel <NUM>, which is movable in the housing <NUM>.

<FIG> illustrates a detailed cross-sectional view of the check valve <NUM> for the capillary hanger <NUM>. The check valve <NUM> in this example is a poppet valve, but other types of valves can be used. A lower retainer 162b fits into the receptacle 152a of the hanger <NUM>, and an upper retainer 162a affixes in the receptacle 152a to hold a poppet <NUM> therein. A spring <NUM> biases the poppet <NUM> toward a seat <NUM> in the retainer 162a to seal off fluid communication from the hanger passage 152b up through the check valve <NUM>. When the distal tip <NUM> of the stinger <NUM> pushes against the poppet <NUM>, the poppet <NUM> unseats from the seat <NUM> and exposes bypass ports <NUM> in the poppet <NUM>. Fluid can now communicate through the open check valve <NUM>. Although not shown here, the check valve (<NUM>) for the stinger <NUM> may be comparably configured.

As noted above, the well connect assembly <NUM> can be used with wellheads of different configurations. <FIG> illustrates the well connect assembly <NUM> installed on another wellhead implementation. Here, the wellhead <NUM> is a production tree that includes a tubing head adapter <NUM> connected to a tubing head <NUM>. Lower and upper master valves 50a-b connect above the adapter <NUM>, and a studded cross <NUM> mounts to the top of the upper master gate valve 50b. As is typical, a flow line gate valve <NUM> and a kill line gate valve <NUM> connect to opposite sides of the studded cross <NUM>, and the gate valves <NUM> and <NUM> connect to additional components (e.g., piping, chokes, etc.).

The master gate valves 50a-b can be opened and closed to control flow for the wellbore. The flow line and kill line gate valves <NUM>, <NUM> are used to control the flow line and kill lines (not shown). The top cap <NUM> can be removed to provide access to the wellbore for various operations. For example, a capillary line (not shown) connected the valve module <NUM> can be installed through the wellhead <NUM> using standard procedures, and the valve module <NUM> can be installed in a tubing hanger <NUM> in the casing hanger <NUM>. The well connect assembly <NUM> can then connect to the top of the studded cross <NUM> in place of the top cap <NUM>.

The well connect assembly <NUM> can operate as before. In the retracted position, the mandrel <NUM> is retracted from the gate valves 50a-b. In the extended position, the mandrel <NUM> is extended through the open gate valves 50a-b to the valve module <NUM> (having the capillary hanger <NUM> and check valve <NUM>) installed in the tubing hanger <NUM> of the wellhead <NUM>.

As noted above, the well connect assembly <NUM> of the present disclosure may be hydraulically actuated, but other forms of actuation can drive the mandrel <NUM> down to make the connection. For example, a mechanical form of actuation having a motor, screw rod, gears, etc. could be used to drive the mandrel <NUM>. <FIG> is an example of one such mechanical arrangement for an actuation device <NUM>'. The rest of the components of the injection module <NUM> can be the same as before.

The housing <NUM> includes an opening, pocket, enclosure, etc. for a pinion gear <NUM> exposed in the lower chamber 112b. The mandrel <NUM> includes a rack gear <NUM> along a portion of its length for engagement with the pinion gear <NUM>. A motor (not shown) for the actuator device <NUM>', which can be hydraulic, pneumatic, electric, or the like, can rotate the pinion gear <NUM> to lower the mandrel <NUM> to extend the mandrel <NUM> to its extended condition to make the fluid connection. The motor for the actuator device <NUM>' can reverse the rotation to raise the mandrel <NUM> to its retracted condition, or a torsion spring (not shown) on the pinion gear <NUM> can reverse the rotation of the pinion gear <NUM> upon release of the motor or a clutch arrangement. Appropriate sealing is used for the housing <NUM> to seal the pinion gear <NUM> and the rack gear <NUM>. For example, a rotary seal <NUM> can be provided for the pinion gear <NUM>, and a glandular seal 124b can be used between the housing <NUM> and the mandrel <NUM> to seal the rack gear <NUM>.

<FIG> is an example of another mechanical arrangement of an actuation device <NUM>' in the form of a worm gear screw jack. The housing <NUM> includes an opening, pocket, enclosure, etc. for a worm <NUM> engaged with a worm gear <NUM> exposed in the lower chamber 112b. The mandrel <NUM> includes a screw gear <NUM> along a portion of its length for engagement with a threaded interior of the worm gear <NUM>. A motor (not shown) for the actuator device <NUM>', which can be hydraulic, pneumatic, electric or the like, can rotate the worm <NUM>, which rotates the worm gear <NUM> to translate the mandrel <NUM> to extend the mandrel <NUM> to its extended condition to make the fluid connection. The motor for the actuator device <NUM>' can reverse the rotation to raise the mandrel <NUM> to its retracted condition, or a torsion spring (not shown) on the worm <NUM> can reverse the rotation of the worm gear <NUM> upon release of the motor or a clutch arrangement. Appropriate sealing is used for the housing <NUM> to seal the worm <NUM> and the screw gear <NUM>. For example, a rotary seal <NUM> can be provided for the worm <NUM>, and a glandular seal 124b can be used between the housing <NUM> and the mandrel <NUM> to seal the screw gear <NUM>.

As will be appreciated, bearings, shafts, sleeves, and other necessary features are not shown in <FIG>. These and other forms of mechanical configurations can be used.

As noted above, the well connect assembly <NUM> can be used for communicating hydraulics and chemicals through the wellhead <NUM>, but other forms of media can be communicated by the well connect assembly <NUM> through the wellhead <NUM>. For example, physical connections for electrical and optical communications can also be achieved using the disclosed assembly <NUM>.

<FIG> show an example of the well connect assembly <NUM> providing a connection for electrical and optical communications according to the present disclosure. The assembly <NUM> includes components similar to other embodiments discussed above so the same reference numerals are used for similar components. As shown here, the housing <NUM> mounted on the wellhead <NUM> includes an insertion port for inserting the media, namely an insertion assembly <NUM> for inserting a capillary line, electrical cable, fiber optics cable, or other type of media line into the housing <NUM>. The insertion assembly <NUM> can include a stuffing box, packing glands, hangers, couplings, and other components used in the art. The media lines <NUM>/<NUM> can include a cable used for a deployed electric submersible pump (ESP) system. In another example, the media lines <NUM>/<NUM> can be used to run fiber optic lines downhole to a thru-tubing fibre optic reservoir monitoring system or the like.

In a simple arrangement, a media line <NUM> can be inserted through the insertion assembly <NUM> and can be run down through the mandrel <NUM> that is stung into the tubing hanger <NUM>. If a back-pressure valve (not shown) is present in the tubing hanger <NUM>, the media line <NUM> can pass through and open the valve. From there, the media line <NUM> can be run further downhole from the wellhead <NUM>. Should the mandrel <NUM> be retracted, however, the media line <NUM> would remain passing through the gate valve <NUM>. The media line <NUM> would need to be retrieved or broken for the gate valve <NUM> to close.

In another arrangement, a media line <NUM> can be inserted through the insertion assembly <NUM> to make a connection to another media line <NUM> supported on a hanger <NUM> in the wellhead <NUM>. A coupling <NUM>, for example, on the end of the media line <NUM> can make a connection to another coupling <NUM> for the media line <NUM> supported on the hanger <NUM>. The coupling <NUM> may be supported at the distal end or stinger of the mandrel <NUM> so the connection can be made as the mandrel <NUM> is moved and stung into the hanger <NUM>.

The mandrel <NUM> can be driven as before so that the distal end stings into the hanger <NUM>, as shown in <FIG>. This stinging can open a one-way valve (not shown), such as a flapper valve or other type of valve, on the hanger <NUM> if present. The media line <NUM> from the well connection assembly <NUM> can thereby connect with the media line <NUM> in the well through the connection of the couplings <NUM>, <NUM>.

Should the mandrel <NUM> be withdrawn for this arrangement, the media line <NUM> passed through the stuffing box <NUM> can be unconnected from the hanger <NUM> at the couplings <NUM>, <NUM>, and the media line <NUM> can be moved up through the gate valve <NUM> with the retraction of the mandrel <NUM>.

<FIG> illustrate schematic views for mandrels <NUM> of the present disclosure. As shown in <FIG> and consistent with previous arrangements, the mandrel <NUM> can be a unitary component having an upper flow tube portion 121a, a piston portion <NUM>, and a lower flow tube portion 121b. As shown in <FIG>, the mandrel <NUM> can be comprised of two or more components, facilitating assembly. For example, here, the upper flow tube portion 121a and the piston portion <NUM> may be a unitary component with the lower flow tube portion 121b being attached (e.g., threaded) thereto. An opposite arrangement can be used, or all three components 121a-b, <NUM> can be separate elements.

Finally, as shown in <FIG>, previous arrangements for the mandrel <NUM> require the assembly's housing to extend a give height H so that the upper flow tube portion 121a can remain sealed with the upper seal 124a as the mandrel <NUM> is moved down. The required height H can be reduced by using a telescopic arrangement for the mandrel <NUM>.

For example, <FIG> illustrates a schematic view for a telescopic mandrel <NUM> of the present disclosure in which the mandrel <NUM> is comprised of two or more telescoping components. Here, the lower tube portion 121b' and the piston portion <NUM> can be a unitary component, while the upper tube portion 121a' is a telescoping component disposed in the lower tube portion 121b'. The telescoping components use appropriate seals (not shown) and catches (not shown) therebetween. An edge of the upper tube portion 121a' can be in contact with a shoulder <NUM> or the like of the assembly's housing. Movement downward by hydraulic pressure against the piston portion <NUM> can then stroke the lower tube portion 121b' down along the length of the upper tube portion 121a' against the bias of the spring <NUM>. The upper seal 124a maintains a seal with the upper tube portion 121a'; the lower seal 124b maintains a seal with the lower tube portion 121b'; and an intermediate seal 124c seals between the tube portions 121a', 121b'. This stroking of the telescopic portions 121a', 121b' can reduce the height required for the assembly's housing, but the arrangement would increase the number of possible leak paths that need to be properly sealed.

Claim 1:
An assembly (<NUM>) for communicating a media through a wellhead (<NUM>) to a media line (<NUM>, <NUM>) in a well, the wellhead (<NUM>) having at least one gate valve (<NUM>) mounted above the wellhead (<NUM>), the assembly (<NUM>) comprising:
a module (<NUM>) configured to install in the wellhead (<NUM>) and configured to support the media line (<NUM>, <NUM>) extending therefrom;
a housing (<NUM>) configured to mount above the at least one gate valve (<NUM>) and having an insertion port (114a, <NUM>) for insertion of the media into the housing (<NUM>); and
a mandrel (<NUM>) disposed in the housing (<NUM>) and having a proximal end (121a) and a distal end (121b, <NUM>), the mandrel (<NUM>) defining a bore (<NUM>) therethrough from the proximal end (121a) to the distal end (121b, <NUM>) for communicating the media through the mandrel (<NUM>), the mandrel (<NUM>) being movable between a retracted condition and an extended condition, the mandrel (<NUM>) in the retracted condition having the distal end (121b, <NUM>) retracted from the at least one gate valve (<NUM>), the mandrel (<NUM>) in the extended condition being extended through the at least one gate valve (<NUM>), having the distal end (121b, <NUM>) engaged with the module (<NUM>), and being configured to communicate the media with the media line (<NUM>, <NUM>).