Wellsite equipment replacement system and method for using same

A system and method for replacing equipment at a wellsite is provided. The wellsite has a subsea stripper installed proximate a subsea borehole. The system has a conveyance for delivering a BHA into the subsea borehole. The system has a subsea stripper having a central bore for passing the conveyance and the BHA therethrough, and at least one actuator connected to the subsea stripper for actuating a packer whereby the wellbore is sealed. The system has at least one replaceable seal assembly for installation within the stripper. The replaceable seal assembly has at least one packer extendable within the subsea stripper to form a seal thereabout and at least one locator sleeve for positioning the seal assembly in an install position within the subsea stripper. The replaceable seal assembly has a frangible member for connecting the seal assembly to the conveyance prior to deployment in the subsea stripper.

BACKGROUND OF THE INVENTION

The present invention relates to techniques for replacing equipment at a wellsite. More specifically, the invention relates to techniques for replacing equipment, such as blowout preventers (BOPs), strippers, and/or components thereof used, for example, in subsea applications.

Oilfield operations are typically performed to locate and gather valuable downhole fluids. Oil rigs are positioned at wellsites, and downhole tools, such as drilling tools, are deployed into the ground to reach subsurface reservoirs. Many oilfield operations occur in the sea, or ocean. Subsea oilfield operations typically require the wellhead and other wellsite equipment to be located on the seabed, while an oil platform or vessel may be located at the water's surface. The wellsite equipment located at the seabed may comprise equipment, such as blow out preventers (BOPs), strippers, control devices, supporting tubing injectors, tubing reels, wireline units, or other subsea equipment.

In sub-sea oil and gas operations, there is often a need for a pressure barrier for moving conveyances, such as a slickline or coiled tubing. The stripper may act as a seal, or pressure barrier, that the conveyance is run through. As the coiled tubing is fed through the stripper, the stripper may seal the outer surface of the coiled tubing, thereby preventing sea water from entering the well, and/or wellbore fluids from leaving the wellbore inadvertently. The BOP may act as a safety device designed to ‘seal in’ large pressure surges in the wellbore. The BOP may have rams that automatically shut thereby closing and sealing in the wellbore.

The subsea equipment may become damaged over the life of the drilling operations. In some cases, the subsea equipment may be repaired and/or replaced by subsea divers, and/or brought to the surface by the diver. Techniques for performing repairs and/or replacement of certain wellsite equipment are disclosed, for example, in U.S. Pat. Nos. 3,741,296; 6,484,808; 5,961,094; 6,012,528; and 6,113,061 and U.S. Publication Nos. 2008/0185153; 2008/0185152; and 2009/0152817, the entire contents of which are incorporated by reference.

Despite the development of techniques for replacing BOP and/or stripper components, there remains a need to provide advanced techniques for performing replacement operations.

SUMMARY

In at least one aspect, the present invention relates to a replaceable seal assembly. The replaceable seal assembly is for sealing equipment at a wellsite. The wellsite has a subsea stripper installed proximate a subsea borehole and a conveyance for delivering a BHA into the subsea borehole. The replaceable seal assembly has at least one packer extendable within the subsea stripper to form a seal thereabout. The replaceable seal assembly has at least one locator sleeve for positioning the seal assembly in an install position within the subsea stripper. The replaceable seal assembly has a frangible member for connecting the seal assembly to the conveyance prior to deployment in the subsea stripper.

The packer(s) of the replaceable seal assembly may have two packers with the at least one locator sleeve located therebetween, and an actuation sleeve(s) for actuating the at least one packer. The actuation sleeve(s) of the replaceable seal assembly may have a tapered end for engaging an actuator of the subsea stripper. The tapered end axially aligns the seal assembly within the subsea stripper. The locator sleeve(s) of the replaceable seal assembly may have a guide for aligning the seal assembly in the install position when the guide is engaged by a locator sleeve actuator of the subsea stripper. The guide may have a reduced necked-down dual chamfer. The replaceable seal assembly may have a sleeve connection member for linearly coupling the at least one packer to the at least one locator sleeve, and a neck portion of the locator sleeve and having a shoulder extending therefrom, and a connector segment having a groove and at least one upset proximate to the groove, wherein the groove is for receiving the shoulder. The connector segment may have a plurality of connector segment joints for radially expanding and contracting the connector segment. The frangible member of the replaceable seal assembly may be a shear pin and/or a neck-down shear area.

In at least one aspect, the present invention relates to a system for replacing equipment at a wellsite. The wellsite has subsea equipment installed proximate a subsea borehole and a conveyance for delivering a BHA into the subsea borehole. The system has a subsea stripper having a central bore for passing the conveyance and the BHA therethrough. The system has at least one replaceable seal assembly for installation within the stripper. The replaceable seal assembly has at least one packer extendable within the subsea stripper to form a seal thereabout. The replaceable seal assembly has at least one locator sleeve for positioning the seal assembly in an install position within the subsea stripper. The replaceable seal assembly has a frangible member for connecting the seal assembly to the conveyance prior to deployment in the subsea stripper. The system has at least one actuator for actuating the packer whereby the wellbore is sealed.

The actuator(s) of the system has a packer actuator and a locator actuator. The locator actuator of the system is for engaging a locator sleeve of the seal assembly and thereby moving the seal assembly to an install position. The locator actuator of the system has an engager for mating with a guide on the locator sleeve. The packer actuator of the system has a motivator for motivating the packer within the subsea stripper and the motivator moves in a longitudinal direction relative to the seal assembly during actuation of the packer and moves in a radial direction in order to allow the seal assembly to be installed and removed from the stripper. The motivator of the system has a slip surface for engaging a bowl of the packer actuator and the slip surface and the bowl are for facilitating the movement of the motivator in the radial direction. The motivator of the system may engage an actuator sleeve of the seal assembly.

In at least one aspect, the present invention relates to a method for replacing equipment at a wellsite. The wellsite has a subsea stripper located proximate a subsea wellbore. The method comprises connecting a seal assembly to a conveyance for delivering a BHA. The seal assembly has at least one packer extendable within the subsea stripper to form a seal thereabout. The seal assembly has at least one locator sleeve for positioning the seal assembly in an install position within the subsea stripper. The seal assembly has a frangible member for connecting the seal assembly to the conveyance prior to deployment in the subsea stripper. The method comprises deploying the conveyance into the subsea stripper and passing the seal assembly past at least one actuator within the subsea stripper. The method comprises locating the seal assembly in the install position with a locator actuator. The method comprises actuating at least one of the packers of the seal assembly into sealing engagement with the conveyance.

The locating of the seal assembly comprises actuating a motivator of at least one packer actuator into a position for engaging the seal assembly. Further, the locating of the seal assembly comprises engaging the motivator with seal assembly. The method comprises breaking the frangible member and thereby disengaging the conveyance from the seal assembly and opening a stop located below the subsea stripper after the seal assembly is in sealing engagement with the conveyance. The method comprises running the conveyance and the BHA past the stop and performing downhole operations. The method comprises removing the seal assembly, the conveyance and the BHA from the subsea stripper and installing a new conveyance with a new seal assembly, wherein the conveyance has an outer diameter and the new conveyance has second outer diameter.

DETAILED DESCRIPTION OF THE INVENTION

The description that follows includes exemplary apparatus, methods, techniques, and instruction sequences that embody techniques of the present inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.

It may be desirable to provide techniques that are capable of performing at even high depths. It may be further desirable that such techniques be performed remotely and/or automatically. Preferably, such techniques involve one or more of the following, among others: efficient replacement, reduced downtime, simpler structure, reduced manning, etc. The present invention is directed to fulfilling this need in the art.

This application relates to a pressure barrier, such as that provided by a packer, or seal assembly disclosed herein, that contains two sealing elements, or packers, into the same body or housing so that tools can be delivered and retrieved therethrough without the limitation of having to disconnect the guide, for example. This may result in a sealing mechanism, or seal assembly, that may either be retrievable or have the functionality to seal on small diameters (e.g., slickline) while being capable of opening to a diameter large enough for tools to pass through. A tool catcher may also be included.

Such a dynamic seal, or seal assembly, may include a body with a single packer element, although two complete units may be used to comply with certain operational requirements. However, a dual-packer system within a single body or housing is shown and described below.

The structure disclosed herein may be applied to a unit, or stripper, to accommodate both coiled tubing and slickline; or may be adapted to one or the other of these applications, such as, for example, slickline-specific. The system also preferably provides a dual acting piston, packer actuators, and system that allows full control over de-energizing the packing element, or packers, when returning to surface.

The dual-packer structure shown and described below may provide a number of advantages over using two complete single-packer arrangements. For example, the dual-packer assembly reduces the overall weight of the system. This design provides the same functionality as its dual-packer predecessor and weighs an estimated 42% less than its predecessor. The dual-packer structure is also modular in design. The unit is comprised of modular subassemblies, or seal assembly. Downtime may be reduced due to the ability to replace upper or lower subassemblies. The dual-packer structure also preferably has fewer components. The design may rely on two actuators, or packer actuators, versus six. This arrangement also may have fewer hydraulic circuits. Two tandem single-packer assemblies may use five hydraulic circuits; whereas, the dual-packer system may require only three.

FIG. 1depicts an offshore wellsite100having a stripper102with an equipment replacement system104. The equipment replacement system104is preferably configured for replacing subsea equipment without the need for removing the equipment, such as the stripper102, using, for example, a remotely operated vehicle (ROV) and/or a diver to replace the equipment. As shown, the equipment replacement system104is located within the stripper102of a subsea system106positioned on a seabed107. A portion of the equipment replacement system104may be configured to run into the subsea equipment108on a conveyance110. The equipment replacement system104may then be actuated in order to seal the conveyance110within the stripper102while allowing the conveyance110to move into and/or out of a wellbore112.

The subsea system106may comprise the stripper102, a blow out preventer (BOP)114, a wellhead116, a conduit118, and a conveyance delivery system120. The conveyance delivery system120may be configured to convey one or more downhole tools122into the wellbore112on the conveyance110. Although the equipment replacement system104is described as being used in subsea operations, it will be appreciated that the wellsite may be land or water based and the equipment replacement system104may be used in any drilling environment. A surface system124may be used to facilitate the oilfield operations at the offshore wellsite100. The surface system124may comprise a rig126, a platform128(or vessel) and a controller130. Further, there may be one or more subsea controllers132. As shown the controller130is at a surface location and the subsea controller132is in a subsea location, it will be appreciated that the one or more controllers130/132may be located at various locations to control the surface and/or subsea systems.

The conveyance delivery system120, as shown, is located proximate the subsea equipment108, for example the stripper102and the BOP114. The conveyance110in an example may be a coiled tubing. The conveyance delivery system120may be, for example, a coiled tubing injector. The coiled tubing injector may inject and/or motivate the coiled tubing and/or downhole tool122into the wellbore112through the subsea equipment108. As shown, the conveyance delivery system120is located within the conduit118, although it should be appreciated that it may be located at any suitable location, such as at the sea surface, proximate the subsea equipment108, without the conduit118, and the like. Although the conveyance delivery system120is described as being a coiled tubing injector, it should be appreciated that the conveyance delivery system120may be any suitable device for conveying the conveyance110through the subsea equipment108and into the wellbore112. Further, the conveyance110may be any suitable conveyance110such as a wireline, a slickline, a production tubing, and the like. The downhole tools122may be any suitable downhole tools for drilling, completing, evaluating and/or producing the wellbore112, such as drill bits, packers, testing equipment, perforating guns, and the like.

The stripper102is preferably configured to allow the conveyance110to pass through the stripper102and into other subsea equipment, such as the BOP114, without allowing seawater into the wellbore112and/or allowing wellbore fluids out of the wellbore112. Portions of the equipment replacement system104may be located in and/or proximate to the stripper102. Portions of the equipment replacement system104may further be locatable within the stripper102and may be run into the stripper102on the conveyance110.

FIG. 2shows a schematic view of the subsea equipment108as shown inFIG. 1. The equipment replacement system104, as shown, comprises the stripper102and a seal assembly200. The seal assembly200may be run in on the conveyance110with a downhole tool122thereon disposable through the stripper102. The stripper102, the BOP114and/or a stop206may be installed on the wellhead116of seabed107. The stripper102may initially not have the seal assembly200within the stripper102. The conveyance110coupled to the seal assembly200may be located proximate the stripper102. Prior to installation of the seal assembly200into the stripper102, the stripper102may be in the unactuated, or open position, as will be discussed in more detail below.

FIG. 3A-3Deach show a longitudinal, cross-section view of the stripper102, ofFIG. 2taken along line A-A, and a schematic, cross-sectional view of the equipment replacement system104ofFIGS. 1 and 2having the seal assembly200and one or more actuators202located within the subsea equipment108. TheFIGS. 3A-3Ddepict a sequence for using the equipment replacement system104. The seal assembly200may be connected to the conveyance110prior to locating the seal assembly200into the subsea equipment108. The conveyance110may deliver the seal assembly200into the subsea equipment108where the one or more actuators202may locate the seal assembly200in the proper (or install) position, and/or actuate one or more packer assemblies204in the seal assembly200, as will be describe in more detail below.

As shown inFIGS. 3A-3D, the seal assembly200is run into the stripper102wherein the one or more actuators202actuate the seal assembly200into a sealing engagement with the conveyance110. Initially all of the one or more actuators202are in an open position as shown inFIG. 3A. In the open position, the downhole tools122, the conveyance110and/or the seal assembly200may pass through the actuators202without obstruction.FIG. 3Ashows the seal assembly200secured to the conveyance110prior to being run into the subsea equipment108. As shown, the seal assembly200will be run into and secured in the stripper102. The seal assembly200may be removed from the conveyance110once secured in the stripper102, for example, by a frangible connection as will be described in more detail below. Although theFIGS. 3A-3Dshow the seal assembly200being secured about the stripper102. The seal assembly200may be secured about any of the suitable subsea equipment108, such as the BOP114(as shown inFIG. 1).

The seal assembly200coupled to the conveyance110may then be run into the subsea equipment108until the downhole tool122, the end of the conveyance110and/or a portion of the seal assembly200engages a stop206as shown inFIG. 3B. As shown, the downhole tool122engages the stop206. The stop206may be any suitable device for stopping the conveyance110and/or notifying the controller(s)130/132, or operator that the seal assembly200is within the stripper102. The stop206may be a valve, a ram of the BOP114and/or a sensor208located in the subsea equipment108. As shown, inFIG. 3B, the stop is located at a position below the stripper102. This position may allow the entire seal assembly200to enter stripper102prior to stopping the conveyance110. With the stop206engaged, one of the one or more the actuators202may be actuated in order to engage the seal assembly200. Once the downhole tool(s)122(or tool string) with the seal assembly200(or consumable arrangement) has been logistically located about the stripper102, the upper actuator202(or the upper piston) may be closed. The uppermost of the actuators202(or an upper locking sleeve) may be actuated in order to move a portion of the actuator202to a location proximate the conveyance110. With the uppermost actuator202actuated, the conveyance110may be pulled up to locate the seal assembly200proximate the stripper102, as shown inFIG. 3C.

The uppermost actuator202may engage the seal assembly200as the conveyance110is pulled up in order to locate the seal assembly200proximate an actuation position as shown inFIG. 3C. Another of the actuators202may then be actuated in order to locate the seal assembly200in the install position. As shown, the middle actuator202may engage the seal assembly200in order to locate the seal assembly200in the install position. The seal assembly200and/or the actuator(s)202may have a locator, or a locator sleeve, configured to locate the seal assembly200in the install position as will be discussed in more detail below.

With the seal assembly200in the install position, the actuators202may all be actuated in order to secure the seal assembly in the stripper102and/or engage the one or more packer assemblies204into a sealing engagement with the conveyance110, as shown inFIG. 3D.

The upper actuator and lower actuator202may be configured to actuate the one or more packer assemblies204into sealing engagement with the conveyance110while the middle actuator202may be configured to locate the seal assembly200in the install position. With the seal assembly200in sealing engagement with the conveyance110, the conveyance110may be detached from the seal assembly200, for example by breaking a frangible member as will be discussed below. The stop206may then be opened and the conveyance110and the downhole tools122may be run into the wellbore112(as shown inFIGS. 1 and 3D). For example, if the stop206is a valve, the valve may be opened, if the stop206is the BOP114, the rams of the BOP114may be opened, thereby providing an opening for the conveyance110and/or the downhole tool122to move through.

The seal assembly200may remain in this actuated position as the conveyance110and downhole tools122run into the well to perform downhole operations in the wellbore112. When the downhole operations are complete and/or the seal assembly200needs to be replaced, the conveyance110may run the downhole tools122up into the subsea equipment108until the downhole tools122pass the stop206. The stop206may then be closed and the actuators202may be disengaged in order to allow the conveyance110and downhole tool122to pass through the stripper102. As the downhole tool122passes through the stripper102, the seal assembly200is taken out of the stripper102with the downhole tools122as shown inFIG. 3A.

A new seal assembly200may then be used on the next conveyance110to enter the wellbore112. The new seal assembly200may be placed on the same type of conveyance110used previously, for example the coiled tubing, or may be used on a different type of conveyance110, for example a slick line, a wire line, a different sized coiled tubing, and the like. Although shown as having two packer assemblies204and three actuators202, it should be appreciated that the equipment replacement system104may have any number of packer assemblies204for example one, and any suitable number of actuators202for example one. Further, the location of the actuators202and the one or more packer assemblies204may be moved to any suitable location so long as the seal assembly200may sealingly engage the conveyance110.

FIG. 4Ashows a longitudinal, cross-sectional view of the seal assembly200ofFIG. 3Ataken along line B-B. As shown, the seal assembly200has a central bore300, the one or more packer assemblies204, a locator sleeve302, and one or more actuation sleeves304. The central bore300of the seal assembly200may have an inner diameter306that is slightly larger than the outer diameter308of the conveyance110to be run through the seal assembly200. The inner diameter306of the seal assembly200may be changed for the type of conveyance110that is going to be used while keeping the same outer dimensions suited for the installed stripper102of the subsea equipment108(as shown inFIG. 1). Thus, in order to use a smaller or larger outer diameter conveyance110, the seal assembly200may be changed to the seal assembly200having the inner diameter306corresponding to the smaller or larger conveyance110.

A frangible member310, as shown inFIG. 4A, may be secured to the conveyance110and the seal assembly200prior to, or during, installation of the seal assembly200. The frangible member310may be any suitable device configured to secure the seal assembly200to the conveyance110while the seal assembly200is being run into and installed in the stripper102(as shown inFIG. 1). When the seal assembly200is installed into the stripper102, the seal assembly200is prevented from moving along a longitudinal axis of the conveyance110relative to the stripper102. By applying a large enough load to the conveyance110, the frangible member310may be broken thereby allowing the conveyance110to move in the longitudinal direction while the seal assembly200stays in the actuated position in the stripper102. The frangible member310is shown as coupling the actuation sleeve(s)304to the conveyance110, but it may be located at any suitable location on the seal assembly200. Further, there may be more than one frangible member310. The frangible member310may be any suitable member such as a shear pin, a shear area, and the like. Although the seal assembly200is shown as being coupled to and disconnected from the conveyance110using the frangible member310, any device suitable for temporarily securing the seal assembly200to the conveyance110may be used.

The locator sleeve302may be a locator sleeve314having a guide312(or an upset) on an outer surface of the locator sleeve314. The guide312may be configured to be engaged by at least one of the one or more actuators202(as shown inFIGS. 3A-3D) as will be discussed in more detail below. As shown, the guide312has a reduced necked-down dual chamfer (or a chamfer)315. The guide312, may extend around the circumference of the locator sleeve314, thereby allowing the guide312to be easily accessed by the one or more actuators202. Although the guide312is shown as the reduced necked-down dual chamfer, it should be appreciated that the guide312may be any suitable device for being engaged by the one or more actuators202and/or positioning the seal assembly200in the proper location within the stripper102, such as one or more indents, one or more grooves, one or more bosses and the like.

The locator sleeve314may be a substantially cylindrical sleeve with a similar inner diameter as the inner diameter306of the seal assembly200. The locator sleeve314may have a sleeve connection member316at one or more of the ends of the locator sleeve314. As shown inFIG. 4A, the locator sleeve314has the sleeve connection member316located at each end of the sleeve314. The sleeve connection member316may allow the locator sleeve314to couple to the other devices in the seal assembly200, such as the packer assemblies204and/or the actuation sleeve304. The sleeve connection members316may couple directly to the packer assemblies204or to a connector segment322.

FIG. 4Bshows the sleeve connection members316in greater detail. As shown, the sleeve connection members316may have a neck portion318and a shoulder320. The neck portion318may be a narrower portion of the locator sleeve314. The shoulder320may be a lip or ring that extends from the neck portion318. The neck portions318may be configured to extend into the connector segment322, or non-extrusion segment.

The locator sleeve314, as shown inFIGS. 4A and 4B, may be constructed of any durable material capable of engaging the one or more actuators202and guiding the seal assembly200into the install position in the stripper102(as shown inFIGS. 3A-3D). The material may further allow the locator sleeve314to support a portion of the packer assemblies204along the seal assembly200. The material may be brass, however, it may be any suitable material such as steel, metal, copper, ceramic, and the like.

The locator sleeve314may be coupled to and/or proximate the packer assemblies204. As shown inFIG. 4A, connector segments322couple to the locator sleeves314and hold a portion of the packer assembly204in place. Each of the packer assemblies204may comprise one or more bushings332, and a packer334. The one or more bushings332as shown inFIG. 3Ahave an upper bushing and a lower bushing. The upper bushing may be located on one side of the packer334while the lower bushing may be located on the opposite side of the packer334. The bushings332may be configured to secure the packer334in the seal assembly200and reduce the wear on the packer334during the life of the seal assembly200. The bushings332may be constructed of any suitable material such as metal, ceramics, plastics and the like. The bushings332as shown may take any shape so long as they secure the packer334in the seal assembly200.

The packer334as shown inFIG. 4Amay be a ring having the central bore300therethrough. The packer334may be an elastomeric material configured to expand into sealing engagement with the conveyance110upon compression of the packer334. Compression may be applied to the packer334via the one or more actuators202(as shown inFIGS. 3A-3D) as will be discussed in more detail below.

The one or more actuation sleeves304, as shown inFIG. 4A, may be a substantially cylindrical sleeve with a similar inner diameter as the inner diameter306of the seal assembly200. The one or more actuation sleeves304may be configured to engage the one or more actuators202(as shown inFIGS. 3A-3D). The actuators202may motivate the actuation sleeves304thereby actuating the packers334, as will be discussed below. The one or more actuation sleeves304may be constructed of a similar material as the locator sleeve314. The one or more actuation sleeves304may engage a portion of the packer assembly204in order to actuate the packer334. The one or more actuation sleeves304may couple to and/or engage the packer assembly204in any suitable manner. In one example, the one or more actuation sleeves304has the one or more sleeve connection members316that connect the sleeve304to the packer assembly204.

The one or more actuation sleeves304may have an actuation end336. The actuation end336may be configured to engage the actuator202(as shown onFIGS. 3A-3D), as will be discussed in more detail below. The actuation end336, as shown inFIG. 3A, has a tapered end338. The tapered end338may be configured to engage the actuators202, thereby securing the one or more actuation sleeves304and seal assembly200in the install position.

The connector segment322may be configured to secure the linearly aligned portions of the seal assembly200to one another. As shown inFIGS. 4A and 4B, the connector segment322may be a ring that surrounds the seal assembly200. The ring may have a groove324configured to envelope, or partially house the shoulder320of the locator sleeve314. The groove324may have an upset326on either side that extends into a portion of the locator sleeve314and/or the next seal assembly portion, in this case the packer assembly204. When assembled, the shoulder320may engage the groove324walls thereby preventing linear movement of the connector segment322relative to the locator sleeve314.

FIG. 4Cshows another connector segment (or non-extrusion ring) that may be used as the connector segment322ofFIGS. 4A and 4B. This connector segment322may be configured to expand and contract its diameter based on the size of the seal assembly200being used. To this end, the alternative connector segment322may have one or more joints328between a plurality of ring segments330. The joints328may allow the ring segments330to move toward and away from one another and thereby allowing the connector segments322to expand or contract in diameter.

FIG. 5Ashows a cross-sectional view of the stripper102ofFIG. 2taken along line A-A. The stripper102has the seal assembly200in the install position therein. The stripper102as shown may have an injection portion400, a seal assembly portion402, and a tool connection portion404. The injection portion400may serve as the entry and/or exit point for the conveyance110on the upstream side of the stripper102. The injection portion400may be configured to connect to a tool such as the conveyance delivery system120(as shown inFIG. 1). The conveyance delivery system120may deploy the conveyance110into the stripper102.

The tool connection portion404may be configured to secure the stripper102to another tool, and/or pipe, downstream of the stripper102, for example the BOP114(as shown inFIG. 1) and/or the stop206(as shown inFIG. 3A-3D). The tool connection portion404as shown is a flange configured to bolt onto the tool, although it should be appreciated that any connection may be used.

The seal assembly portion402of the stripper102may comprise a body with the actuators202therein and a stripper central bore406therethrough. The stripper central bore406may be configured to allow the conveyance110with the attached seal assembly200to enter and pass through the stripper central bore406when the stripper102is in an open position (as shown inFIG. 3A). The actuators202in the stripper102secure the seal assembly200within the stripper central bore406.

The seal assembly portion402of the stripper102, as shown inFIG. 5A, has two packer actuators408and two locator actuators410(or middle actuators). The locator actuators410may engage the locator sleeve302in order to axially align the seal assembly200in the stripper102. Each of the locator actuators410may have an engager412, a piston414and a cylinder416. The piston414and the cylinder416may operate like a standard piston and cylinder in order to axially extend and retract the piston414, and thereby the engager412. The engager412is configured to engage the locator sleeve302of the seal assembly200.

As shown inFIG. 5B, the engager412may have an upset418configured to mate with the guide312of the locator sleeve302. The upset418may have a sloped edge420(or beveled edge) configured to engage the dual chamfer of the guide312. As the sloped edge420of the engager412engages the dual chamfer315of the guide312, the sloped edge420may align the seal assembly200both axially along an X-X axis of the seal assembly200and centrally within the central bore406. Although the guide312and the engager412are described as having the dual chamfer315and the sloped edges420, the guide312and the engager412may have any suitable form capable of locating the seal assembly200at the install position within the stripper102, as shown inFIG. 5A.

The packer actuators408may be configured to sealingly engage the packer334against the conveyance110.FIG. 5Ashows two packer actuators408although there may be any suitable number of packer actuators408, such as one or more. The operation of the upper of the packer actuators408, as shown inFIG. 5Awill now be described in detail. The packer actuator408may have a packer piston422and a packer cylinder424configured to move a motivator426. The packer piston422and the packer cylinder424may operate like a standard piston and cylinder in order to axially extend and retract the packer piston414, and thereby the motivator426. As the packer piston414moves the motivator426in the axial direction, the motivator426may further move in the radial direction in order to selectively allow the seal assembly200to pass through the central bore406.

FIGS. 5C and 5Eare longitudinal, cross-sectional views of the injection portion400of the seal assembly200. As shown inFIG. 5C, the packer actuator408is in an unactuated position. In the unactuated position, the motivator426does not block movement of the seal assemblies200(as shown inFIG. 5A) into the central bore406of the stripper102. The motivator426may be one or more slip portions428.FIG. 5Dshows a horizontal, cross-sectional top view taken along line C-C (shown in whole) of the motivator426ofFIG. 5Ahaving four slip portions428located at 90° from one another. Each of the slip portions428, as shown inFIGS. 4C and 4Dmay have a slip body430and a slip central bore end432. The slip body430may have a slip surface434configured to engage a bowl436. As the motivator426is moved axially, the bowl436will engage the slip surface434, thereby moving the motivator426radial inward or outward.

FIGS. 5C and 5Dshow the one or more slip portions428in the unactuated position wherein the piston422is in a retracted position and the slip body430is proximate a first interior wall of the packer actuator408. As the piston422moves axially toward the actuated position (as shown inFIG. 5E), the slip surface434travels along the bowl436. The bowl436moves each of the one or more slip portions428radially inward as the piston422moves the slip portions axially down the bowl436. As the slip portions428move radially inward, the slip central bore end432moves into the central bore406of the stripper102as shown inFIG. 4E.

The slip portions may move radially inward until the slip portions426reach a seal assembly engagement position wherein the slip central bore ends432are positioned for engaging seal assembly200and/or actuating the packer334(as shown inFIG. 5A). In the seal assembly engagement position, the slip body430may be located between an outer piston surface442and a second interior wall438, as shown inFIG. 5E. The second interior wall438may be located proximate the bowl436and may have a substantially cylindrical wall, or wall substantially parallel to the central axis X-X. With the slip body430located between the second interior wall438and the outer piston surface442, the piston422may move the motivator426axially without further moving the slip portions430radially in order to actuate the packer334(as shown inFIG. 5D).

A motivator connector440may couple the motivator426to the piston422. The motivator connector440may be any suitable device that allows the motivator426to move axially with the piston while allowing the motivator426to move radially relative to the piston422. As shown, the motivator connector440is a pin connector coupled to the piston422and the motivator426.

The slip portions430of the motivator426may have a seal assembly engagement edge444. The seal assembly engagement edge444as shown in FIGS.5A and5C-5E is a sloped surface configured to engage the tapered end338of the actuation sleeve304of the seal assembly200. As the tapered end338of the seal assembly200is engaged by the seal assembly engagement edge444, the seal assembly200may be further aligned and secured along the central bore406of the stripper102. Although the seal assembly engagement edge444is shown as a sloped edge configured to engage the tapered edge338of the seal assembly, it should be appreciated that any arrangement for securing the seal assembly200to the actuators202within the stripper102may be used. The continued movement of the motivator426against the actuation sleeve304may actuate the one or more packers334into sealing engagement with the conveyance110.

The system may also include the hydraulic system, or a plurality of hydraulic operators which drive or move the one or more actuators202, the BOP114and/or the stop206(as shown in FIGS.1and3A-3D). One or more hydraulic lines450(as shown inFIG. 5A) may be supplied by one or more hydraulic systems. The hydraulic systems may have any suitable device and/or devices for controlling the one or more actuators202such as at least one pump, pressure gauges, relief valves, and the like. The hydraulic system and/or the one or more actuators202may be in communication with the controllers130and/or132in order to control the movement of the actuators202automatically and/or remotely. Although the one or more actuators202, the BOP114and/or the stop206are shown as being operated by the hydraulic system it should be appreciated that any suitable system and/or device and/or combination thereof may actuate the these components such as one or more servos, a pneumatic system, a mechanical actuator and the like.

FIGS. 6-12Cshow the operation of the equipment replacement system104ofFIG. 2in greater detail. These illustrations show the stripper102(or the unit) first in an open state allowing the conveyance110and the downhole tools122(or the tool string) to pass through the stripper102as shown inFIG. 6, and then in a closed state with the seal assembly200(or the brass/packer assembly) in place as shown inFIG. 8Aand being actuated as shown inFIG. 10. Illustrated also is the sequence of the conveyance110as it deploys the packers334(or the consumable packers and brass) through the stripper102and prepares to position them for further deployment of the downhole tools122, or the tool string as shown inFIG. 11A. The consumable components (brass bushings and packer elements) of the seal assembly200may be joined together to allow their deployment via the conveyance110(or the tool string) as shown inFIGS. 6-12C. This may be accomplished by using a bonding agent or by incorporating the brass into the molding of the packers, or by any suitable method including those described herein. In either configuration with the dual packing elements, the consumables will be configured as shown and described below. The packers334(or the packing elements) may be energized independently of one another. In an embodiment shown inFIG. 8B, the locator actuator410(or the middle actuators) locate the seal assembly200(or the brass and packers) while the motivators426of the packer actuators408(or the upper and lower locking sleeves) secure around the tapered end338(or the tapers of the actuation sleeves)304(or the upper and lower brass components). At this time, the upper or lower piston can be actuated to energize the packing element the operator chooses to use.

FIG. 6shows a cross-sectional view of the stripper102ofFIG. 2in the open position. In the open position, the actuators202are all unactuated, or retracted, thereby unobstructing the stripper central bore406. The conveyance110with the seal assembly200may then be run into the stripper102. To position the seal assembly200(or the brass and packer elements) into the stripper102unit, the seal assembly200components are lowered on the conveyance110(or tool string) until they reach a predetermined position. This position may be made known to the operator via the weight string indicator top-side when contact is made with the closed rams on the BOP114and/or the stop206as shown inFIG. 7A. In the case of the stripper102having a dual-packer design, the upper actuators (or the uppermost of the packer actuators)408may then be closed and the conveyance110(or tool string) may be pulled against the closed motivator426(or upper rams). The uppermost packer actuator408may be actuated in order to move a portion of the motivator426into the stripper central bore406, as shown inFIG. 7B. In this position, the motivator426may allow the conveyance110to move axially within the stripper102but will engage the seal assembly200.

The conveyance110may then be pulled toward the closed motivator426(or upwards) until the seal assembly200engages a portion of the uppermost packer actuator408, as shown inFIGS. 8A and 8B. The locator actuator410and the lowermost packer actuator408(or the middle and bottom rams respectively) are then closed to contain the seal assembly200(or the components) in place. Once the positioning is detected, the uppermost of the packer actuator408(or the upper piston) is actuated to the closed position and the seal assembly200(or the components) may be pulled against the uppermost motivator426(or the upper assembly). The actuators and lower piston are then closed around the seal assembly200(or the components) to hold their position. In both scenarios, a shearing function may then occur using either a shear pin, a frangible member and/or a slotted bushing. The bushings and packers may be properly in place with the BHA being free to travel downward.

The seal assembly200engaging the closed motivator426may be detected as a force increase in the conveyance110by the operator, and/or the controllers132and/or134. Upon detection of the seal assembly200engaging the uppermost actuator408, movement of the conveyance110may be temporarily stopped until the seal assembly200is in the install position.

With the seal assembly200engaged with the uppermost actuator408, the locator actuator406may be actuated to align the seal assembly in the install position, as shown inFIG. 9. The seal assembly200may be configured wherein the locator sleeve302is substantially aligned with the locator actuators410when the seal assembly200is engaged with the uppermost actuator408. As the locator actuator410actuates, the engager412engages the guide312. The engager412moves the guide312, and thereby the seal assembly200, into the install position as the engager412moves into engagement with the guide312. The lowermost actuator408may at this time still be in the unactuated position as shown inFIG. 9. Although the lowermost actuator408is shown as being unactuated while the locator actuator410engages the locator sleeve302, it should be appreciated that the lower actuator408and the locator actuator410may be actuated simultaneously.

The lowermost of the two packer actuators408may then be actuated until its corresponding motivator426engages the actuation sleeve304of the seal assembly200, as shown inFIGS. 10 and 11A. The seal assembly200is then located in the install position. The seal assembly200may then be actuated. The two packer actuators408may actuate the seal assembly by compressing the packers334between the actuation sleeve304and the locator sleeve302. This compression will force the elastomeric packer334into a sealing engagement with the conveyance110as shown inFIG. 11A. With the seal assembly200in the installed position, the packers334are sealingly engaged with the conveyance110.

Note the tapers (the seal assembly engagement edge444, and/or the tapered end338as shown inFIG. 5A) on both models and how the locking guides (or the motivator426) are forced open upon the primary (or upper) piston's (the uppermost packer actuator408) retraction and then closed around the corresponding chamfers on the upper brass (or tapered end338of the seal assembly200). Again, the actuators202hold the seal assembly200(or the consumable assembly) in place to allow energizing of one of the packers334, or other packing elements.

The seal assembly200(or the consumables) are first located and secured in the stripper102assembly. At this time force is put on the conveyance110(and/or the tool string) by the injector120(as shown inFIG. 1) resulting in the shearing/release of the conveyance110and/or the downhole tools122(or the BHA) from the seal assembly200(or the consumable package) where it continues its descent. This may be made possible due to the lower portion of the seal assembly200(or the consumable assembly package) that contains a “necked-down” shear area, as shown inFIG. 11B.

The conveyance110may then be moved in order to break the frangible member310, and/or1100inFIGS. 4A and 11B, and thereby uncouple the conveyance110from the seal assembly200. As discussed above, the frangible member may be a pin coupling the conveyance110to the seal assembly200. Further, the frangible member may be a neck-down shear area1100of the conveyance110at an end of the seal assembly200as shown inFIG. 11B. Thus, the frangible member may be a small neck of the seal assembly200, as shown on the lower side of the seal assembly200. When force is applied to the seal assembly200with the lower actuators202engaged with the seal assembly200, the neck-down shear area1100will break, thereby allowing the conveyance to move relative to the stripper102. The stop206and/or BOP114(as shown in FIGS.1and2A-2D) may then be opened to allow conveyance110and/or the downhole tools122to enter and perform operations in the wellbore112.

FIG. 11Cdepicts a schematic perspective view of the seal assembly200and the conveyance110coupled to one another. The seal assembly200as shown has a split1102design. The split1102design may allow two or more separate portions of the seal assembly to be constructed and put together easily around the conveyance110. The split assembly may enable the operator to quickly remove the seal assembly and the downhole tools122from the conveyance110.

Regarding design of the packing element and brass bushings, a split-packer or a solid, non-split packer may be used for this application. The solid packer allows for ease of manufacturing (and potentially less cost), but may result in the BHA connector having to be disconnected from the tool string each time the consumables are removed. This split design may be used throughout the seal assembly200(or the consumable package) to allow for ease of installation around the coil tubing and/or the conveyance110. Once the split halves are situated around the coil tubing, they may be fastened together prior to deploying. The split design may also allow for ease in the retrieval process.

Once downhole operations are complete, the conveyance110and the seal assembly200may be removed from the stripper102. In removing the seal assembly200(or the consumables), the conveyance110with the downhole tools122(or tool string) may be brought up to the lower of the actuators202(or the actuators/subassembly). Actuators202and/or the pistons414/422may then be opened and the seal assembly200(or the components) may rest on a BHA connector1104as shown inFIG. 11A. The seal assembly200, having brass and packer elements, may then be brought to the surface once the job is complete or for redressing.

Once the job is complete the seal assembly200(or the consumable package) may be returned to surface. The conveyance110with the downhole tools122(or the tool string) ascends through the BOP114and tags off on the bottom of the retrievable stripper102. The packer actuators408(or the upper and lower pistons) may be actuated to the open position as are the locator actuators410; there is no protocol necessary regarding the sequence for opening these. Once the upper, lower pistons and actuators are in the open position, the seal assembly200(or the consumable assembly) comes to rest on the BHA. At this time, it may continue its ascent through the stripper102with the consumables on the tool string.

FIGS. 12A-12Cshow a sequence of removing the conveyance110and the seal assembly200from the stripper102. The conveyance110with the one or more downhole tools122may be run up-hole until the downhole tools122and/or the end of the conveyance110are past the BOP114and/or the stop206. The downhole tools122may then engage the lowermost of the one or more packer actuators408. A decrease in the tension, or force in the conveyance110may indicate that the downhole tools122have reached the proper position above the stop206and/or the BOP114. The stop206and/or the BOP114may then be closed in order to prevent fluid flow from the wellbore112(as shown inFIG. 1) to the stripper102. The actuators202, for example the packer actuators408and the locator actuators410, of the stripper102may then be opened, thereby releasing the seal assembly200from the stripper102as shown inFIG. 12B. With the actuators202in the open position, the conveyance110may be moved out of the stripper102. As the conveyance110leaves the stripper102, the downhole tools122, or the end of the conveyance110may engage the seal assembly200thereby removing the seal assembly200from the stripper102as shown inFIG. 12C. The seal assembly200may then be removed from the conveyance110and a new seal assembly200may be placed on the conveyance110for further use. Further, a different type of conveyance110, for example a wireline may be deployed into the stripper102. The wireline conveyance may have the same type of seal assembly200deployed with it. In such cases, a smaller inner diameter may be used.

FIG. 13is a flowchart depicting a method for replacing equipment at a wellsite. The method connects1300a seal assembly to a conveyance for delivering a BHA. The seal assembly may have at least one packer extendable within the subsea stripper to form a seal thereabout, at least one locator for positioning the seal assembly in an install position within the subsea stripper, and a frangible member for connecting the seal assembly to the conveyance prior to deployment in the subsea stripper. The method continues by deploying1302the conveyance into the subsea stripper and passing1304the seal assembly past at least one actuator within the subsea stripper. The method continues by actuating1306the at least one actuator and moving1308the seal assembly toward the at least one actuated actuator with the conveyance and thereby engaging1310the seal assembly with the at least one actuator. The method continues by actuating1312the seal assembly into sealing engagement with the conveyance. The method continues by locating1311the seal assembly in an install position with a locator actuator and deploying1314the conveyance into the subsea wellbore while sealing the conveyance in the stripper using the seal assembly.

To automate the replacement of the one or more seal assemblies200, the equipment replacement system104may be in communication with the controller(s)130/132. The equipment replacement system104may communicate with the controllers130and/or132via one or more communication links133, as shown inFIG. 1. The communication links133may be any suitable communication means such as hydraulic lines, pneumatic lines, wiring, fiber optics, telemetry, acoustic device, wireless communication, any combination thereof, and the like. Further, any of the devices and/or systems in the subsea system106may communicate with the subsea controller132and/or the controller130via the communication links133. Further still, the subsea controller132may communicate with the controller130via the communication links133.

It will be appreciated by those skilled in the art that the techniques disclosed herein can be implemented for automated/autonomous applications via software configured with algorithms to perform the desired functions. These aspects can be implemented by programming one or more suitable general-purpose computers having appropriate hardware. The programming may be accomplished through the use of one or more program storage devices readable by the processor(s) and encoding one or more programs of instructions executable by the computer for performing the operations described herein. The program storage device may take the form of, e.g., one or more floppy disks; a CD ROM or other optical disk; a read-only memory chip (ROM); and other forms of the kind well known in the art or subsequently developed. The program of instructions may be “object code,” i.e., in binary form that is executable more-or-less directly by the computer; in “source code” that requires compilation or interpretation before execution; or in some intermediate form such as partially compiled code. The precise forms of the program storage device and of the encoding of instructions are immaterial here. Aspects of the invention may also be configured to perform the described functions (via appropriate hardware/software) solely on site and/or remotely controlled via an extended communication (e.g., wireless, internet, satellite, etc.) network.

While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.