US20150337624A1

US20150337624A1 - Stage tool for wellbore cementing

Info

Publication number: US20150337624A1
Application number: US14/759,394
Authority: US
Inventors: Daniel Jon Themig; Robert Joe Coon
Original assignee: Packers Plus Energy Services Inc
Current assignee: Packers Plus Energy Services Inc
Priority date: 2013-01-08
Filing date: 2014-01-08
Publication date: 2015-11-26
Also published as: CA2897229A1; WO2014107805A1

Abstract

A stage tool for cementing a wellbore annulus, comprising: a main body including a tubular wall with an outer surface and an inner bore extending from a top end to a bottom end; a cementing port through the tubular wall providing fluidic access between the longitudinal bore and the outer surface; a valve for controlling flow through the cementing port between the outer surface and the inner bore; and a plug sealing a circulation path between the valve and the outer surface, the plug being expellable by pressure applied from the inner bore. The stage tool may be run in with the plug isolating annular pressure from the valve. After sufficient cement has been introduced to the annulus, the stage tool fluid port can be closed to hold the cement in the annulus.

Description

FIELD

The invention relates to a tool for wellbore operations and, in particular, a tool for wellbore cementing.

BACKGROUND

In wellbore operations, cementing may be used to control migration of fluids outside a liner installed in the wellbore. For example, cement may be installed in the annulus between the liner and the formation wall to deter migration of the fluids axially along the annulus.
Often cement is introduced by flowing cement down through the wellbore liner to its distal end and forcing it around the bottom and up into the annulus where it is allowed to set. Sometimes it is desirable to introduce cement into the annulus without pumping it around the bottom end of the liner. A stage tool may be used for this purpose. A stage tool is a tubular that can be installed along the length of the liner and includes a tubular wall defining an inner tubular surface and an outer tubular surface and a port between the inner tubular surface and the outer tubular surface through which fluid can be passed to cement the annulus along a length of the liner.

SUMMARY

In accordance with a broad aspect, there is provided a method for cementing a tubing string in a wellbore, the method comprising: positioning the tubing string with a stage tool in the wellbore, an annulus being defined between the stage tool and the wellbore wall; expelling a plug from over a cementing port of the stage tool by pressuring up an inner bore of the stage tool; pumping cement into the annulus; and closing the cementing port to hold the cement in the annulus to provide time for the cement to set.
In accordance with a broad aspect of the present invention, there is provided a stage tool comprising: a main body including a tubular wall with an outer surface and an inner bore extending from a top end to a bottom end; a cementing port through the tubular wall providing fluidic access between the inner bore and the outer surface; a valve for controlling flow through the cementing port between the outer surface and the inner bore; and a plug sealing a circulation path between the valve and the outer surface, the plug being expellable by pressure applied from the inner bore.
It is to be understood that other aspects of the present invention will become readily apparent to those skilled in the art from the following detailed description, wherein various embodiments of the invention are shown and described by way of illustration. As will be realized, the invention is capable for other and different embodiments and its several details are capable of modification in various other respects, all without departing from the spirit and scope of the present invention. Accordingly the drawings and detailed description are to be regarded as illustrative in nature and not as restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

Referring to the drawings, several aspects of the present invention are illustrated by way of example, and not by way of limitation, in detail in the figures, wherein:

FIG. 1 is a schematic sectional view through a wellbore with a tubing string installed therein;

FIGS. 2A to 2F are views of a stage tool according to one aspect of the present invention in sequential stages of operation, wherein FIG. 2A is an axial sectional view of a stage tool in a run in position, FIG. 2B is an axial sectional view of the stage tool of FIG. 2A in a position activated and ready to be opened for cement circulation through the annulus, FIG. 2C is an axial sectional view of the stage tool of FIG. 2A in an open position for circulation therethrough to permit cementing through the annulus, FIG. 2D is an axial sectional view of the stage tool of FIG. 2A in a position closed by a check valve after dissipation of circulation pressure, FIG. 2E is an axial sectional view of the stage tool of FIG. 2A in a closed and locked position preventing cement circulation and FIG. 2F is an axial sectional view of the stage tool of FIG. 2A in a closed position, with a back up sleeve closing against cement circulation.

FIGS. 3A to 3E are views of a stage tool according to one aspect of the present invention in sequential stages of operation, wherein FIG. 3A is an axial sectional view of a stage tool in a run in position, FIG. 3B is an axial sectional view of the stage tool of FIG. 3A in a position activated and ready for cement circulation through the annulus, FIG. 3C is an axial sectional view of the stage tool in a first stage of being closed, FIG. 3D is an axial sectional view of the stage tool in a second stage of being closed, and FIG. 3E is an axial sectional view of the stage tool of FIG. 3A in a closed position preventing cement circulation.

FIGS. 4A to 4D are view of a kobe useful in the stage tool of FIG. 3A, wherein FIG. 4A is a side elevation of the original kobe, FIG. 4B is an axial section, FIG. 4C is an isometric view of the original kobe and FIG. 4D is an isometric view of the kobe after use.

DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS

The description that follows and the embodiments described therein are provided by way of illustration of an example, or examples, of particular embodiments of the principles of various aspects of the present invention. These examples are provided for the purposes of explanation, and not of limitation, of those principles and of the invention in its various aspects. In the description, similar parts are marked throughout the specification and the drawings with the same respective reference numerals. The drawings are not necessarily to scale and in some instances proportions may have been exaggerated in order more clearly to depict certain features.
In wellbore operations, as shown in the example of FIG. 1, generally a surface hole is drilled and surface casing 100 is installed and cemented in place to protect surface soil and ground water from wellbore operations and to prevent cave in. Thereafter, an extended wellbore 101 may be drilled below the surface casing point 100 a to reach a formation of interest 103. Sometimes further casing is installed below the surface casing. Where operations are to be conducted using a liner 104, the liner can extend from a point above the lower most casing point, in this case casing point 100 a with an active, lower portion of the liner extending out beyond casing point 100 a at the bottom of the cased section of the well.
According to the current invention, a tool, a process and an installation are described that permit a liner 104 to be supported in an extended wellbore 101 by stage cementing below any casing point 100 a, as shown, which may be of the surface casing or a lower section of casing. The liner, therefore, can be run in, set and cemented in a well including in an open hole, uncased section of the well. The liner 104 has an upper end, a lower end, a tubular wall defining an inner diameter and an outer surface and, installed along its length, a stage tool 110, which separates the string into an upper portion 104 b, above (uphole of) the stage tool, and a lower portion, below (downhole of) the stage tool. The stage tool can be positioned at various locations along the liner. In FIG. 1, stage tool 110 is positioned near the heel of the well, for example, just downhole of the heel. In that embodiment, the lower portion of the liner below the stage tool may contain active components 108 a, 108 b, etc. of the liner.
Cement C may be introduced into the annulus 150 to fill a portion of the annulus along a length of the liner to cement, and therefore seal off, that portion of the annulus between the liner and the open hole wall 101 a. The cement may be introduced to fill a selected portion of the annulus, for example, to create a column extending back from at least above the stage tool to the lowest cased section of the well. In one embodiment, the cement is introduced until it fills the annulus down to a point above the active components.
Active components on the liner may take various forms such as, for example, selected from one or more of packers, slips, stabilizers, centralizers, fluid treatment intervals (such as may include fluid treatment ports, nozzles, port closures, etc.), fluid production intervals (such as may include fluid inflow ports, screens, inflow control devices, etc.), etc. For example, in one embodiment active components may include slips 108 a, multistage fracturing components such as sleeve valves, hydraulic ports 108 b (i.e. fracing ports) and packers 108 c′, 108 c for zone isolation, a blow out plug 108 d, etc.
The liner may be run in and positioned in the well by any of various procedures. In one embodiment, during or after running in the liner a fluid may fill, be introduced to or circulated through the string. It may be useful to have pressure communication through the fluid through the string 104 including below stage tool 110, for example, for circulation or for pressure actuation of active components. Sometimes, it is desirable to float in the liner in which case a float valve may be useful that pressure isolates the string from the wellbore. If both circulation and float properties are of interest, a valve may be of interest.
Once in place, further operations may proceed to set the liner in the wellbore. The order of operations may depend on the desired result for the well and the features of the liner and the components carried by the liner. In one embodiment, such as that shown in FIG. 1A, the cementing operation is undertaken first and then the liner is finally installed by setting the packers. In an embodiment such as that shown in FIG. 1B, the liner may be secured first by various means including by slips 108 a and/or packers 108 c, 108 c′ in the well.
While the slips or packers may in some embodiments be set by pressuring up the string, the string may later be opened to achieve conductivity to the formation. In one embodiment, the liner is configured to hold pressure during the setting of the packers, but can be opened for fluid conductivity thereafter for fluid treatments to the formation. In one embodiment, for example, the liner may be run in with a valve that selectively holds pressure in the liner or a blow out plug, which before being expelled, holds pressure in the liner. Alternately, the liner may include a port opened by pressure cycling, such that once downhole, the liner can be pressured up and pressure released to open the liner. An example of such a pressure cycle valve is shown in applicants corresponding application WO 1009/132462, published Nov. 5, 1009.
In some frac operations, packers 108 c, 108 c′ are carried on the liner. The packers may be open hole packers or take other forms. The packers are set to create annular seals between the liner and the wellbore wall for zone isolation. In some frac operations, the packers intended for zone isolation during wellbore treatments are set in a substantially horizontal section of the well, downhole of the heel. In such systems it may be beneficial, as shown, to create a cement column from at least adjacent the uppermost packer 108 c′ to a point above the lower most casing point, for example to the top of the liner. This may isolate the annulus between the liner and the formation at the heel of the horizontal well and may provide stability to the hole. Of course, if stage tool 110 is positioned downhole of uppermost packer 108 c′ the annulus can be cemented to a point below the uppermost packer for example, down to the location of the stage tool, as desired.
Stage tool 110 includes one or more ports 122 and a valve to control flow through the ports from the annulus to the inner bore. The valve may be operated to open the ports to permit fluid flows with the cement to flow therethrough to achieve circulation to the string inner bore 104 b from annulus 150.
After the stage tool's circulation ports are opened, cement may be pumped by fluid circulation as provided through ports 122. In the illustrated embodiment, cement is pumped from above down through the annulus 150 toward the stage tool, in what is called a reverse cementing operation. In particular, since the circulation flow is down through the annulus and up through the liner, this is the reverse of a standard flow direction for circulation and the cement can be placed in the annulus without requiring it to be pumped through or even into the string. In one embodiment, a spacer is pumped first, followed by a cement slurry. After an appropriate amount of cement has been pumped to accommodate a selected portion of the annulus, for example extending down from a casing point 100 a to the stage tool, to the uppermost packer 108 c′ or having passed all the way to stage tool 110 and perhaps even through ports 122 into the liner, the circulation is stopped and the cement may be held in the annulus until it sets. While various means may be employed to maintain the cement in the annulus, generally the stage tool includes a closure that closes the ports. The stage tool and its components such as the valve may take various forms. For example, the stage tool may include a mechanical closure installed therein, such as a sleeve and/or a check valve that can be manipulated remotely or directly to seal off ports 122.
In one embodiment, therefore, a wellbore may be stage cemented by use of a stage tool with flow in a reverse direction. For example, a method for cementing a tubing string in a wellbore having a heel transitioning from a substantially vertical section to a substantially horizontal section, may include: introducing cement to the annulus to flow down to a selected depth, which may be at least the heel and/or possibly just above the uppermost packer on the string and/or all the way to the stage tool; allowing the cement to flow through the annulus by opening a stage tool to create a circulation path from the annulus into the tubing string; and holding the cement in the annulus to provide time for the cement to set. The amount of cement can be selected to substantially fill the selected portion of the annulus without injecting much or any cement into the inner bore. For example, the circulation path can be closed before the cement passes from the annulus into the tubing string.
In one embodiment, the method may include running into a wellbore with a string that includes at least one fracing port below the uppermost packer and after cementing, a fracturing fluid treatment is conducted through the string and out through the at least one fracing port to treat the formation accessed by the at least one fracing port.
In one embodiment, the method may include activating and/or opening ports 122 of the stage tool by pressuring up on the string. Pressuring up may include substantially the entire string or just a portion of the string (i.e. a portion above a seat). Pressuring up may be solely to activate or open the valve or may be used for other purposes in the string such as the setting of one or more packers. Pressuring up may drive a piston by creating a pressure differential across a piston.
In one embodiment, holding the cement in the annulus includes allowing a valve to close and to thereby seal the cement in the annulus. In one embodiment, closing the valve to seal the cement in the annulus includes dissipating a pressure differential where annular pressure had been higher than tubing pressure, which may include pressuring up on the inner diameter of the string or reducing annular pressure. In another embodiment, closing the valve to seal the cement in the annulus includes pressuring up on the inner diameter of the string.
The valve operates relative to a port through the tubing string wall. The valve may control fluid flow from the annulus through the port and upwardly through the inner diameter toward surface. Alternately or in addition, the valve may control fluid flow downwardly through the inner diameter and through the port toward the annulus.
The valve may include a lock that positively locks the valve in the closed position.
In one embodiment, the valve may include a backup closure that can be closed to seal the cement in the annulus.
Referring to FIGS. 2A to 2F, a stage tool 210 for use to stage cement a wellbore liner is shown. The stage tool may be installed in a tubular string. This stage tool includes a port, a one way check valve for the port, used, when activated, to open the port to fluid flow therethrough in response to reverse circulation and a releasable lock that holds the one-way check valve in an inoperable position until the valve is activated.
The stage tool further may include a final lock for locking the check valve in a closed position and/or a backup closing sleeve that closes the port to fluid flow after use of the check valve.
For example, the stage tool may include a tubing body installable in a string, a port through the wall of the tubing body and a one way check valve for the port, such as one including a spring loaded valve body in the form of a sleeve or a rod (for example, a poppet), used to open the port to fluid flow therethrough in response to reverse circulation (from the outer surface to the inner diameter). The stage tool may further include a releasable lock in the form of an expellable plug. The releasable lock initially releasably locks the check valve in the inactive position. The expellable plug is hydraulically actuatable to activate, and in this embodiment release, the check valve for operation. The stage tool may further include a final closing sleeve operable to provide a back up closure for the port.
Stage tool 210 may include a tubular body including a wall 211 with an outer surface 212, an inner bore 214 defined by an inner surface 216 of the wall, a first end 218 and a second end 220. A port 222 extends through the wall and is openable (FIG. 2C) and closable (FIGS. 2A, 2B, 2D to 2F) to open and close, respectively, the stage tool to circulation through the port.
Stage tool 210 may be intended for use in wellbore applications for actuation to permit cementing of a portion of the annulus behind a borehole liner along a length of the liner, generally spaced from the liner's distal end. The tubular body may be formed of materials useful in wellbore applications such as of pipe, liner, casing, etc. and may be incorporated as a portion of a tubing string or in another wellbore string. Bore 214 may be in communication with the inner bore of a tubing string such that pressures may be controlled therein and fluids may be communicated from surface, such as for wellbore treatment therethrough. The tubular body may be formed in various ways to be incorporated in a tubular string. For example, the tubular segment may be formed integral or connected by permanent means, such as welding, with another portion of the tubular string. Alternately, the ends 218, 220 of the tubular body may be formed for engagement in sequence with adjacent tubulars in a string. For example, the ends may be formed as threaded pins or boxes to allow threaded engagement with adjacent tubulars.
A valve body 224 is positioned to act as a closure for port 222 and is moveable relative to the port to manipulate it between the open and the closed positions. Valve body 224 may carry or ride over seals 223 that provide a pressure seal between valve body 224 and wall 211 to seal against migration of fluid through port 222 past the valve body.
Valve body 224 acts as a one way check valve. Valve body 224, when activated, is biased to a closed position, but may be moved by fluid pressure to open. Thus, port 222 can be opened and closed without the need to run in a manipulation string or line to open or close it. Valve body 224 is spring-loaded with a biasing spring 226 such that it is normally in a position closing port 222, but can be moved to open the port when the annular pressure P1 is greater than the tubing pressure P2 with a differential sufficient to overcome the bias in spring 226. Thus, valve body 224 may be opened by reverse flow from the annulus to the tubing string such that fluid can pass through port 222 inwardly from annulus 250 to inner bore 214, with valve body 224 acting as a one way check valve and resisting flow outwardly through the ports of the stage tool.
Valve body 224 may be secured adjacent the port to be positionable, when active, to sense the pressure differential P1 vs P2 with annular pressure on one side of seals and tubing pressure on the other side of seals. In the illustrated embodiment, check valve body 224 is also positionable such that this pressure differential is not sensed. In the illustrated embodiment, valve body 224 is installed in an external chamber 225 (sometimes also called a pocket) defined between wall 212 and wall 225 a. The chamber has an active space in the circulation path between port 222 and an open end 225 b wherein seals 223 on the valve body can reside. Wall 225 a also forms a closed end of the chamber which is positioned adjacent port 222 but diametrically opposite open end 225 b. The closed end doesn't have an opening to the exterior of the tool and defines an inactive area for the valve body. When the seals of the valve body are in this inactive area, the valve body is inactive as seals 223 are not exposed to a pressure differential. In the inactive position, valve body 224 can be held from moving in the pocket and may be held with seals 223 in the inactive area. When activated, the valve body can slide in the chamber as driven by spring 226 and, when seals 223 are in the active area, the valve body may be driven by pressure. The valve body is secured against removal from chamber 225 by stops 227 that reduce the space across the chamber to a dimension through which valve body 223 cannot pass.
There may be an equalization port 228 through wall 211 into chamber 225 in the inactive area to avoid the formation of a pressure lock behind the valve body.
While chamber 225 is shown here as a cylindrical side pocket, it is to be understood that it could be annularly formed extending fully or partly around wall 211 and in which case the valve body may be a sleeve.
The check valve may include a lock to positively lock valve body 224 in a port closed position with seals in active position. For example in the illustrated embodiment, the lock may include a lock ring 229 a formed to catch on a ridge (sometimes called an upset) 229 b. While here valve body 224 carries lock ring 229 a, it may be installed on either the valve body or the chamber. While lock ring 229 a is normally biased outwardly to catch on and limit movement past ridge 229 b, lock ring 229 a is collapsible if sufficient force is applied to move past the ridge. The surface of ridge 229 b may be ramped, gradually increasing in height, such that it is easier to ride thereover (i.e. side 229 b′) or the surface may have an abrupt height change to create a stop wall over which lock ring 229 b cannot readily pass. In this embodiment, the locking side 229 b″ of the ridge is abruptly angled to prevent lock ring 229 a from returning over the ridge once it has passed into the locked position.
Spring 228 has insufficient force to drive the valve body into the locked position relative to ridge 229 b. However, valve body 224 may be driven from the activated position into the locked position by pressuring up on the inner bore. Pressuring on the inner bore renders P2 greater than P1. This differential is communicated to the valve body through port 222 and port 228 and is sensed across seals 223. This drives the valve body up until it is stopped by stops 227.
Valve body 224 is initially inactive, for example, during run in of the tool such that it is not affected by pressure differentials. However, the valving operation of valve body 224 may be activated when its operation is required. For example, valve body 224 may be releasably locked in an inactive position, but may be unlocked to act as a check valve when such operation is required. In this embodiment, the releasable lock for maintaining the inactive state of valve body 224 is provided by plug 230. The plug normally holds valve body 224 in an inactive position, but movement of the plug can release valve body 224 for check valve operation. Plug 230 for example, is secured by a shear pin 231 in a position holding valve 224 in an inactive position, where it cannot move and the seals are in the inactive area. However, plug 230 can be moved to free valve body 224 for movement. Plug 230 can be moved by overcoming the holding force of pin 231. In this embodiment, plug 230 is expellable from chamber 225 to activate valve body 224.
Plug 230 is positioned in chamber 225 and seals the circulation path from port 222 to open end 225 b and thus, when in place, isolates external pressure from the check valve. Plug 230 itself, however, can feel pressure differentials thereacross between annular pressure and tubing pressure and can act as a piston and be expelled through the open end when P2 is sufficiently greater than P1 to overcome pin 231.
Plug 230 also serves to close port 222 when valve body 224 is inactive. Plug 230 may include seals 226 to ensure that pressure differentials are sensed across the plug and to prevent fluid leakage between outer surface 212 and bore 214. The plug can be sized to catch against stop 227 to resist further movement of the plug, if P1 becomes greater than P2.
While plug 230 may be moveable by various means, hydraulic means permits the activation of valve body 224 entirely remotely, simply by pressuring up on the inner bore 214.
Once released from its inactive position, valve body 224 is responsive to fluid pressure differentials between P1 and P2 and only allows one way flow inwardly when P1>P2. The stage tool may include a final closing sleeve 246 to act as a back-up seal for port 222. Final closing sleeve 246 may be normally offset from port 222 but is moveable to cover the port. Sleeve 246 may be moveable in various ways, as by a remote system, such as hydraulics, electronics, motors, etc. or by engagement by a shifting tool.
Final closing sleeve 246 may include seals 258 to seal the interface between sleeve 246 and wall 216 to prevent leaks therebetween. A lock such as a body lock ring or ratchet may be employed between sleeve 246 and wall 211 to lock sleeve 246 against movement towards reopening.
Having thus described the components of the example stage tool 210, the operation of that stage tool will be described. Stage tool 210 may be manipulated between a plurality of positions. As shown by the drawings, the stage tool may be manipulated between a first, run in position (FIG. 2A), a second, cementing port openable position (FIGS. 2B to 2D) and a third, cementing port-closed position (FIG. 2E). The stage tool 210 may also be manipulated to a contingency closed position (FIG. 2F).
The stage tool may be run into and set in the hole in a condition as shown in FIG. 2A and may be manipulated as shown in FIG. 2B to an active condition shown in FIGS. 2C and 2D for stage cementing an annulus about the stage tool. Stage tool 210 allows cement to be introduced through the annulus and allows reverse circulation, arrows C, of annular fluids from the annulus into the tubing string though inner bore 214 and then back up toward surface. The stage tool acts to permit only flow inwardly to inner bore 214, when pressure P1 is sufficient to overcome the force of spring 226. When the pressure P1 is insufficient, spring 226 forces the valve into a closed position, to close off communication between the annulus and the inner bore of the tool and, thus, holding the cement in the annulus. After the introduction of cement to the annulus formed between the tool and the wellbore wall down to a selected level, the tool may be manipulated to a condition shown in FIG. 2E to positively lock stage tool in a closed position. For contingency, back up sleeve 246 may be moved to also close port 222 (FIG. 2F).
In summary, the stage tool may be installed in a tubing string and run into the wellbore with the port closed by a removable closure, in this embodiment plug 230, which also holds a check valve in an inactive state. Once in position, port 222 is rendered openable by hydraulic actuation, here by blowing out plug 230, to provide fluid communication between the annulus about the tool and inner bore 214. The stage tool can be located just above an uppermost packer on a treatment string, such that the annulus can be cemented between the upper end of the string and a point just above the uppermost packer. Cement is then introduced to annulus and can be pumped down the annulus as permitted by circulation through port 222 into inner bore 214. When sufficient cement is introduced to fill the annulus along a selected length, port 222 is closed to stop circulation from the annulus into bore 214. This, then, holds the cement in the annulus and time is allowed for the cement to set. The amount of cement introduced can be selected to substantially fill the selected portion of the annulus without injecting much or any cement into inner bore 214.
To elaborate, tool 210 may be installed in a tubular string with its inner bore 214 in communication with the inner diameter of the tubing string. The tool will be run into the wellbore with ports 222 closed. FIG. 2A shows the position of the components of stage tool 210 during run in. Once in position, valve body 224 can be activated to operate as a check valve by removing its releasable lock. This may be accomplished by pressuring up the tubing string. In one embodiment, the process to set the tubing string in the hole, as by setting of packers, slips, etc, is also by pressuring up and, as such, the operations to set the string in the well and to activate the valve body may occur at the same time. This may include dropping a ball that lands in a toe-end of the string to pressure up substantially the entire string. This may set one or more packers on the string in addition to triggering valve body 224 to the active position by removing plug 230 (FIG. 2B).
For example, inner bore 214 can be pressured up relative to the annulus about stage tool 210 to overcome the holding force of pin 231 and to blow plug 230 out of the chamber, as shown by arrow E. Removal of plug 230 renders port 222 openable and activates check valve body 224. Plug 230 is expelled outwardly by pump pressure, such that it is out of the way of cementing flows. Plug 230 may be released entirely from the stage tool into the annulus.
The plug 230, when in place in the stage tool, seals off a cement circulation path from annulus to port 322, but when removed, the cement circulation path is opened through open end 225 b, the active area of chamber and port 322 to inner bore 314.
After the stage tool is activated, cement can be pumped down the annulus 250 which creates a pressure P1>P2 sufficient to overcome the check valve and, in particular, to move valve body 224 against the bias of spring 226 to permit circulation, arrows C, through port 222 and into bore 214 toward surface.
Valve body 224 resists flow in an opposite direction relative to arrows C through port 222 due to the bias in spring 226. In this active position, closing movement of the valve body is stopped when lock ring 229 a hits ridge 229 b. Spring 226 cannot apply sufficient force to move lock ring 229 a over the ridge.
Once the annulus pressure P1 is reduced, FIG. 2D, such as when the cement job is interrupted or completed, the valve body 224 shuts. This prevents further flow through port 224, unless pressure is increased again in annulus 250. The bias in spring 226 can be sufficient to resist the opening of valve body 224 by the weight of the cement, absent pump pressure.
The amount of cement introduced can be selected to substantially fill a selected portion of the annulus at least uphole of the stage tool without injecting much or any cement through port 222 into inner bore 214. The method may include pumping leading fluids ahead of the cement, the fluids being pumped down the annulus to clean the annulus and/or open the check valve to flow through the port from the annulus to the inner diameter ahead of the cement. The fluids may include, for example, mud. In such an embodiment, the circulation through port allowing the cementing of the annulus can be accomplished by the leading fluids and circulation may be stopped before the cement begins to pass through port 222.
If desired, after the cementing job is done, valve body 224 can be locked in a closed position. To do so, the tubing string can be pressured up to cause P2 to exceed P1. The seals, being positioned in the active area between port 222 and open end 225 b of the pocket, feel the pressure differential P2>P1 and drive the valve body toward open end 225 b. The pressure differential may be sufficient to move lock ring 229 a over ridge 229 b. Stop 227 prevents the valve body from being expelled from chamber. Due to the abrupt angle on surface 229″ and the outward bias of lock ring 229 a, it cannot be pushed back over ridge 229 b and is, thus, locked in a closed position relative to port 222 (FIG. 2E).
Also, if desired, final closing sleeve 246 can be moved over port 222 to prevent further flow through the port in either direction and to act as a back-up for sleeve 224. This may include engaging final closing sleeve 246 to move it to a cementing port-closed position (FIG. 2F).
After the cement is installed and set, wellbore operations may proceed. In the embodiment of FIG. 2, the tubing string inner bore is open and by selection of the inner diameter of sleeve 246 may be fully open to the drift diameter. In some embodiments, wellbore operations may include wellbore fluid treatments such as stimulation including fracturing. In such an embodiment, string manipulations may be necessary below the stage tool. For example, fluid treatment ports may be opened below the stage tool through which treatment fluids will be communicated, sometimes under pressure to the formation. In one embodiment, for example a fracing operation may be carried out on a formation accessed through the wellbore below the stage tool. Fracturing fluids under pressure may be introduced through the tubing string, passing through inner bore 214 of tool 210, and injecting the fluids under pressure out from the tubing string through fracing ports downhole of the stage tool. In some instances, string manipulation may include pressuring up the string inner bore including bore 214 of the stage tool. In some instances, tools, free or connected to strings, must be passed through the string inner bore including bore 214 of the stage tool.
Another stage tool 310 is shown in FIGS. 3A to 3E. That stage tool 310 also contains a pump out plug 320 to control activation of the stage tool's cementing port 322. However, in this embodiment, once plug 320 is pumped out, the cementing port is entirely open to flows in either direction. While there is no check valve illustrated in this embodiment, one could be employed if desired. Stage tool 310 however, does have a closure that can be set to close the port when desired. As with the stage tool of FIG. 2A, this stage tool 310 also can be closed by hydraulics without launching a plug into the string.
For example, the stage tool 310 has a cementing port closure operable through electronics. The side pocket cementer may be installed in a stage tool anywhere along the string.
The tool allows run in with the cementing port closed, cementing of the annulus of a well by opening the cementing port 322 and closing the port with a pressure signal. The port has a valve that controls the open and closed condition of the port.
The port is in the liner wall 311 and opens into a side pocket 325 on the wall. As will be appreciated, a side pocket can be annularly formed and accommodate a sleeve type valve, or a side pocket can be formed as a non-annular, roughly cylindrical form and accommodate a poppet type valve. The side pocket 325 forms therewithin a channel extending between port 322 and the exterior of the stage tool at an open end 325 a of the side pocket.
The port's valve is normally closed, for example during installation of the liner (FIG. 3A). The valve is then openable and then is recloseable. The valve includes a plug 320 held in the channel by a shear pin 331. The plug is in communication on one side with the tubing pressure and on the other with the annular pressure and can therefore be affected by a pressure differential set up between the tubing string and the annulus. An end 320 a of the plug 320 holds a valve body in the form of a piston 324 in place in the channel. Piston 324 is in communication on one side with tubing pressure and, on the other communicates with a chamber 352 at atmospheric pressure, which is normally always lower than both tubing and annular pressures.
As shown in FIG. 3B, applied tubing pressure P2 through port 322 shears the pin 331 pushing the plug 320 from pocket 325 through open end 325 a and out into the annulus. This provides a communication path through port 322 and the pocket from the tubing ID to the annulus open to outer surface 312 of the stage tool wall. Cement that is pumped down the tubing will exit the port and cement the annulus. Reverse cementing is also possible as the port 322 is fully open when plug 320 is removed.
Once plug 320 is removed, piston 324 is also activated, since it is no longer held in place by end 320 a.
Piston 324 is sized and intended as a closure for port 322. However, even though it is activated it cannot move to close the port until it is signaled to do so. In particular, the applied pressure that removed piston 320 and the subsequent flow of cement creates a hydrostatic pressure greater than that in the atmospheric chamber and that pressure differential holds piston 324 in place. In fact, piston 324 may be pushed against a spring 326. The spring may collapse to bias the piston against the pressure that is higher than atmospheric, but the pressure differential (hydrostatic pressure vs atmospheric pressure) holds the piston from advancing into channel 325 toward port 322.
The closing of port 322 by piston 324 is controlled by a controller 354. When it is time to close the port, a pressure signal is transmitted down the tubing and is communicated to controller 354, here through a port 355 (FIG. 3C). This signal could be a maximum pressure (greater than the pressure to shear pin 331) or a plurality of pressure pulses. A sensor in controller 354 senses this pressure signal and opens chamber 352 to tubing pressure such that the pressures are equalized across piston (FIG. 3D). The spring now has the power to push the piston over the port 322 closing the communication between the tubing and the annulus. The force in spring 326 may then act on piston 324 and bias it into a plugging position in channel 325 over the port (FIG. 3B). This closes the port against further flow.
Controller can take various forms. In the illustrated embodiment, controller 354 includes a circuit board and a battery and a releasable plug in the form of a meltable kobe 356. When the sensor senses the signal, it communicates with the circuit board and the circuit board in turn activates the batteries that heat a wire 358 configured to melt the kobe material and open the kobe end 356′ to expose a channel 356″ to conduct fluid pressure P2 to chamber 352. In this embodiment, the meltable material is plastic and the wire is wrapped around the plastic kobe 356. This burns the end of the plastic kobe and allows tubing pressure behind the piston 324, equalizing the pressure in the atmospheric chamber 352 and, as noted above, allows piston 324 to be moved, arrow M, by spring 326 to close the port (FIG. 3E).
The described valve works with either forward or reverse flows, provided there is an initial forward flow to remove piston 320.
One meltable plastic of interest is polyphenylene sulfide (available as Ryton™), but other plastics are useful as well. A meltable kobe 456 is shown in FIGS. 4A to 4D. The kobe includes an inner bore 460 defined by side walls. There is an opening to the bore at a base end 462. The bore is closed by a closed end 464. The kobe is installed by its base end 462 in a mount such that a fluid can enter bore 460. The kobe remains closed as long as side walls and end 464 remain intact. However, the kobe can be opened to permit fluid flow through bore 460 by creating an opening in the side walls or end 464.
As clearly shown in FIG. 4B, a wire 458 is wrapped around side walls in an area through which bore 460 extends. When required, wire 458 operates as a thermal knife relative to the material of the kobe's side walls. The wire may be of nichrome or other electrical resistance wire. The wire may be applied externally, as shown, in multiple wraps or a U-shaped wrap or the wire may be embedded. In operation, electricity is supplied to the wire which heats it to a temperature suitable to soften and degrade the plastic to break open the closed end 464. The internal pressure within bore 460 assists the opening of closed end 464, as the pressure may move the melted plastic away. Finally the plastic of the closed end yields and a leak path is formed to release the internal pressure from bore 460 to the chamber.
While the above-noted embodiment, employs a tubing pressure fluctuation signal sensed by a pressure sensor and a meltable Robe, it will be appreciated that other embodiments could be employed wherein the kobe is destroyed by other means such as acid. In such an embodiment, for example, an amount of acid is conveyed with the circulating flow to signal the closing of the port.
The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. No claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase “means for” or “step for”.

Claims

1. A method for cementing a tubing string in a wellbore, the method comprising: positioning the tubing string with a stage tool in the wellbore, an annulus being defined between the stage tool and the wellbore wall; expelling a plug from over a cementing port of the stage tool by pressuring up an inner bore of the stage tool; pumping cement into the annulus; and closing the cementing port to hold the cement in the annulus to provide time for the cement to set.

2. The method of claim 1 wherein expelling drives the plug into the annulus.

3. The method of claim 1 wherein during cementing, a check valve permits only one way flow through the cementing port.

4. The method of claim 1 wherein expelling includes exposing a check valve for the cementing port to annular pressure.

5. The method of claim 1 wherein closing includes pressuring up on the inner bore.

6. The method of claim 1 wherein closing includes locking a check valve into a closed and locked position.

7. The method of claim 1 wherein closing includes signaling to open an atmospheric chamber to tubing pressure to drive a closure to close the cementing port.

8. A stage tool comprising: a main body including a tubular wall with an outer surface and an inner bore extending from a top end to a bottom end; a cementing port through the tubular wall providing fluidic access between the inner bore and the outer surface; a valve for controlling flow through the cementing port between the outer surface and the inner bore; and a plug sealing a circulation path between the valve and the outer surface, the plug being expellable by pressure applied from the inner bore.

9. The stage tool of claim 8 wherein the plug and the valve are open to the inner bore and the valve is normally inactive and is activated by removing the plug.

10. The stage tool of claim 8 wherein the plug is shear pinned to hold the valve in an inactive position retracted from the cementing port.

11. The stage tool of claim 8 wherein the valve is a check valve.

12. The stage tool of claim 11 the check valve permits one way flow through the cementing port in a direction from the outer surface to the inner bore, the check valve being normally inactive and only acting on fluid flows through the fluid port when activated.

13. The stage tool of claim 8 further comprising a lock for locking the valve in a closed and locked position.

14. The stage tool of claim 13 wherein the valve is responsive to pressuring up the inner bore to be driven to the closed and locked position.

15. The stage tool of claim 8 wherein the circulation path is defined through a chamber between the cementing port and the outer surface and the plug is shear pinned in the chamber between the cementing port and the outer surface and holds the valve in an inactive position retracted from the cementing port and positioned out of the circulation path.

16. The stage tool of claim 15 wherein the valve is a check valve permitting one way flow through the cementing port in a direction from the outer surface to the inner bore, the check valve being activated by removal of the plug such that it moves into an active position in the circulation path.

17. The stage tool of claim 16 further comprising a lock for locking the check valve in a closed and locked position, the lock being operable by pressuring up the inner bore to drive the check valve from the active position in the circulation path to the closed and locked position.

18. The stage tool of claim 8 further comprising an atmospheric chamber to hold the valve in an open position relative to the cementing port and a controller to open the atmospheric chamber to the inner bore to close the valve.