CA2926062A1 - Stage tool, wellbore installation and method - Google Patents

Abstract

A method for stage cementing a wellbore includes opening a stage tool while a tubing pressure within the stage tool is approximately equal to annular pressure;
and pumping cement through the stage tool into an annulus about the stage tool.
A wellbore installation includes: a bore hole in a fragile formation; a tubing string in the bore hole, the tubing string including a lower end, an upper end and a tubular wall with an inner bore defined within the tubular wall and an outer surface and an annular space defined between the tubing string and the bore hole;
and a stage tool installed in the tubing string, the stage tool having a cementing port and the stage tool configured to open the cementing port when pressures are substantially equalized between the tubing string inner bore and the annular space.

Description

STAGE TOOL, WELLBORE INSTALLATION AND METHOD
FIELD
The invention relates to wellbore operations and, in particular, a stage tool, a wellbore installation and a method 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 wellbore 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 then forcing the cement around the bottom and up into the annulus where it is allowed to set.
Occasionally, 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 an inner bore defined by an inner tubular surface, an outer tubular surface, 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 and a closure for the port which is openable and closeable to control the flow of cement through the port.

WSLEGAL\045023\00417\11731577v3 Often the closure is opened by elevated fluid pressure. However, some formations cannot accommodate high pressures, as they damage the formation as by fracturing.
SUMMARY
In accordance with another broad aspect of the present invention, there is provided a method for stage cementing a wellbore, the method comprising: increasing pressure within a tubing string within the wellbore to conduct an operation in the tubing string, the tubing string including a stage tool with an inner diameter in pressure communication with the tubing string; reducing pressure in the stage tool inner diameter;
opening the stage tool when the pressure in the stage tool inner diameter is approximately equal to annular pressure in an annulus about the stage tool; and pumping cement through the stage tool into the annulus.
In accordance with another broad aspect of the present invention, there is provided a wellbore installation comprising: a bore hole in a formation; a tubing string in the bore hole, the tubing string including a lower end, an upper end and a tubular wall between the lower and the upper end, with an inner bore defined within the tubular wall and an annular space defined between the tubing string and a wall of the bore hole;
and a stage tool installed in the tubing string, the stage tool having a cementing port and the cementing port configured to open when the pressure in the inner bore is increased and then decreased until the pressure in the inner bore is substantially equal with the pressure of the annular space.
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.

2 WSLEGAL\045023\00417\11731577v3 BRIEF DESCRIPTION OF THE DRAWINGS
Several aspects of the present invention are illustrated by way of example, and not by way of limitation, in detail in the drawings.
The drawings include:
Figures 1A, 1B and 1C are sequential schematic sectional views through a wellbore with a wellbore installation therein, where Figure lA shows a stage tool being activated, Figure 1B shows a stage tool in a delayed mode where the stage tool ports have not yet been opened, but pressure is being equalized between the string and the annulus, and Figure 1C shows cement being pumped through the stage tool into the annulus.
Figures 2A, 2B and 2C are axial sectional views of a sleeve valve for a stage tool in first, second and final positions, respectively, according to one aspect of the present invention.
Figures 3A, 3B and 3C are a series of sectional views along one embodiment of a stage tool.
Figures 3D and 3E are enlarged views of the stage tool of Figure 3A.
Figures 3F and 3G are enlarged views of another activation mechanism for a stage tool.
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.

3 WSLEGAL\045023\00417\11731577v3 A cementing stage tool has been invented that opens when tubing pressure is approximately the same as annular pressure. Thus, the stage tool has a port that opens only when a pressure differential is dissipated between the stage tool inner diameter and its outer surface, which is open to the annulus about the tool and thereby to the formation.
Because substantially no opening or cementing pressure surge is applied to the formation, the stage tool is particularly useful for cementing in weak or unstable formations. This is primarily directed, at the current time, for shallow wells, and in particular for thermal applications such as those in oil sands formations such as Canadian oil sands formations, which are generally unconsolidated produced through in-situ, thermal, such as steam-assisted, operations.
There may be a requirement for stage cementing and for converting these thermal wells to a monobore. In a monobore scenario, the diameter of the production conduit is substantially uniform from the reservoir to surface. The simplest form of monobore is a string of tubing cemented in place that eliminates the need for one of the casing strings or liners when compared with a conventional wellbore design. In the formation of the monobore, a surface borehole is drilled and set with surface casing. Then a wellbore extension, such as a lateral, is drilled from the surface borehole in one drilling procedure, a monobore system is run and then a stage cementing operation is conducted.
The monobore is run through the heel, where the borehole orientation transitions from the surface substantially vertical hole to the lateral, substantially horizontal hole.
In such a procedure, stage cementing according to the invention can be carried out without providing a surge on the formation to avoid formation damage such as break down fracturing. Thus, although tubing pressure may be elevated significantly over annular pressure during initial operations: to pressure test and/or to actuate pressure responsive mechanisms, such as, for example, to set packers, to actuate stage tools or other tools, etc., that elevated pressure is not communicated to the annulus.
In such an embodiment, a stage tool may be employed that only opens to permit communication from the tubing string inner diameter to the folination once tubing pressure is reduced to be less than that which would damage the formation, such as a pressure that is about the same as or less than the annular pressure.

4 WSLEGAL\045023 \ 00417 \11731577v3 In one embodiment the stage tool may include a delay mechanism configured to permit opening of the stage tool ports only after a selected period of time lapses.
The stage tool ports open only that selected period of time after an activation of the delay mechanism.
The delay mechanism therefore delays opening the stage tool ports until a selected amount of time has lapsed after activation of the port opening process.
Activating the tool perntits the stage tool ports to be opened but does not open the ports, the opening of the ports being delayed by the delay mechanism.
The stage tool may include a signal receiver in addition to the delay mechanism. The signal receiver is configured to receive an activation signal indicating that it is an appropriate time to start the port opening process and the delay mechanism is configured to delay opening the stage tool ports until a selected amount of time after activation. The amount of time may be selected, for example, to be a time sufficient for all pressured up operations to be accomplished. Thus, while pressured up operations are conducted, the stage tool remains closed, but thereafter the stage tool ports are opened.
The delay mechanism can be a timer, a resistive force, a pressure sensor, etc.
The stage tool ports can open electrically, mechanically (such as by a driving spring) or hydraulically (such as by using a pressure chamber such as an atmospheric chamber).
The delay mechanism can be activated at surface before being the tubing string in which the stage tool is installed is run in into the well. The activated delay mechanism, such as for example, may include a timer that is started before installation of the stage tool and tubing string. The delay mechanism, for example the timer, then delays the stage tool port-opening for a period of time sufficient to run in the string and the stage tool and to conduct string setting operations. Alternately, the delay mechanism may be activated when the stage tool is already in place in the wellbore, for example, using a signal receiver for the delay mechanism.
A signal receiver may be configured to receive a mechanical, a sonic, an electrical or a hydraulic, etc. activation signal. The signal receiver can be configured to accept a signal from (i) a mechanical contact, such as from contact by a conveyed activating tool such as WSLEGAL\045023\00417\11731577v3 a dart or ball, (ii) sonically, (iii) electrically or (iv) hydraulically. For example, in a hydraulic system, the signal may be communicated to the stage tool by pressuring up the tubing string inner diameter and thereby the inner diameter of the stage tool, which through a pressure differential between the inner diameter pressure and another piston face, such as that within a pressure chamber, differential piston faces or that exposed to annular pressure.
Regardless of the mode of activation, the stage tool is configured to only open its ports when tubing pressure within the stage tool is reduced over the pressured up level of the tubing string. The tubing pressure is reduced to be substantially pressure balanced with annular pressure. The reduction of tubing pressure may be actively by reverse pumping or bleeding off pressure at surface.
In a hydraulic system, for example shown in Figures 1 A to 1C, the activating signal may be communicated through the string 8 to the stage tool 10 by pressuring up the tubing string, which is increasing tubing pressure in the string to a pressure P1 that is greater than annular pressure Pa (Figure 1A). Communicating the activating signal by pressuring up may involve pumping an activating tool through the string to the stage tool.
Alternately, without a separate activating tool, pressuring up may hydraulically activate the stage tool to be ready to open. While the activating signal activates the stage tool, closure 10a remains over cementing ports 10b of the stage tool. After being activated, the opening of the stage tool ports 10b is delayed (Figure 1B) until the tubing string and the annulus are substantially pressure balanced, wherein tubing pressure is reduced to P2 which is substantially the same as Pa. To achieve a substantial pressure balance between the inner bore and the annulus, the tubing pressure is reduced. For example, the tubing pressure may be released and time may be permitted to allow the tubing pressure to dissipate from P1 to P2.
When P2 is substantially equal to Pa, the stage tool ports 10b open and cement, arrows C, can be circulated from the inner bore of the stage tool, through ports 10b and into the annulus (Figure 1C). The stage tool may be positioned adjacent to the heel of the well, WSLEGAL\045023\00417\11731577v3 uphole of a packer such that the cement is placed in the annulus and the cement extends from the stage tool, as introduced through the cementing ports, upwardly toward surface.
Achieving a substantial pressure balance before allowing the stage tool ports to open avoids putting a surge on the formation. Considering the fragility of the formation, cement circulation may be gentle, for example at low pump pressures, circulated from the inner bore of the stage tool, through ports 10b and into the annulus (Figure 1C). The cementing ports may be open just prior to cement flow therethrough. For example, to avoid the generation of a surge due to pressure differentials, the cementing port may be open for the cement to pass therethrough. As such, the use of operable check valves at the cementing ports during cementing may be avoided.
One embodiment of a useful stage tool is shown in Figures 2A to 2C, wherein the activating signal is hydraulic and acts against a piston face on the stage tool and the delay mechanism is a form of pressure sensor that only allows the stage tool ports to be opened when the pressure inside the stage tool is about equal with the pressure outside the stage tool. A stage tool 10 with a hydraulically actuable sleeve valve is shown.
Stage tool 10 may include a tubular segment 12, a sleeve 14 supported by the tubular segment and a driver, shown generally at reference number 16, to drive the sleeve to move.
Stage tool 10 is configured to have durability suitable for use in wellbore tool applications, such as wellbore stage cementing. Tubular segment 12 may be a wellbore tubular such as of pipe, liner casing, etc. and may be a portion of a tubing string. Tubular segment 12 may include a bore 12a in communication with the inner bore of a tubing string such that pressures may be controlled therein and fluids may be communicated from surface therethrough, such as for actuation of the tool and conveying cement.
Tubular segment 12 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 various means, such as threading, welding etc., with another portion of the tubular string.
For example, ends 12b, 12c of the tubular segment, shown here as blanks, may be formed for engagement in sequence with adjacent tubulars in a string. For example, ends 12b, 12c WSLEGAL\045023\00417\11731577v3 may be formed as threaded pins or boxes to allow threaded engagement with adjacent tubulars.
Sleeve 14 may be installed to act as a piston in the tubular segment, in other words to be axially moveable relative to the tubular segment at least some movement of which is driven by fluid pressure. Sleeve 14 may be axially moveable through a plurality of positions. For example, as presently illustrated, sleeve 14 may be moveable through a first position (Figure 2A), a second position (Figure 2B) and a final or third position (Figure 2C). The installation site for the sleeve in the tubular segment is formed to allow for such movement.
Sleeve 14 may include a first piston face 18 in communication, for example through ports 19, with the inner bore 12a of the tubular segment such that first piston face 18 is open to tubing pressure. Sleeve 14 may further include a second piston face 20 in communication with the outer surface 12d of the tubular segment. For example, one or more ports 22 may be formed from outer surface 12d of the tubular segment such that second piston face 20 is open to annulus, hydrostatic pressure about the tubular segment.
First piston face 18 and second piston face 20 are positioned to act oppositely on the sleeve and act as the signal receiver to receive a hydraulic signal to activate the stage tool to open. Since the first piston face is open to tubing pressure and the second piston face is open to annulus pressure, a pressure differential can be set up between the first piston face and the second piston face to move the sleeve by offsetting or adjusting one or the other of the tubing pressure or annulus pressure. In particular, although hydrostatic pressure may generally be equalized between the tubing inner bore and the annulus, by increasing tubing pressure, as by increasing pressure in bore 12a from surface, pressure acting against first piston face 18 may be greater than the pressure acting against second piston face 20, which may cause sleeve 14 to move toward the low pressure side, which is the side open to face 20, into a selected second position (Figure 2B).
Seals 18a, such as o-rings, may be provided to act against leakage of fluid from the bore to the annulus about the tubular segment such that fluid from inner bore 12a is communicated only to face 18 and not to face 20.

WSLEGAL\045023\00417\11731577v3 One or more releasable setting devices 24 may be provided to releasably hold the sleeve in the first position. Releasable setting devices 24, such as one or more of a shear pin (a plurality of shear pins are shown), a collet, a c-ring, etc. provide that the sleeve may be held in place against inadvertent movement out of any selected position, but may be released to move only when it is desirable to do so. In the illustrated embodiment, releasable setting devices 24 may be installed to maintain the sleeve in its first position but can be released, as shown sheared in Figures 2B and 2C, by differential pressure between faces 18 and 20 to allow movement of the sleeve. Selection of a releasable setting device, such as shear pins to be overcome by a pressure differential is well understood in the art. In the present embodiment, the differential pressure required to shear out the sleeve is affected by the hydrostatic pressure and the rating and number of shear pins.
Driver 16 may be provided to move the sleeve into the final position. The driver may be selected to be unable to move the sleeve until releasable setting device 24 is released.
Since driver 16 is unable to overcome the holding power of releasable setting devices 24, the driver can only move the sleeve once the releasable setting devices are released.
Since driver 16 cannot overcome the holding pressure of releasable setting devices 24 but the differential pressure can overcome the holding force of devices 24, it will be appreciated then that driver 16 may apply a driving force less than the force exerted by the differential pressure such that driver 16 may also be unable to overcome or act against a differential pressure sufficient to overcome devices 24. Driver 16 may take various forms. For example, in one embodiment, driver 16 may include a spring and/or a gas pressure chamber such as an atmospheric chamber 26 to apply a push or pull force to the sleeve or to simply allow the sleeve to move in response to an applied force such as an inherent or applied pressure differential or gravity. In the illustrated embodiment of Figures 1, driver 16 employs hydrostatic pressure through piston face 20 that acts against trapped gas chamber 26 defined between tubular segment 12 and sleeve 14.
Chamber 26 is sealed by seals 18a, 28a, such as o-rings, such that any gas therein is trapped. Chamber 26 includes gas trapped at atmospheric or some other low pressure. Generally, chamber 26 includes air at surface atmospheric pressure, as may be present simply by assembly of W5LEGAL\045023\00417\11731577v3 the parts at surface. In any event, generally the pressure in chamber 26 is somewhat less than the hydrostatic pressure downhole. As such, when sleeve 14 is free to move, a pressure imbalance occurs across the sleeve at piston face 20 causing the sleeve to move toward the low pressure side, as provided by chamber 26, if no greater forces are acting against such movement.
In the illustrated embodiment, sleeve 14 moves axially in a first direction when moving from the first position to the second position and reverses to move axially in a direction opposite to the first direction when it moves from the second position to the third position. In the illustrated embodiment, sleeve 14 passes through the first position on its way to the third position. The illustrated sleeve configuration and sequence of movement allows the sleeve to continue to hold pressure in the first position and the second position.
When driven by tubing pressure to move from the first position into the second position, the sleeve moves from one overlapping, sealing position over port 28 into a further overlapping, port closed position and not towards opening of the port. As such, as long as tubing pressure is held or increased, the sleeve will remain in a port closed position and the tubing string in which the valve is positioned will be capable of holding pressure.
The second position may be considered a closed but activated or passive position, wherein the sleeve has been acted upon, but the valve remains closed. In the presently illustrated embodiment, the pressure differential between faces 18 and 20 caused by pressuring up in bore 12c does not move the sleeve into or even toward a port open position. Pressuring up the tubing string only releases the sleeve for later opening. Only when tubing pressure is dissipated to reduce or remove the pressure differential, can sleeve 14 move into the third, port open position.
While the above-described sleeve movement may provide certain benefits, of course other directions, traveling distances and sequences of movement may be employed depending on the configuration of the sleeve, piston chambers, releasable setting devices, driver, etc. In the illustrated embodiment, the first direction, when moving from the first position to the second position, may be towards surface and the reverse direction may be downhole.
WSLEGAL\045023\00417\11731577v3 Sleeve 14 may be installed in various ways on or in the tubular segment and may take various forms, while being axially moveable along a length of the tubular segment. For example, as illustrated, sleeve 14 may be installed in an annular opening 27 defined between an inner wall 29a and an outer wall 29b of the tubular segment. In the illustrated embodiment, piston face 18 is positioned at an end of the sleeve in annular opening 27, with pressure communication through ports 19 passing through inner wall 29a.
Also in this illustrated embodiment, chamber 26 is defined between sleeve 14 and inner wall 29a.
Also shown in this embodiment but again variable as desired, an opposite end of sleeve 14 extends out from annular opening 27 to have a surface in direct communication with inner bore 12a. Sleeve 14 may include one or more stepped portions 31 to adjust its inner diameter and thickness. Stepped portions 31, if desired, may alternately be selected to provide for piston face sizing and force selection. In the illustrated embodiment, for example, stepped portion 31 provides another piston face on the sleeve in communication with inner bore 12a, and therefore tubing pressure, through ports 33. The piston face of portion 31 acts with face 20 to counteract forces generated at piston face 18.
In the illustrated embodiment, ports 33 also act to avoid a pressure lock condition at stepped portion 31. The face area provided by stepped portion 31 may be considered when calculating the total piston face area of the sleeve and the overall pressure effect thereon.
For example, faces 18, 20 and 31 must all be considered with respect to pressure differentials acting across the sleeve and the effect of applied or inherent pressure conditions, such as applied tubing pressure, hydrostatic pressure acting as driver 16.
Faces 18, 20 and 31 may all be considered to obtain a sleeve across which pressure differentials can be readily achieved.
In operation, sleeve 14 may be axially moved relative to tubular segment 12 between the three positions. For example, as shown in Figure 2A, the sleeve valve may initially be in the first position with releasable setting devices 24 holding the sleeve in that position. To move the sleeve to the second position shown in Figure 2B, pressure may be increased in bore 12a, which pressure is not communicated to the annulus, such that a pressure differential is created between face 18 and face 20 across the sleeve. This tends to force the sleeve toward the low pressure side, which is the side at face 20. Such force releases WSLEGAL\045023\00417\11731577v3 devices 24, for example shears the shear pins, such that sleeve 14 can move toward the end defining face 20 until it arrives at the second position (Figure 2B).
Thereafter, pressure in bore 12a can be allowed to relax such that the pressure differential is reduced or eliminated between faces 18 and 20. At this point, since the sleeve is free from the holding force of devices 24, once the pressure differential is sufficiently reduced, the force in driver 16 may be sufficient to move the sleeve into the third position (Figure 2C).
In the illustrated embodiment, for example, the hydrostatic pressure may act on face 20 and, relative to low pressure chamber 26, a pressure imbalance is established that may tend to drive sleeve 14 to the third, and in the illustrated embodiment of Figure 2C, final position.
As such, a pressure increase within the tubular segment causes a pressure differential that releases the sleeve and renders the sleeve into a condition such that it can be acted upon by a driving force to move the sleeve to a further position. Pressuring up is only required to release the sleeve and not to move the sleeve into a port open position. In fact, since any pressure differential where the tubing pressure is greater than the annular pressure holds the sleeve in a port-closed, pressure holding position, the sleeve can only be acted upon by the driving force once the tubing pressure generated differential is dissipated.
The sleeve may, therefore, be actuated by pressure cycling wherein a pressure increase within the tubular segment causes a pressure differential that releases the sleeve and renders the sleeve in a condition such that it can be acted upon by a driver, such as existing hydrostatic pressure, to move the sleeve to a further position.
The sleeve valve of the present invention may be useful in various applications where it is desired to move a sleeve through a plurality of positions, where it is desired to actuate a sleeve to open after increasing tubing pressure, where it is desired to open a port in a tubing string hydraulically but where the fluid pressure must be held in the tubing string for other purposes prior to opening the ports to equalize pressure. In the illustrated embodiment, for example, sleeve 14 in both the first and second positions is positioned to cover port 28 and seal it against fluid flow therethrough. However, in the third position, sleeve 14 has moved away from port and leaves it open, at least to some degree, for fluid flow therethrough. Although a tubing pressure increase releases the sleeve to move into WSLEGAL\045023\00417\11731577v3 the second position, the valve can still hold pressure in the second position and, in fact, tubing pressure creating a pressure differential across the sleeve actually holds the sleeve in a port closed position. Only when pressure is released after a pressure up condition, can the sleeve move to the port open position. Seals 30 may be provided to assist with the sealing properties of sleeve 14 relative to port 28. Such port 28 may open bore 12a to the annular area about the tubular segment, such as may be required for wellbore stage cementing. In one embodiment, for example, the sleeve may be moved to open port 28 through the tubular segment such that cement from bore 12a can be passed into the annulus open to outer surface 12b.
In the illustrated embodiment, for example, a plurality of ports 28 pass through the wall of tubular segment 12 for passage of cement between bore 12a and outer surface 12d and, in particular, the annulus about the string.
As illustrated, tool 10 may include one or more locks, as desired. For example, a lock may be provided to resist sleeve 14 of the valve from moving from the first position directly to the third position and/or a lock may be provided to resist the sleeve from moving from the third position back to the second position. In the illustrated embodiment, for example, an inwardly biased c-ring 32 is installed to act between a shoulder 34 on tubular member 12 and a shoulder 36 on sleeve 14. By acting between the shoulders, they cannot approach each other and, therefore, sleeve 14 cannot move from the first position directly toward the third position, even when shear pins 24 are no longer holding the sleeve. C-ring 32 does not resist movement of the sleeve from the first position to the second position. However, the c-ring may be held by another shoulder 38 on tubular member 12 against movement with the sleeve, such that when sleeve moves from the first position to the second position the sleeve moves past the c-ring.
Sleeve 14 includes a gland 40 that is positioned to pass under the c-ring as the sleeve moves and, when this occurs, c-ring 32, being biased inwardly, can drop into the gland.
Gland 40 may be sized to accommodate the c-ring no more than flush with the outer diameter of the sleeve such that after dropping into gland 40, c-ring 32 may be carried with the sleeve without catching again on parts beyond the gland. As such, after c-ring 32 drops into the gland, it does not inhibit further movement of the sleeve.

WSLEGAL\045023\00417\11731577v3 Another lock may be provided, for example, in the illustrated embodiment to resist movement of the sleeve from the third position back to the second position.
The lock may also employ a device such as a c-ring 42 with a biasing force to expand from a gland 44 in sleeve 14 to land against a shoulder 46 on tubular member 12, when the sleeve carries the c-ring to a position where it can expand. The gland for c-ring 42 and the shoulder may be positioned such that they align when the sleeve moves substantially into the third position. When c-ring 42 expands, it acts between one side of gland 44 and shoulder 46 to prevent the sleeve from moving from the third position back toward the second position.
The tool may be formed in various ways. As will be appreciated, it is common to form wellbore components in tubular, cylindrical form and oftentimes, of threadedly or weldedly connected subcomponents. For example, tubular segment in the illustrated embodiment is formed of a plurality of parts connected at threaded intervals.
The threaded intervals may be selected to hold pressure, to form useful shoulders, etc., as desired.
Stage tool 10 has a port-recloseable function. For example, in some applications it may be useful to open ports 28 to permit cement flow therethrough and then later close the ports to hold the cement in the annulus. In one embodiment, for example, sleeve 14 may be moveable from the third position to a position overlying and blocking flow through ports. The stage tool may further include a contingency closing secondary sleeve.
Another embodiment of a useful stage tool includes a delay hydraulic opening device, wherein the closure for the stage tool ports is moveable from a closed position to an open position, but the movement is resisted and thereby delayed. The closure is activated by receiving a force to shear pins on the closure so that it is allowed to begin moving. The force may be a physical force by a tool such as a dart passing thereby or by a hydraulic force, as by pressuring up. Then, once activated, the closure is restricted to move very slowly to the open position, the restriction being selected to delay the opening long enough that any pressure differential between the tubing string and the annulus is substantially dissipated. Thus, for example, the string inner diameter may be pressured WSLEGAL\045023 \00417\11731577v3 up to activate the delay hydraulic closure and then a driving force can be applied against the resistive force to keep the closure slowly opening. The driving force may be by an atmospheric pressure charge, a nitrogen dome charge, a spring, a motor, such as an electric motor, and/or an existing hydrostatic to move to the open position.
The resistive force may be hydraulic fluid metering device, a frictional system, etc. In any event, once the stage tool goes to the open position, there is substantially no pressure differential, and, therefore, substantially no surge on the formation. Thereafter, cement can be gently circulated at low pump pressure to cement the annulus through the stage tool.
Such a stage tool is shown in Figures 3. The tool includes a tubular housing 110 defining an inner bore 112 and an outer surface 110a, a port 114 (two ports can be seen, but other numbers are possible) through the wall of the tubular housing and a closure for the port.
In this embodiment the closure is a sliding sleeve 116. The sliding sleeve has a port-closed position (Figure 3A), wherein the sliding sleeve maintains port 114 in a closed condition by overlying the port. Seals 118a, 118b, such as o-rings in glands, act between sleeve 116 and the tubular housing in the port-closed position to generally prevent leakage of fluid through the port from inner diameter 112 to outer surface 110a. Sleeve 116 is actuable and, thereafter, capable of moving to a port-open position (Figure 3C). In the port-open position, the port is open to fluid flow therethrough. In Figure 3C, for example, sleeve 116 is withdrawn from over port 114, but it will be appreciated that as soon as the sleeve is removed from its overlapping position over the seal 118b, the port will be open to permit some amount of fluid flow therethrough.
The system further includes a port opening delay mechanism 120 configured to act after actuation of the sliding sleeve 116. After the sliding sleeve 116 is in the active position, port opening delay mechanism 120 acts to slow movement of the port-closure such that it only reaches the port-open position after a selected time has lapsed, that selected time being longer than the time it would take the closure to move from the port-closed to the port-open position if the delay mechanism was not in place.
Tubular housing 110 can be foimed as a sub, such as one to be installed in a wellbore tubing string. Such a sub may include ends (not shown) formed for connection to WSLEGAL\045023\00417\11731577v3 adjacent tubulars in the string. Suitable forming may include, for example, threading, tapering, etc. Generally, tubular housing 110 will be cylindrical but other forms may be employed.
Port 114 extends through the wall of the tubular housing, providing fluid access through the wall. The fluid access may flow inwardly or outwardly through the port between inner bore 112 and the housing's outer surface 110a (as shown).
Sliding sleeve 116 moves axially through the tubular housing when moving from the port-closed to the port open position. This movement could be along the outer surface.
In this embodiment, sleeve 116 moves towards surface, arrows B, when moving to the port-open position, but this could be reversed with a few modifications.
Port opening delay mechanism 120 acts to slow movement of the port-closure such that it only reaches the port-open position after a selected time has lapsed, that selected time being longer than the time it would take the closure to move from the port-closed to the port-open position if the delay mechanism was not in place. The port opening delay mechanism is configured to act after actuation of sleeve 116 to resist, and therefore delay, opening of the port to fluid flow therethrough until after the selected time has lapsed. In this embodiment, the delay mechanism includes a hydraulic chamber between housing 110 and sleeve 116 that has metered movement of hydraulic fluid therein to slow any movement between the parts. In particular, in the embodiment of Figures 3, as best seen in Figure 3D, the delay mechanism 120 includes hydraulic chamber with a metering valve 122 moveable therein, which separates the chamber into a first hydraulic chamber 124 and a second hydraulic chamber 126. The metering valve is driven by relative movement between housing 110 and sleeve 116 to move through the chamber, reducing the size of one chamber, while at the same time increasing the size of the other chamber such that fluid must move through a restriction in metering valve 122 from one chamber to the other. Thus, while the sleeve, after being actuated, can move toward its port-open position, it is slowed in that movement by the resistance exerted by metering valve in the hydraulic chamber.

WSLEGAL\045023\00417\11731577v3 The chamber is, in this embodiment, an annular space between housing 110 and the sleeve. Seals 128a and 128b, such as o-rings in glands, are positioned between sleeve 116 and the inner wall of the tubular housing at either end of the chamber to pressure isolate the chamber from inner diameter 112 and from fluid pressures about outer surface 110a. As such any fluid in the chamber, which may be introduced through ports 30, is trapped in the chamber. In the illustrated embodiment, chamber 124 is filled with air and chamber 126 is filled with a hydraulic fluid, such as oil, both at atmospheric pressure.
While both chambers could be filed with any fluid, a hydraulic fluid offers predictable viscosity and cannot immediately flow through valve 122 such that the flow, while capable of occurring through valve, occurs at a slow rate. While both chambers could be filled with the same fluid, having a compressible fluid in the receiving chamber allows for pressure relief should the hydraulic-fluid filled chamber undergo pressure fluctuations while handling, such as when being moved from surface into borehole conditions.
Metering valve 122, in this embodiment, is secured to the outer surface of sleeve 116.
The metering valve therefore moves with the sleeve. Metering valve 122 includes an annular ring that separates the annular chamber into the two chambers 124, 126. The movement of sleeve 116 to achieve port-opening, forces metering valve 122 to move through the chamber to increase the volume of first chamber 124 while reducing the volume of second chamber 126. In response to this relative volume change between the two chambers, one's volume increasing and the other's volume decreasing, hydraulic fluid in the chamber of decreasing volume must pass the restriction presented by metering valve to permit the sleeve movement. In the illustrated embodiment, the restriction includes an orifice 132 providing limited fluid movement between the two chambers 124, 126 through openings 132a, 132b. Seals 134 prevent fluid from bypassing around the piston. While sleeve could otherwise move readily within the housing, the movement is resisted by the restriction of metering valve 122 moving through the hydraulic-fluid-filled chamber. Thus, the valve 122 slows movement of the sleeve, corresponding to the rate at which the hydraulic fluid in the chamber may pass through the valve's fluid orifice 132.
It will be appreciated that various modifications can be made to the delay mechanism.
For example, the piston could be carried on the housing. In one embodiment, the delay WSLEGAL\045023 \00417\11731577v3 mechanism is adjustable to control the degree of resistance imparted thereby.
For example in an embodiment employing a hydraulic chamber, the viscosity of the hydraulic fluid and/or the size of the valve orifice can be selected, to control the metering effect and therefore the delay imparted by the mechanism.
The port closure, in this embodiment, sleeve 116 may be actuated to begin the port opening process by a pressure driven mechanism. The pressure driven mechanism actuates the closure to an active position (Figure 3B) where the closure can move from the port-closed position to the port-open position. The pressure driven mechanism may vary depending on the sleeve. In one embodiment, for example, the pressure driven mechanism is incorporated in the closure mechanism such as, for example, in a fluid pressure responsive valve as described above. As described therein, the fluid pressure responsive valve is actuated in response to pressure differentials across the valve to begin opening. The actuation is a release of the sleeve such that it becomes free to move to the port-open position.
In Figures 3, the pressure driven mechanism involves the use of a pressure driven tool.
Figures 3A to 3E show one embodiment of a tool and Figures 3F and 3G show another embodiment. In Figures 3A to 3E: Figure 3E shows the assembly pre-actuation (in a run-in condition); Figure 3A shows the assembly mid-actuation; Figure 3B shows the assembly after actuation, when sleeve 116 is activated and ready to move; and Figure 3C
shows the assembly after sleeve 116 has moved. In Figures 3F and 3G: Figure 3F
shows the assembly mid-actuation and Figure 3G shows the assembly after actuation, when sleeve 116 has moved.
In these embodiments, sleeve 116 is actuated to begin the port opening process by a pressure driven tool that acts by direct contact or proximity to actuate the closure to begin moving to the port-open position. The pressure driven tool is drivable through the tubular housing by fluid pressure. The pressure driven tool may take various forms, for example, it may be single or multipart. In one embodiment, for example, the pressure driven tool includes a conveyed part, such as a plug 136, for example a ball (as shown) or dart, etc. that lands against a release mechanism, such as a sleeve with a seat, a latch, etc.

WSLEGAL\ 045023 \ 00417 \ 11731577v3 that is substantially not pressure drivable until the conveyed part is landed thereagainst.
In the illustrated embodiment, for example, the assembly includes an activation sleeve 140 with a seat 142 formed thereon sized to act with plug 136. Plug 136 and seat 142 are correspondingly sized such that when plug 136 is pressure driven through the tubular housing 110, the plug cannot pass through the seat. Plug 136 therefore lands on the activation sleeve's seat 142 and, the sleeve with the plugging device landed therein, occludes inner bore 112 of the tubular housing to create a pressure differential across the activation sleeve. Sleeve 140, therefore, can be driven along by the pressure differential toward the low pressure side, arrow A, and this movement can actuate, and in particular release, sleeve 116 to begin to move, arrow B, to the port-open position (Figure 3C).
The pressure driven tool can serve further purposes in the wellbore. For example, in one embodiment as shown, plug 136, once having actuated the sleeve, may pass through seat 142 and may continue on and land on a seat (not shown) below. The seat may serve various purposes, after it has plug 136 landed therein. For example, it may act to divert fluid to ports 114, once they are opened. As such, seat 142, while formed to initially retain plug 136, may also be formed to be overcomeable, such as by deformation, so that plug 136 can pass through the seat and proceed downhole.
The actuation assembly as illustrated, includes activation sleeve 140 with seat 142 and plug 136 sized to be retained in seat 142 long enough to cause actuation of the system.
Seat 142 is deformable and includes a main body 142a installed in sleeve 140 and a subsleeve 142b slidably installed in a bore through main body 142a. The subsleeve 142b defines the bore through which plug 136 passes and is retained. In particular, annular ledge 142c creates a stop against which the plug is caught when passing through the bore of the subsleeve 142b. The subsleeve is locked in a first position by keys 142d, Figure 3A, 11E. In the first position, subsleeve 142b is captured radially in the bore of main body 142a such that the subsleeve's walls about ledge 142c cannot radially expand.
However, if keys 142d are retracted, the subsleeve is freed to move to a second position, Figure 3B. In the second position, the subsleeve's walls about ledge 142c extend into an enlarged diameter area in the bore of main body 142a, such that the walls can be expanded radially to enlarge the diameter across ledge 142c. Keys 142d can retract when WSLEGAL\045023\00417\11731577v3 main activation sleeve 140 moves down into a releasing position (Figure 3B, 3F), where the keys 142d are positioned in a space where they have room to retract. Plug 136 is retained in subsleeve 142b when it is in the first position and plug 136 can pass through subsleeve 142b when it is in the second position, which is the position achieved after plug 136 has driven activation sleeve 140 to actuate sleeve 116.
While activation sleeve 140 could operate in numerous ways to actuate sleeve 116, to free it for movement, it is noted that sleeve 140 is initially secured to sleeve 116 by a C-ring lock 144 wedged between the sleeves. C-ring lock 144 is positioned in an annular gland 146 in an end extension of sleeve 116 and is supported at its back side by an annular extension 140a of sleeve 140. When sleeve 140 is pulled out from behind C-ring lock 144, it is free to expand out of gland 146 and sleeve 116 is freed by the actuation assembly to move.
The actuator may include a releasable lock that is released by the pressure driven mechanism. For example, shear pins may be employed to ensure sleeve 140 is initially locked in position. Shear pins 150 may be used to ensure that sleeve 116 does not inadvertently move out of position. However, the shear pins are selected to have a holding force capable of being overcome by appropriate pressures.
Locks may also be employed to hold the parts in their final positions. For example, a C-ring lock 151 may be employed to ensure sleeve 140 remains in its position after activation of sleeve 116. C-ring lock 152 may be positioned to engage between sleeve 116 and housing 110 after sleeve 116 has moved to the port-open position, to ensure that sleeve 116 does not inadvertently move out of the port-open position.
While a sleeve with a deformable subsleeve has been disclosed as the activation mechanism for the system, the activation of sleeve 116 for movement may be accomplished in various ways. For example, Figure 3F shows an alternative deformable seat. In this embodiment, seat 142 is formed by a plurality of collet fingers 182 that are compressed together during run in to form the ball-catching seat, but are pushed into a WSLEGAL\045023 \00417\11731577v3 recess 184 that allows fingers to expand, when the activation sleeve 184 is driven by the plug and fluid pressure.
The above-noted pressure driven plugging device and sleeve actuates the closure by direct manipulation. In another embodiment, the pressure driven tool may operate by proximity such as by emitting a signal that is detected by the closure. In such an embodiment, for example, the pressure driven tool is conveyable, such as including a non-plugging dart, a plug (such as a ball or dart), etc. that emits a signal and the closure's actuator includes a receiver that receives the signal. The pressure driven tool signals the actuator to begin the opening process, when the pressure driven tool passes in signaling proximity thereto. In one of these embodiments, for example, the conveyed tool and actuator may employ RF technology for emitters and receivers. Such technology is disclosed, for example, in US Patent Document 2007/0272411. As such, it is to be understood that there are various ways to actuate the closure to assume its port-open condition.
From the foregoing, it will be appreciated that the pressure driven tool may actuate the closure to begin opening, but in this embodiment does not actually drive the closure open.
For example, in one embodiment, a conveyed tool may land against a tubing ID
restriction and may apply a force as it passes the restriction, which force actuates the closure to begin the opening process. However, the conveyed tool may activate the stage tool to initiate opening but the conveyed tool does not actually drive the closure open. In such an embodiment, a driver may be required, as discussed below, to impart a drive force to the closure. Thus, the port closure system may further include a driver that provides the energy to move the closure to the open position, after it is actuated. The driver may include one or more of a motor, a biasing member such as a spring or a pressure charge (i.e. a nitrogen chamber charge or an atmospheric pressure chamber), a piston configuration to respond to differential well/tubing pressures, etc.
While the driver may be capable of applying a force to rapidly move the closure from the port-closed to the port-open position, the port opening delay mechanism resists and therefore slows such movement. A driver may permit a closure to be moved without maintaining the original pressure drive that initiated the movement. For example, if the actuation is by WSLEGAL\045023\00417\11731577v3 pressuring up the tubing string, the pressure may be dissipated but the driver continues to apply a driving force to the sleeve. In one embodiment, the driver may be selected to operate apart from the actuation of the closure. For example, the driver may be a biasing member that generates or stores energy that can only be dissipated after the sleeve is actuated to begin opening. In the illustrated embodiment, the driver includes opposing piston faces across which a pressure differential is established to drive the sleeve toward the lower pressure side. For example, seals 128a create one piston face and seals 128b create a second piston face. The larger diameter of seals 128b over seals 128a provides a greater surface area of seal 128b vs. seal 128a. The greater surface area of seals 128b compared to seals 128a creates a pressure differential across atmospheric chambers 124, 126 that drives the sleeve toward seals 128a. Fluid can be communicated to seals 128b through fluid ports 129.
Once the port 114 is open, it can remain open until cementing is complete and then it can be closed to trap the cement in the wellbore annulus against the outer surface of the stage tool. A plug or running tool could be deployed after the fact to selectively close the port, after it is opened.
The delay mechanism allows pressurized operation to open the port but the port remains closed to fluid flow therethrough until after a selected time which allows time for the pressure to be dissipated before the ports are actually opened. For example, with reference to Figures 3, the delay mechanism is in place to ensure that there is sufficient time to allow the pressure required to convey activation device, plug 136, to dissipate before communication is established with the wellbore.
In operation, the stage tool may be installed in a string and run into a wellbore. Plug 136 is released uphole of tubular 110 and is conveyed by gravity and fluid pressure to activation sleeve 140. When plug 136 reaches sleeve 140, it lands in seat 142.
Pressure is increased from surface to break shear pins (not shown) and the sleeve 140 moves down (arrow A). This allows the release of C-ring lock 144. Lock ring 151 locks sleeve 140 in the shifted position when the ring expands behind a shoulder 153 in housing 110. After the sleeve shifts, the plug 136 continues to create a seal in the seat.
Increased pressure WSLEGAL\045023\00417\11731577v3 yields the seat and allows the plug 136 to continue down the string. In particular, seat 142 yields when subsleeve 142b shifts and ledge 142c expands to release the plug. In another embodiment, plug 136 remains in the seat.
With the release of C-ring lock 144, sleeve 116 is considered actuated, being free to move. Any pressure in the string then can act on the differential areas of seals 128a, 128b against the fluid filled chambers 124, 126. This causes sleeve 116 to begin shifting and overcomes any holding force exerted by shear pins 150. In this embodiment, the movement of sleeve 116 is uphole. Any movement of the sleeve is resisted and therefore slowed by the changing volume of chambers 124, 126, metering valve 122 between the chambers and the viscosity of the hydraulic fluid in chamber 126, which together act as a delay mechanism. In particular, the differential forces between seals 128a and 128b acting against the atmospheric conditions of the fluid in chambers, causes sleeve 116 to move toward seals 128a and this movement causes metering valve 122 to move with the sleeve through the annular chamber such that fluid is forced from chamber 126 to chamber 124 through orifice 132 of metering valve 122. In this embodiment, a driving force is applied to the sleeve after actuation thereof by ensuring that the seals 128a, 128b have a differential area and by selecting the pressure in the chambers to be less than the downhole pressures, considering the downhole temperature and pressure conditions. The delay mechanism acts against the force applied by the driver and slows the movement of the sleeve.
The driving force causes sleeve to continue to move until it is stopped for example when C-ring lock 152 expands into a gland in chamber 124 or become butted against a stop wall. In so doing sleeve 116 is withdrawn from its position covering port 114 such that port is opened. The driver, which is the effect of the differential areas of seals 128a, 128b acting against the atmospheric chambers 124, 126, continues to apply a driving force on the sleeve while tubing pressure is dissipated and even after the port opens.
While the above-noted sleeve is driven by pressure differentials between seals 128a, 128b acting against the atmospheric chambers 124, 126, it is to be understood that the driver that applies a driving force against the resistance of the delay mechanism, chambers 124, WSLEGAL\045023\00417\11731577v3 126, could take other forms. For example, in one embodiment, the driver may be a pressure charged chamber, such as one containing nitrogen. In another embodiment, a spring may be used as the driver. In these embodiments, the pressure charge and the spring act to apply the driving force to urge the sleeve open, against the resistance of the delay mechanism.
Port 116 only opens after time is permitted to allow the pressure in inner bore to substantially equalize to the pressure about the outer surface. Once port 116 is opened, stage cementing can proceed. For example, in one embodiment cement is pumped out though port 116 and into the annulus about the outer surface of the stage tool.
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".

W5LEGAL\045023\00417\11731577v3

Claims (21)

Claims:

1. A method for stage cementing a wellbore, the method comprising: increasing pressure within a tubing string within the wellbore to conduct an operation in the tubing string, the tubing string including a stage tool with an inner diameter in pressure communication with the tubing string; reducing pressure in the stage tool inner diameter; opening the stage tool when the pressure in the stage tool inner diameter is approximately equal to annular pressure in an annulus about the stage tool; and pumping cement through the stage tool into the annulus.

2. The method of claim 1 wherein the operation in the tubing string includes activating a tool in the tubing string.

3. The method of claim 2 wherein activating a tool in the tubing string includes activating the stage tool to permit opening of the stage tool.

4. The method of claim 3 wherein activating the stage tool includes activating a delay mechanism of the stage tool to delay opening of the stage tool until the pressure within the stage tool is approximately equal to annular pressure.

5. The method of claim 1 wherein the method further comprises activating a timer at surface to delay opening of the stage tool for an amount of time while the stage tool is in the wellbore, the amount of time being sufficient for all pressure operations prior to cementing to be accomplished.

6. The method of claim 1 wherein reducing pressure includes releasing pressure.

7. The method of claim 1 wherein opening includes signaling a signal receiver in the stage tool to activate the stage tool to open after a period of time.

8. The method of claim 1 wherein pumping cement through the stage tool includes pumping at pressures less than a pressure capable of damaging the formation.

9. The method of claim 1 wherein pumping cement is through an open cementing port of the stage tool.

10. A wellbore installation comprising:
a bore hole in a formation;
a tubing string in the bore hole, the tubing string including a lower end, an upper end and a tubular wall between the lower and the upper end, with an inner bore defined within the tubular wall and an annular space defined between the tubing string and a wall of the bore hole; and a stage tool installed in the tubing string, the stage tool having a cementing port and the cementing port configured to open when the pressure in the inner bore is increased and then decreased until the pressure in the inner bore is substantially equal with the pressure of the annular space.

11. The wellbore installation of claim 10 wherein the tubing string is part of a monobore installation.

12. The wellbore installation of claim 10 further comprising cement in the annular space extending from the cementing port upwardly toward the upper end.

13. The wellbore installation of claim 10 wherein the formation is an oil sands formation.

14. The wellbore installation of claim 10 wherein the stage tool includes: a delay mechanism to delay the opening of the cementing port until the pressure in the inner bore is substantially equal with the pressure of the annular space.

15. The wellbore installation of claim 14 wherein the delay mechanism delays the opening an amount of time after receiving a signal to permit opening of the cementing port.

16. The wellbore installation of claim 14 wherein the delay mechanism includes a timer.

17. The wellbore installation of claim 14 wherein the delay mechanism is a pressure sensor that permits the cementing port to open when the pressure in the inner bore is substantially equal with the pressure of the annular space.

18. The wellbore installation of claim 10 wherein the stage tool includes: a signal receiver to receive a signal to activate the stage tool to be capable of opening the cementing port; and a delay mechanism to delay the opening of the cementing port until the pressure in the inner bore is substantially equal with the pressure of the annular space.

19. The wellbore installation of claim 18 wherein the delay mechanism delays the opening of the cementing port an amount of time after the signal receiver receives the signal to activate.

20. The wellbore installation of claim 18 wherein the signal receiver is signaled by a pressured up condition wherein when the pressure in the inner bore is increased relative to the pressure of the annular space.

21. The wellbore installation of claim 18 wherein the delay mechanism is a pressure sensor that permits the cementing port to open when the pressure in the inner bore is substantially equal with the pressure of the annular space.